United States
Environmental Protection
Agency
Research and
Development
PROCEEDINGS:\5TElST JOINT
SYMPOSIUM ON DRY SO2 AND
SIMULTANEOUS S02/N0X
CONTROL TECHNOLOGIES
Volume 2. Power Plant Integration.
Economics* and Full-scale Experience
Prepared for
1
Office of Environmental Engineering and Technology
EPA-600 /9-85-020b
July 1985
Prepared by
Air and Energy*Engi neering Research
Laboratory
Research Triangle Park NC 27711
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ittonai grouping, was conadouaiy
maximum interface in related fields.
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& Scientific and Technical Aaaeaament Reports (STAR)
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a. "Special** Reports
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EPA REVIEW NOTICE
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EPA-600'9-85-020b
July 1985
PROCEEDINGS: FIRST JOINT SYMPOSIUM ON
DRY SO2 AND SIMULTANEOUS S02/N0x CONTROL TECHNOLOGIES
Volume 2. Power Plant Integration. Economics, and Full-scale Experience
Symposium Cochairpersons:
M. W. McElroy (EPRI) and R. D. Stern (EPA)
Acursx Corporation
555 Clyde Avenue
Mountain View, CA 94039
EPA Contract 68-02*3933
EPRI Contract RP2533-3
Air and Energy Engineering Research Laboratory
Research Triangle Park. NC 27711
EPA Project Officer:
P. Jeff Chappell
Prepared for:
US Environmental Protection Agency
Office of Research and Development
Washington. DC 20460
Electric Power Research Institute
3412 Hillview Avenue
Palo Alto, CA 94303
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ABSTRACT
Forty six papers describing recent advances 1n dry sorbent Injection technologies
for SO2 control were presented at the 1st Joint Symposium on Dry SO2 and
Simultaneous S02/N0X Control Technologies. These papers covered the following
topics: fundamental research; pilot-scale development of furnace Injection; burners
for simultaneous S0z/N0x control; post-furnace SO2 removal; process Integration and
economics; sorbent av«1lab1l1ty and costs; and field applications and full-scale
testing.
11
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PREFACE
The 1st Joint Symposium on Dry SO? and Simultaneous S02/N0X Control Technologies was
held November 13 through 16, 1984 1n San Diego, California. This symposium, jointly
sponsored by EPRI and EPA, was the first meeting of Its kind devoted solely to the
discussion of emissions control processes based on dry Injection of calcium or
sodium sorbents to meet SO2 and N0X regulations for coal-fired power plants.
Specific processes that were discussed included: direct furnace Injection of
calcium-based sorbents, sorbent Injection combined with low-NOx burners for
simultaneous SOg/NOx control, and post-furnace injection of calcium and sodium
sorbents. The objective of the symposium was to provide a timely forum for the
exchange of data and information on the current status and plans for these emerging
technologies.
Forty six papers were presented beginning with a keynote address on add rain
strategies and control technology Implications, followed by overviews of the EPRI,
EPA, and Canadian programs, and the utility perspective for dry control
technologies. Other papers focused on the latest advances 1n fundamental research
and process design, power plant Integration and economics, field applications, and
fuTl-scale testing. A panel of representatives from architect-engineering firms,
boiler manufacturers, and utfllty companies discussed the Impaet of dry SO2 control
processes on new and existing power plants*
The speakers included EPRI and EPA staff members as well as representatives from
utility companies, manufacturers of utility boilers and process equipment, sorbent
suppliers, and research and development qrouos conducting Investigations sponsored
by EPRI, EPA, and Others. Participants from W««t Gernany, Franca, The Netherlands,
Austria, Canada, and Japan provided a worldwide update on technological developments
and an international perspective on SOj and S02/N0X control Issues.
The Cochalrmen of the symposium were Michael W. McElroy, Subprogram Manager of
EPRI*s Air Quality Control Program in the Coal Combustion Systems Division and
Richard D. Stem, Chief of EPA's LIMB Applications Branch of the Industrial
Environmental Research Laboratory.* The welcoming address was given by John Hamrlck,
Vice President of Customer Service for San Diego Gas ft Electric and the keynote
address was given by Donald J. Ehreth, Deputy Assistant Administrator, Office of
Research and Development, EPA.
The symposium proceedings has been published 1n two volumes:
• Volume 1: Fundamental Research and Process Development
— Session I: Introduction
— Session II: Fundamental Research
~ Session III: Pilot-Scale Development of Furnace Injection
— Session IV: Burners for Simultaneous S02/N0X Control
— Session V: Post-Furnace SO2 Removal
(*) Now, the Air and Energy Engineering Research Laboratory.
iii
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• Volume 2: Power Plant Integration, Economics, and Full-Scale Experience
— Session VI:
— Session VII:
Process Integration and Economics
Sortient Availability and Costs
Session VIII: Field Applications and Full-Scale Testing
iv
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CONTENTS
VOLUME 1
FUNDAMENTAL RESEARCH AND PROCESS DEVELOPMENT
Page
SESSION I: INTRODUCTION
Chairman, Richard Stern, EPA, IERL/RTP and
Michael McElroy EPRI
1 "Acid Deposition Strategies and Implications for Control
Technology Requirements," D. J. Ehreth* 1-1
2 "The EPRI Program — Background and Motivation," 0. S. Maulbetsch . . 2-1
3 "EPA's LIMB R&D Program - Evolution, Status, and Plans," 6. B. Martin
and J. H. Abbott* 3-1
4 "Overview of Canadian Research, Development and Demonstration
Program for Low N0X/S02 Control Technologies," W. A. Warfe and
S. K. Lee 4-1
5 "The Utility Perspective on Dry S02 Control Technologies,
G. P. Green . 5-1
SESSION II (PART 1): FUNDAMENTAL RESEARCH
Chairman, Kerry Bowers, Southern Company
Services
6 "EPA Experimental Studies of the Mechanisms of Sulfur Capture by
Limestone," R. H. Borgwardt, K. R. Bruce, and J. Blake* 6-1
7 "Flow Reactor Study of Calcination and Sulfation," V. P. Roman,
L. J. Muzlo, M. W. McElroy, K. W. Bowers, and D. T. Gallaspy 7-1
8 "Calcium-Based Sorbents for Dry Injection," J. L. Thompson 8-1
SESSION II (PART 2): FUNDAMENTAL RESEARCH
Chairman, Dennis Drehmel, EPA, IERL/RTP
9 "Laboratory-Scale Production and Characterization of High Surface
Area Sorbents," D. A. Klrchgessner* 9-1
10 "Reactivity of Calcium-Based Sorbents for SO2 Control," J. A. Cole, '
J. C. Kramltch, 6. S. Samuel sen, W. R. Seeker, and G. D. SHcox* . . . 10-1
*See EPA disclaimer on page ix
v
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CONTENTS
Paper Page
11 "Bench Scale Evaluation of Sulfur-Sorbent Reactions,"
D. M. Slaughter, 6. D. Sllccx, P. M. Lemieux, G. H. Newton,
and 0. W. Pershing* 11-1
12 "Evaluation of SO2 Removal by Furnace Limestone Injection with
Tangentlally Fired Low-NOx Burner," K. Tokuda, M. Sakai, T. Sengoku,
N. Murakami, M. VI. McElroy, and K. Mouri 12-1
13 "Performance of Sorbents With and Without Additives, Injected Into,
a Small Innovative Furnace," S. I. Rakes, G. T. Joseph, and
J. M. Lorraln* 13-1
SESSION III: PILOT-SCALE DEVELOPMENT OF FURNACE INJECTION
Chairman, Michael McElroy, EPRI
14 "Pilot-Scale Characterization of a Dry Calcium-Based Sorbent SO2
Control Technique Combined with a Low-NOx Tangentlally Fired System,"
J. T. Kelly, S. Ohmine, R. Martin, and D. C. Drehmel* 14-1
15 "Boiler Simulator Studies on Sorbent Utilization for SO2 Control,"
B. J. Overmoe, S. L. Chen, L. Ho, W. R. Seeker, M. P. Heap, and
D. W. Pershing* 15-1
16 "Studies of Sorbent Calcination and S02-Sorbent Reactions in a
Pilot-Scale Furnace,* R. Beittel, J. P. Gooch, E. B. Dlsmukes, and
L. J. Muzio 16-1
17 "Recent IFRF Fundamental and Pilot Scale Studies on the Direct
Sorbent Injection Process," S. Bortz and P. Flament 17-1
18 "Demonstration of Boiler Limestone Injection In an Industrial
Boiler," C. E. Fink, N. S. Harding, B. J. Koch, 0. C. McCoy,
R. M. Statnlck, and T. J. Hassell 18-1
19 "Pilot-Scale Studies of In-Fumace Hydrated Lime Injection for
Flue Gas SO2 Emission Control," G. F. Weber, M. H. Bobman, and
G. L. Schelkoph 19-1
20 "Bench Scale Process Evaluation of In-Fumace N0X and S0X Reduction
by Reburnlng and Sorbent Injection," S. B. Greene, S. L. Chen,
D. W. Pershing, M. P. Heap, and W. R. Seeker* 20-1
SESSION IV: BURNERS FOR SIMULTANEOUS S02/N0X CONTROL
Chairman, G. Blair Martin, EPA, IERL/RTP
21 "Evaluation of Low-N0x Burners for SO2 Control," R. Payne and
A. R. Abele* 21-1
22 "Limestone Injection With an Internally Staged Low-NOx Burner,"
J. Yatsky and E. S. Schlndler (Paper not submitted) 22-1
•See EPA disclaimer on page ix
vi
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CONTENTS
Paper Page
23 "Development of Internally Staged Burners for LIMB," G. C. England,
R. Payne, and Clough* . 23-1
SESSION V: POST-FURNACE SO2 REMOVAL
Chairman, Dan Giovanni, Electric Power Technologies, Inc.
24 "Characterization of Alternate Sodium Sorbents for Fabric Fiber
SO2 Capture," R. Hooper 24-1
25 "Dry Injection"Scrubbing of Flue Gases With the SHU Process,"
M. Schutz 25-1
26 "Flue Gas Desulfurfzatlon by Combined Furnace Limestone Injection
and Dry Scrubbing," L. E. Sawyers, P. V. Smith, and T. B. Hurst . . . 26-1
27 "Pilot Evaluation of Combined SO2 and Particulate Removal on a
Fabric Filter," F. G. Pohl, M. W. McElroy, and R. Rhudy ....... 27-1
VOLUME 2
POWER PLANT INTEGRATION, ECONOMICS. AND FULL-SCALE EXPERIENCE
SESSION VI: PROCESS INTEGRATION AND ECONOMICS
Chairman, David Lachapelle, EPA, IERL/RTP
28 "Fireside Consequences of Furnace Limestone Injection for SO2
Capture," G. J, Goetz, M. D. M1roll1, and D. Esk1naz1 28-1
29 "Effects of Furnace Sorbent Injection on Fly Ash Characteristics
and Electrostatic Precipitator Performance," R. S. Dahlln,
J. P. Gooch, and J. D. Kllgroe* 29-1
30 "Evaluation of Temperature Histories 1n the Radiant and Convectlve
Zones of a Pulverized Coal-Fired Steam Generator," B. M. Cetegen,
J. L. Reese, K. Kurucz, W. Rlchter, and D. G. Lachapelle* 30-1
31 "Impact of Sorbent Injection on Power Plant Heat Rates*"
D. V. Giovanni 31-1
32 "Boiler Design Criteria for Dry Sorbent S0X Control with Low-N0x
Burners," A. Kokklnos, D. C. Borlo, R. W. Koucky, J. P. Clark,
C. Y. Sun, and D. 6. Lachapelle* 32-1
33 "Wall-Fired Boiler Design Criteria for Dry Sorbent SO2 Control
With Low-N0x Burners," R. K. Mongeon, J. P. Mustonen, and
D. G. Lachapelle* ................. 33-1
34 "Dry Sorbent Emission Control Prototype Conceptual Design and
Cost Study," D. T. Gallaspy 34-1
35 "EPA's LIMB Cost Model: Development and Comparative Case Studies,"
D. G. Lachapelle, N. Kaplan, and J. Chappell* 35-1
*See EPA disclaimer on page iac
vii
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CONTENTS
Paper Page
SESSION VII: SORBENT AVAILABILITY AND COSTS
Chairman, Richard Hooper, EPRI
36 "An Update on the Application of Lime Products for SO2 Removal,"
D. 0. Hoffman and 0. H. Stowe, Jr 36-1
37 "Dry Injection for FSO Sodium-Based Sorbents: Availability and
Economic Evaluation," R. M. Wright 37-1
38 "Sodium Bicarbonate for Sulfur Dioxide Emission Control,"
R. Shaffery 38-1
SESSION VIII: FIELD APPLICATIONS AND FULL-SCALE TESTING
Chairman, Richard Stem, EPA, IERL/RTP
39 "Reduction of S02-£nrlss1on 1n Brown Coal Combustion: Results From
Research and Large Scale Demonstration," K. R. G. Hein and
5. Kirchen 39-1
40 "Reduction of SG2 Emissions From a Coal Fired Power Station by
Oirect Injection of Calcium Sorbents 1n Furnace," H. Brlce,
6. Chelu, G. Flament, R. Manhaval, and M. Vandycke 40-1
41 "Direct Desulfurfzatlon at the 700-MW Welher III Unit,"
N. Y. Chugtal (Paper not submitted) 41-1
42 "Laboratory Tests, Field Trials, and Application of Furnace
Limestone Injection in Austria," G. Staudinger and
H. Schrofelbauer 42-1
43 "Experience With Furnace Injection of Pressure Hydrated L1me at
the 50-MW Hoot Lake Station," H. Ness, T. P. Oorchak, J. R. Reese,
and V. 43-1
44 "EPA*Wal1-Fired LIMB Demonstration," R. V. Hendrfks* 44-1
45 "The Homer City Experience in Developing a LIMB Process for
Use with Coal Preparation," D. U. Carey, D. I. Cessna, and
J. H. T1ce 4S-1
46 "N0x/S02 Control Experience at Saskatchewan Corporation's
Boundary Dam G.S. — Unit #6," R. D. Winship and J. A. Kaynes .... 46-1
UNPRE5ENTED PAPERS
47 "Suction Pyrometry Tests on Innovative Furnace," S. L. Rakes
and G. T. Joseph* 47-1
48 "Surface Characterization and Microanalysis of Sorbents
and Ash/Sorbent Mixtures," R. S. DahUn and D. A. Klrchgessner* . . . 48-1
APPENDIX A — LIST OF ATTENDEES A-l
*See EPA disclaimer on page ix
viii
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EPA DISCLAIMER
Papers Identified by an asterisk (*) 1n the Table of Contents were funded by the
U.S. Environmental Protection Agency (EPA) and have been reviewed in accordance with
EPA peer and administrative review policies and approved by EPA for presentation and
publication. The contents of other papers do not necessarily reflect the views of
the EPA and no official EPA endorsement should be Inferred.
ix
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SESSION VI: PROCESS INTEGRATION ANO ECONOMICS
Chairman, David laciiapelle, EPA, IERL/RTP
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FIRESIDE CONSEQUENCES OF FURNACE
LIMESTONE INJECTION FOR S02 CAPTURE
G. J. Goetz, and M. D. Mi rolli
Combustion Engineering, Inc.
1000 Prospect Hill Road
Windsor, Connecticut 06095
and
D. Eskinazi
Electric Power Research Institute
Palo Alto, California
ABSTRACT
The influence of limestone injection on the furnace performance characteristics of
two coals was investigated experimentally in Combustion Engineering's pilot scale
Fireside Performance Test Facility (FPTF), .under an EPRI sponsored study. The
slagging, fouling and emission characteristics of a high sulfur, high iron
Illinois *6 bituminous coal and a low sulfur, high sodium Montana subbituminous
coal were investigated under low N0„ conditions. Calcium to sulfur ratios of 2-4
were investigated in detail.
Results indicate that limestone can be injected without adversely affecting the
slagging and fouling performance of units firing these fuels. For high sodium
coals it has significant potential for reducing fouling by weakening the deposit
to tube bond, thereby enhancing sootblower cleaning effectiveness. With each coal
upper limits for limestone dosage were established based upon either deposit acc-
umulation and/or heat transfer rates.
INTRODUCTION
Furnace limestone injection 1n conjunction with low NO^ firing systems is under
consideration as a way of reducing the costs of controlling SO- emissions from
pulverized coal-fired power plants. In this process, limestone (CaCO,) 1s injected
into the furnace where 1t 1s calcined to lime (CaO). The lime reacts with S0? to
form solid calcium sulfate particles which are removed from the flue gas in a con-
ventional particulate control device. This dry, front-end process 1s attractive
because of its potential lower capital cost and relative simplicity of design and
operation, particularly for low and medium sulfur coals where only a modest amount
of sulfur capture may be required.
Furnace limestone injection has been performed by numerous researchers in fac-
ilities ranging from small scale laboratory furnaces to utility steam generators.
Wide ranges of sulfur capture have been reported with greater capture occurring in
those combustors having lower temperatures and extended residence times. Earlier
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tests with high sulfur coals have reported SO- removal efficiencies in the range
17-60% during furnace limestone injection at a Ca/S ratio of two. (1,2,3).
A major unanswered question regarding furnace limestone injection is its impact on
ash deposition in the radiant section (slagging) and convective passes (fouling)
of a steam generator. Furnace limestone injection will increase the particle
loading and change the chemical composition of the ash, and therefore influence
the character of ash deposits in various sections of a steam generator. The dis-
tribution and quantity of these deposits and their chemical and physical proper-
ties have an important impact on heat transfer performance and steam generator
performance. These factors, therefore, have a major bearing on the feasibility and
cost of furnace limestone injection.
The ultimate objectives of this study were to (1) determine the effects of lime-
stone injection under low N0„ firing conditions on the slagging and fouling
behavior of two coals with ash characteristics representing generic slagging and
fouling behavior encountered in the utility industry, and (2) interpret these
effects as they relate to boiler operation and performance.
The ash behavior was evaluated using the Fireside Performance Test Facility
(FPTF), a pilot scale combustion test facility designed to simulate the radiant
and convective heat transfer surfaces, ash properties and combustion conditions in
a pulverized coal-fired boiler (4). Test results from this facility have shown
excellent agreement with field slagging and fouling performance (5).
TEST PROGRAM
To attain the project objectives, Combustion Engineering, under an EPRI contract
performed a two phase pilot scale study. The first phase involved furnace studies
on a moderate ash, high sulfur, high iron, Midwestern Illinois #6 high volatile C
bituminous coal. The second phase involved furnace studies on a low ash, low sul-
fur, high sodium, Montana subbituminous 8 coal. Both coals are burned commercially
in utility boilers and were selected for their differing slagging and fouling
characteristics. Experience with the Illinois *6 coal indicates that it exhibits
high slagging and moderate fouling tendencies while high slagging and high fouling
tendencies are characteristic of the Montana subbituminous coal under standard
firing conditions. The limestone used during both phases of testing was Marble-
white 2Q0 obtained from Pfizer Chemical, Inc. The two coal and limestone analyses
are included in Table 1. The coals were pulverized to a fineness of 75-80% less
than 200 mesh and the limestone was typically 96% less than 200 mesh.
Illinois #6 coal testing Included a series of short term ML optimization tests,
a series of short term SO- optimization tests, and nine long term (40 continuous
hours) tests evaluating slagging and fouling. The short term tests were performed
to establish firing conditions for long term slagging and fouling testing. Long
term tests were performed at conditions simulating full and reduced load boiler
operation. Their 40 hour duration has been established based on past experience
relating FPTF deposits with those from the field. Standard firing, low NO^ (base-
line) and low N0X with limestone addition tests were run to evaluate the effects
of low NOy firing and limestone addition during low N0X firing, individually. Long
term limestone injection tests were performed at Ca/S mole ratios of 2.0 and 3.5.
Phase II testing with the Montana coal included a series of short term N0Y, SO-
optimization tests and four long term tests (40 hour) evaluating slagging and
fouling. The short term tests were performed to establish firing conditions for
long term testing. The four long term tests were run at constant low N0X firing
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conditions simulating full load boiler operation. Ouring the long term
Ca/S mole ratios were varied. Ca/S mole ratios of 0 (baseline), 1.0, 2.0, and 4.u
were investigated.
The primary objective of this work was to evaluate the slagging and fouling con-
sequences of furnace limestone in.iection under representativ«, $0- removal con-
ditions: Furnace limestone injection geometry and operating concftions were not
selected to optimize S02 capture. Sulfur capture levels observed 1n the FPTF were
in the range of previous field experience.
TEST FACILITIES AND PROCEDURES
The ash behavior of the fuels was evaluated using the Fireside Performance Test
Facility (FPTF) (Figure 1), a pilot scale (2-4 MMBTU/hr 0.6-1.2 MW) combustion
test facility designed to simulate the heat transfer surfaces, combustion con-
ditions and ash deposit properties in & pulverized coal fired il*T , i„I wn
furnace is bottom fired with staged combustion capabilities to simulate a low N0X
combustion environment. The furnace radiant section, designed to simulate the
temoeratures and residence times of a full scale boiler, contains a .
waterwal1 test surface to evaluate lower furnace ash deposition. In the convective
section, designed to simulate velocities and a range of temperatures corresponding
to a full scale boiler, four banks of air cooled probes are used to .
boiler reheater and superheater tubes and study convective section
Short term test results led to the injection of overfire air through the m1ddl«
location to reduce N0„ emissions and limestone through the side location for all
long term tests (10)/Temperature conditions associated with low N0„ firing were
believed to be essential for S02 removal at the beginning of this project.
Lower furnace ash deposition (slagging) is evaluated based upon
panel deposit cleanability (evaluated using an air lance which
mercial sootblowing conditions), physical characteristics a"d \
deposit on waterwall panel heat flux. Convective section ash deposition fouling)
is evaluated based upon the convective ash deposit physical characteristics,
accumulation and cleanability. Cleanability is evaluated with a^JJ-e meter to
determine deposit to tube bonding strength measurements (BSM s); B5W s >5
indicate deposits are controllable with conventional sootblowers.
The flue gas SO. concentration 1s measured downstream of the FPTF costive:sec-
tion. A gas sample is drawn Into a phase discriminating probe which »P«rat«s the
suspended flyash particles from the gas sample and quenches (200 F, 93 C) the gas
sample to prevent further SO? - alkali reactions. The 9as sample 1s not cooled
below the sample dew point because any water present would absorb SO-. The 50,
measurement is performed by a Oupont S0? analyzer. Flue gas NO^ concentration s
also measured downstream of the FPTF convective section, using a second gas samp
line. The gas sample is conditioned to remove flyash particles and *ater
then introduced into the gas analysis system. A chemiluminescent analyzer measures
the N0y concentration. Other analyzers measure the concentrations of CO, co2, ana
0-. A
o2.
SLAGGING CHARACTERISTICS OF ILLINOIS # 6 COAL
Baseline Results
During standard firing (20% excess air, no overfire air) of the
"critical" temperature range for controlling lower furnace ash deposits was
2900-3000*F (1593-1649#C). In this range waterwall panel deposits changed from
sintered (1/4-1/2 inch, 0.6-1.3 cm thick) and deanable through
molten (1/2-3/4 inches, 1.3 - 1.9 cm thick). Oeposit physical states are very
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similar between the FPTF and the field; generally field deposits are a bit thicker
than those generated in the FPTF. Deposits on utility waterwalls are also sintered
to molten in nature, 0-4 inches (0-10 cm) thick at comparable furnace conditions.
Although the field deposits are controllable with regular sootblowing, this Changs
in physical state (from sintered to molten) plus experience at the utilities
indicates-, that there is little margin to increase load (temperature) beyond this
point. Hence this 2900-3000^ (1593-1649aC) range can be considered a critical
temperature for both the FPTF and the field.
Effect of Staged Combustion
Low NOy or reducing conditions had a pronounced effect on increasing the severity
of slagging with this high iron coal. In Figure 2 waterwall panel heat flux is
shown for tests with (Test 8, primary stage stoichiometry of 0.9) and without
(Test A, primary stage stoichiometry of 1.2) staged combustion. Flame temperatures
during both tests were similar (2620-2630°F, 1438-1443'C); all tests were run with
20% overall excess air. Lightly sintered deposits covering about 50% of the lower
panel and 4036 of the upper panel developed during standard firing. The lower panel
deposit was cleaaable through sootblowing with heat flux increasing from 13,000 to
54,000 3tu/hr ft (41-170 Kw/m ) after sootblowing 12 hours into the test. In com-
parison, during low N0„ firing molten deposits covering 100% of the lower panel
and about 80% of the upper panel surface developed. After 12 hours of test firing
the £ower waterwall panel heat flux was approximately 22,000 8tu/hr-ft (69
kw/m"). The heat flux after sootblowing returned to between 25,000 and 30,000
8TU/hr-ft (79-95 kw/m ) indicating the molten deposits were not removed from the
panel and were not controllable by sootblowing.
These results clearly show that staged combustion alone will have a pronounced
affect on increasing slagging. Critical temperatures for slagging were greater
than 2900*F (1593°C) for a primary stage stoichiometry of 1.2 and less than 2620"F
(143S°C) for a primary stage stoichiometry of 0.9. The most likely cause of this
is the fact that iron in a more reduced state melts at lower temperatures. Iron
can also act to flux silica present in the panel deposit further lowering the
melting temperature (6). Illinois #6 coal ash has about 14% iron (analyzed as
Fe-0,). The iron has a strong influence on the slagging characteristics of the
coal"?
Effect of Limestone Addition Under Low Conditions
Limestone addition at Ca/S mole ratios >2.0, during low N0X firing at flame temp-
erature of 2600-2700*F (1427-1482*0 resulted in an overall Improvement in slag-
ging. Although waterwall panel deposits developed at a faster rate and Increased
thickness due to limestone addition, the deposit physical state and cleanability
was generally improved.
Comparison of tests with Ca/S ratios of 0, 2.0, and 3.5 (Tests 8, C, 0, Figure 3)
indicate poor deposit cleanability without limestone and good cleanability with
limestone, evidenced by the sharp increase in heat flux immediately after?soot-
blowing with limestone addition (12.000 to 73,000 8tu/hr ft£ (54-230 kw/m ) for
test C, 15,000 to 60,000 Btu/hr ft (47-189 kw/m ) for test 0.). Oeposit physical
state was molten at Ca/S of 0 and 2.0 and sintered at Ca/S»3.5. Panel surface
coverage was 90-100% for all cases. However deposit accumulation was greater with
increased limestone addition and the heat transfer benefits of improved clean-
ability were shortlived (5-6 hrs for Ca/S ¦ 2.0, 2-4 hrs for Ca/S ¦ 3.5). While
this cleanable situation is still preferable to the baseline non-cleanable situ-
ation, conventional sootblowing frequencies on the order of 8 hours will not keep
up with the increased accumulation rate for Ca/S * 3.5. Furthermore, the increased
ash loading in this situation (26.5 lb/MMBTU'-vs. 9.2 lb/MMBTU for baseline, 48 vs
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17 mg/kcal) is impractical from a material handling standpoint. A Ca/S ratio of
less than two appears to be a practical upper limit for most high sulfur (3.5% S)
coals based on the additional particulate loading due to limestone addition.
Results of baseline and limestone addition tests Indicate that the addition of
limestone resulted in a slight reduction in heat flux before blowing the panel due
to the-insulating effect of the deposit. Deposit thickness also increased with
limestone feed rate, ranging from 1/8-1/4 inch (0.3-0.6 cm) at Ca/S«0 and 2.0 to
1/2-3/4 inch (1.3-1.9 cm) at Ca/S*3.5. However, the improvement in deposit clean-
ability with limestone addition resulted in an overall improvement in average
waterwall panel heat transfer compared to the baseline (no limestone) test. These
results indicate that during low N0„ steam generator operation with limestone add-
ition, sootblowing will be required more frequently in the lower furnace. However,
the blowers will be more effective in removing wall deposits with limestone add-
ition.
FOULING CHARACTERISTICS OF ILLINOIS # 6 COAL
Baseline Results
During baseline standard firing and low N0„ firing Illinois #6 coal exhibited a
moderate/low fouling potential. Above 2150*F (1177°C) highly sintered deposits
developed during baseline tests. This shows excellent agreement with utility oper-
ation where highly sintered deposits develop above 2100*F (1149°C) on boiler heat
transfer surfaces. Deposit accumulation was low for baseline tests with no accumu-
lation below 1750#F (954°C) gas temperature. This temperature is between the
normal operating gas temperatures for a finishing reheater and finishing super-
heater in a utility boiler.
Throughout Illinois #6 coal testing the convective probe deposit to tube bonding
strengths were low (*5). This result indicates that sootblowing should be effec-
tive at removing convective pass deposits during utility operation at standard,
low N0„ or low N0„ with limestone injection firing conditions. Of key concern was
deposit accumulation rate, measured during the final 8 hours of the FPTF tests.
For all baseline tests (both standard and low N0„ without limestone) deposit
buildup rates were universally low (less than 0.3 Ib/hr ft , 0.4 g/sec nr) for gas
temperatures below 2150°F (1177*C, Figure 4). Test F results also show that at gas
temperatures above 2150*F (1177*C) deposit buildup rate significantly increased.
At a gas-temperature of 2300*F (1260*C) the deposit buildup rate increased to 1.1
Ib/hr ft (1.5 g/sec m ).
The similar convective pass fouling results obtained during both the high N0X and
low N0„ FPTF tests indicated that changes in burner zone stoichiometry and/oP
flame temperature had little effect on the fouling characteristics of Illinois *6
coal. These results suggest that convective pass fouling deposit characteristics
during utility operation employing a low N0X firing system will be similar to
fouling deposit characteristics obtained with the present firing systems.
Effect of Limestone Addition Under Low NO^ Conditions
Convective section probe deposit buildup rates increased significantly as lime-
stone addition was increased from 0 to 2.0 to 3.5 during low NO,. firing with
Illinois #6 coal. Convective pass deposit buildup rate curves for high firing rate
tests E (Ca/S»0) and G (Ca/S-2) and low firing rate Tests B (Ca/S-0) H (Ca/S-2)
and I (Ca/S«3.5) are presented 1n Figure 5. At both firing rates the effect of
limestone addition on deposit buildup rate is evident. Both graphs show the con-
siderable increase in deposit buildup rate that occurred due to limestone addition
28-5
-------
(Ca/S * 2.0) in comparison with the baseline (Ca/S*0) curves. The low firing rate
graph also shows that as limestone addition is increased from a Ca/S ratio of 2.0
to a Ca/S ratio of 3.5, there is a further substantial increase in deposit buildup
rate.
The increase in deposit buildup rates, due to limestone addition, resulted in more
frequent convective pass sootblowing cycles to maintain a standard deposit thick-
ness of less than 3i Inches. During high firing rate baseline Test E and limestone
addition Test G (Ca/S*2.0) the sootblowing frequency was about 15 hours and 5
hours respectively. Similar results were obtained during low firing rates Tests 8.
H, and I. Increasing the limestone feed rate from a Ca/S«0 to Ca/S«2.0 to Ca/S»3.5
increased the sootblowing frequency from 20 hours to 8 hours to 6 hours. Convec-
tive pass velocities during the high firing rate tests fell within the range of
utility convective pass velocities for Illinois No. 6 coal. As a result the high
firing rate deposit buildup rates best represent utility operation and indicate a
Ca/S ratio of less than two is probably a practical upper limit based on soot-
blowing frequency (5 hours).
Deposit to tube bonding strength measurements (BSM's) were low during all tests,
being slightly lower during limestone addition test (maximum less than 4, majority
less than 1) than tests without limestone (maximum less than 4, majority of 1-3).
As stated earlier deposit accumulation rate will be a limiting factor, limiting
limestone addition to a Ca/S ratio of less than two with this coal.
Illinois »6 Coal SO., Capture Results
While not a primary objective of this project, results indicate that gas temper-
ature and residence time have a strong influence on sulfur capture, with increased
absorption occurring at extended residence times below 2300#F (1260*C). Earlier
work performed by Battel1e (7, 8) suggests the existence of an upper temperature
limit (2300aF, 126O0C) for sulfur capture dictated by calcium sulfate thermo-
dynamics. Therefore thermodynamics favor low temperatures.
The Sattelle work also suggests a lower temperature limit for S02 absorption. The
minimum temperature for S02 capture is less easily defined. Hence a "temperature
window" may exist for SO- capture. The upper limit of this window is set by
thermodynamics of calcium sulfate stability and 1s about 23G0BF; the lower limit
is established by lime/SQj/O* reaction rates to form calcium sulfate and is
unknown.
Oata from the FPTF was correlated with temperature. Results correlated best with
temperatures between 2300*F (1260°C) and 180Q°F (982*C, typical FPTF convective
section outlet temperature). Figure 6 supports the existence of an 1S00-2300*F
(982-1260°C) temperature window with S02 removal increasing with residence time in
this window. At a residence time of about 0.7 seconds, which closely simulates
residence time 1n a utility boiler in this temperature regime, about 25% sulfur
capture was obtained at Ca/S-2.0.
SLAGGING CHARACTERISTICS OF MONTANA SUBBITUMINOUS COAL
Baseline Low N0V Results
One limestone-free low N0« test was performed as a basis for comparison with the
limestone additive tests. During baseline Test A the average peak flame temper-
ature was 273QaF (1499°C). One eighth to 1/4 inch (0.3-0.6 cm) thick molten
deposits developed on the lower waterwall panel and 1/4 to 1/2 inch (0.6-1.3 cm)
thick molten deposits developed on the upper waterwall panel. The deposits were
fluid in nature, flowing down the panel surface. The lower and upper panel
28-6
-------
deoosits were removed with the sootblower after 12 and 20 hours of testing (Test
A, Figure 7). Very thin molten deposits may be removed from waterwall panel sur-
faces by thermally shocking the deposit with a relatively cold cleaning medium.
Utility boilers firing this high sodium Montana coal experience a similar slagging
situation as was obtained during FPTF Test A. Thin molten deposits are generally
obtained'which do not significantly reduce heat transfer. Removal of these
deposits through conventional sootblowing techniques, while not as effective as
with dry or sintered deposits, is generally attained due to the fact that deposits
are thin enough to permit thermal shocking.
effect of Limestone Addition Under Low NO^ Conditions
Three long term tests were performed to evaluate the effect of limestone addition,
during low N0„ firing, on the slagging and fouling behavior of this coal. Test
conditions were consistent with Test A with the exception of limestone addition.
Tests 8, C, and 0 were performed at Ca/S ratios of 2.0, 1.0, and 4.0 respectively.
Results indicate that as limestone addition (Ca/S ratio) increased, waterwall
panel deposit thicknesses increased and deposits became drier. At Ca/S ratios 52.0
thicker (1/4 to 1-1/4 inches, 0.6-3.2 an) drier (sintered) deposits developed on
both the lower and upper panels in comparison with the thin (1/8-1/4 inch,
0.3-0.6cm) molten deposits encountered during test A. At a Ca/S ratio of 1.0 (Test
C), the lower panel deposit was similar to that from Test A. However, the Test C
upper panel deposit was drier and thicker than from Test A. During limestone
addition the formation of thicker sintered deposits on both the upper and lower
panels restricted heat transfer in comparison with the baseline results. Sintered
deposits generally have lower thermal conductivities than molten deposits. Hence
the formation bf thicker sintered deposits compounds the insulating effect. At
Ca/S ratios>2.0 both upper and lower panel deposits resulted in a significant
reduction in heat transfer to the panel compared to baseline results (Figure 7),
The baseline steady state heat flux for the lower panel was about 45,000-BTlj/hr
ft (142 kw/m ) and for the upper panel about 20,000 BTU/hr ft (53 kw/m). In -
comparison the test B (Ca/S-2) heat flux for the lower panel was,15,000 BTU/hr-ft
(47 kw/m ) and for the upper panel about 8000 BTU/hr ft (25 kw/m ), significantly
lower due to the 1/4-3/4 inch (0.6-1.9 cm) sintered deposits which formed on the
panel surface. Similarly, the Test.D (Ca/S»4?0) lower panel steady stats heat flux
was approximately 13,000 Btu/hr ft (41 kw/m) and the upper panel 8000 Btu/hr ft
(25 kw/m ) with 1/2-1 1/4 inch (1.3-3.2 cm) sintered deposits.
At the 12 and 20 hour point of each test, the upper and lower panel deposit clean-
abilities were evaluated with the sootblower. In general the deposits from each
test were removed from the waterwall panel with the sootblower. The heat flux
benefit from cleaning the waterwall panel varied from 1 to 5 hours before
returning to a steady state condition. At Ca/S rstlossZ.O the lowes panel heat
flux recovery approached clean panel conditions ( 60,000 Btu/hr ft , 189 kw/rn).
At a Ca/S^ratio of 4.0 (lest D), the lower panel recovery was less (35,000-45,000
Btu/hr ft , 110-142 kw/m ) due to the greater rate of deposit accumulation and
thicker deposits associated with the greater limestone feed rate.
During baseline low N0X testing with this high sodium coal thin molten deposits
developed on the waterwall panel. Sootblowing was effective at removing the'
due t0 a th«rmal shock mechanism. These results are consistent with
utility operation with this coal at standard firing conditions. Limestone addition
in the FPTF at Ca/S ratios>2.0 resulted in the formation of thicker sintered
deposits, also amenable to sootblowing, but reduced heat transfer to the panel by
greater than a factor of two. In a utility the reduction in heat transfer may be
the limning factor in establishing limestone additive feed rate. A possible
28-7
-------
alternative to obviate the reduced heat transfer effect 1s to add the limestone as
high in the furnace as possible providing the limestone can be properly distri-
buted. Given this scenario it may be possible to add limestone at Ca/S ratio >2.0.
FOULING CHARACTERISTICS OF MONTANA SUBBITUMINOUS COAL
Baseline. Results
The fouling mechanism of the high sodium (5.9* Na-0 in ash, 4.9% ash) Montana Sub-
bituminous coal studied is dominated by the active organic sodium compounds pre*
sent in the coal (9). At furnace flame temperature these low melting sodium com-
pounds vaporize. Condensation and solidification of the sodium compounds on rela-
tively cold heat transfer surfaces and ash particles results in highly fused
deposits which are tightly bonded to tube surfaces. The sodium compounds are
therefore the "glue" responsible for formation of the strongly bonded deposits.
Utility steam generators firing high sodium Montana subbitumlnous coal have exper-
ienced severe fouling problems. The buildup of strongly bonded deposits on
reheater and superheater finishing sections (especially the areas not directly
covered by sootblowers) has lead to pluggage and heat transfer problems. Constant
cycling of the convective section sootblowers is required during boiler operation.
During low N0X baseline Test A this coal exhibited a high fouling potential. The
deposit buildup rate w« relatively low with 3-1/2 inch (9cm) deposits developing
on Probe Bank I after about 16 hours of furnace operation. However, the deposit to
tube bonding strengths were high. Bonding strength measurements below 15 usually
indicate the deposits will be controllable with conventional sootblowers. During
baseline Test A average maximum bonding strength measurements fell in the 20-30
range indicating that at flame temperatures of about 2750°F (1510*C) and gas
temperatures above 1920°F (1049°C) deposit cleanability is poor.
The physical state of the outer deposits ranged from hard/sintered on the front
probes in Banks I and II (gas temperatures between 2085 and 200GaF (1140-1093'C))
to lightly sintered on the back probes in each section. The lightly sintered
deposits were friable and broke into smaller pieces when contacted with the
bonding strength apparatus. The hard, sintered deposits were difficult to break
into smaller pieces when hit with an Iron rod. These hard sintered deposits
represent a problematic situation in a utility boiler. Not only are they difficult
to remove- from tube surfaces, once removed they are difficult to break into
smaller pieces which may lead to pluggage of heat transfer surfaces downstream in
a toiler, for example the economizer section.
Effect of Limestone Addition Under Low No^ Conditions
Ouring the four low N0„ tests only Ca/S mole ratio was varied. Tests A, B, C, and
0 were performed at Ca/S mole ratios of 0, 2.0, 1.0, and 4.0 respectively. Results
show that as furnace limestone addition increased, convective pass deposit buildup
rates increased and deposit to tube bonding strengths decreased.
The most significant result of limestone addition, with regard to fouling, was the
reduction of deposit to tube bonding strength measurements. Figure 8 presents the
average bonding strength measurements obtained on probe Bank I ( 2100"F or 1149'C)
for the four tests. In comparison with the baseline (Ca/S«Q) average bonding
strength of 30, at a Ca/S ratio of 1.0 (Test C) the average bonding strength value
decreased to 7 as a result of limestone addition. Increasing the limestone add-
ition rate to 2.0 and 4.0 resulted in further reductions in the bonding strengths
of deposits. This trend was consistent throughout the FPTF convective section over
the temperature range 2100-1700°F (1149-927'C). Therefore, the addition of "lime-
stone at Ca/S ratios >1.0 results in an improvement from a severe/high fouling
28-8
-------
situation to a moderate situation with deposits controllable with conventional
sootblowers. Limestone addition also resulted in an improvement in the physical
state of the deposits. As Ca/S ratio was Increased the friability of suP«^JJtj;"
probe outer deposits tended to increase. This increased friability may reduce
potential for pluggage of boiler heat transfer surfaces with large deposits sus-
pended in the gas stream.
Convective pass deposit accumulation rates (Figure 9) Increased
addition. As the Ca/S ratio increased from 0 to 1.0 to 2.0 to **0' "f
frequency increased from once every 16 hours to 11 hours to 8 h°"rs to 6 hou s
respectively. These results indicate that a utility boiler should b« able to oper-
ate at a Ca/S ratio between 2 and 4. However Increasing the limestone additive
feed rate above a Ca/S ratio of 4.0 will probably increase the convective pass
sootblowing frequency to an impractical level, i.e., more than once per shift.
With respect to steam generator operation, the reduction in convective pass
deposit to tube bonding strengths as a result of £u™ace ! jestone action should
be a great benefit. A high fouling situation (Ca/S»0 should be proved to a
moderate situation (Ca/S >1.0) with deposits controllable wi ."Je"
blowers. Deposit buildup rates will increase as a function of limestone additive
feedrate. A Ca/S ratio of between 2.0 and 4.0 appears to be an upper practical
limit based on sootblowing frequency results in the FPTF.
Montana Subbituminous Coal SO- Capture Results
In comparison with Illinois #6 coal, the Montana subbituminous coal selected for
the test program has about one-fifth the sulfur content and a s gn^"ntly
greater concentration of alkali in the ash (see Table 1). The alkali r**c ,
with SO- formed from the sulfur 1n coal to reduce flue gas SO- concentration sign-
ificantly. The alkali/S mole ratio 1n this coal is 1.96, compared to 0.13 n
Illinois »6 coal. As a result, the SO- absorption values obtained during testing
are based upon a theoretical SO- emission value rather than a measured base
SO- value as was the practice diring Illinois *6 coa testing. The theoretical S02
vaW (457 ppm) was calculated based upon the ASTM ultimate analysis o
posite coal feed sample obtained from each long term test (0.5% sulfur).
Again results (Figure 10) Indicate that sulfur capture «« strongly Influenced by
Ca/S ratio and residence time between 1800-2300 F (982-1260 C).
increased from 2% to 35S as Ca/S ratios (based on ^«"one addition) Increased
from 0 to 5 at 0.4 second residence time and from 32* to 67* at 0.9 "cond
residence time at similar Ca/S ratios. The 0.9 seconds results also 1n^cate
substantial anouit of sulfur capture (32%) by alkali in the coal ash. These
results were obtained with minimal ash deposits.
A substantial amount of sulfur capture was also obtained by convection Pass ash
deposits with this coal. Results (Table 2) indicate that for similar reside ce
times and Ca/S ratios sulfur capture increased by as much as 125 ppm for tnis
coal. Given the low sulfur content of this coal this translated into as much
27% increase (31X to 58X) in sulfur capture.
UTILITY APPLICATON OF RESULTS
Illinois #6 Coal
Figure 11 is a schematic of a typical utility firing Illinois *6 coal at a stan-
dard firing condition with no limestone addition. The radiant and convective
section problem areas are indicated. While utility boilers firing Illinois coat
generally have not experienced major slagging problems, FPTF results suggest tney
28-9
-------
are operating at a critical temperature (2900-3000°f)(1590-1650°C) with littfe, if
arty, safety margin. An increase in flame temperature may lead to slagging pro-
blems. Extensive fouling of the reheater pendant and economizer surfaces has been
experienced 1n some utilities firing Illinois #6 coal. The buildup of hard sin-
tered deposits on closely spaced reheater elements results in deposit bridging
between.tubes, requiring frequent sootblowing. Hard sintered deposits that are
removed by sootblowing convective surfaces lodge in the straight finned staggered
tube economizer resulting In economizer pluggage. Frequent sootblowing and/or
pluggage of heat transfer surfaces leads to erosion of tube surfaces and accele-
rates tube failure.
Figure 12 is a schematic of a utility firing Illinois #6 coal with a low N0X
firing system and furnace limestone injection (Ca/S*2.0). Assuming that a low NCL
firing system can be designed and implemented without increasing slagging, then
limestone addition at a Ca/S ratio' 2.0 will reduce slagging. Accumulation of
waterwall deposits will increase, requiring more frequent sootblowing, but
cleaning effectiveness will also increase. A greater number of sootblowers and
more frequent blowing will be required in the pendant reheater area. Limestone
feed rate will ultimately be limited by the ability of the sootblowers to ke«p up
with deposit accumulation in the pendant reheater and will most likely be limited
to Ca/S *2. Bare tube in-line economizers are recommended, if possible, to reduce
pluggage of economizer sections due to the lodgement of deposits from upstream
convective sections.
Montana Subbituminous Coal
Utilities firing this Montana high sodium coal at standard or baseline conditions
(Figure 13) experience thin molten deposits on waterwall tube surfaces. These
deposits are generally controllable by frequent (3 to 6 hours) sootblowing. Severe
fouling problems are encountered, particularly in the finishing superheater and
finishing reheater surfaces. Thick (3"-12*\ 8-30 cm) highly sintered strongly
bonded deposits develop which cannot be effectively removed with conventional
sootblowers. Although the deposit buildup rate is low, frequent blowing is a con-
sequence of the ineffectiveness of sootblowers.
Furnace limestone injection (Ca/S *1.0) in a utility firing this coal with a low
N0X firing system (Figure 14) will greatly reduce convective pass deposit to tube
bonding strengths to levels controllable with conventional sootblowers overcoming
a major problem. Deposit friability and accumulation rate will increase as lime-
stone injection rate 1s increased. Limestone injection rate may be limited by the
insulating effect of lower furnace deposits. FPTF results indicate that limestone
addition at Ca/S ratios >2.0 will significantly reduce heat transfer through the
water-walls. Therefore, during utility operation, the ability to maintain heat
transfer rates 1n the lower furnace may set the maximum limestone feed rate.
CONCLUSIONS
The application of furnace limestone injection will be fuel and unit specific. Two
coals representing a wide range of fouling characteristics were tested at pilot
scale: a high iron, high sulfur Midwest bituminous coal and a high sodium, low
sulfur Western subbituminous coal. Results indicate that limestone can be injected
without adversely affecting the furnace slagging and convective pass fouling per-
formance of units firing these two coals under standard firing conditions. For
high sodium coals limestone has significant potential for reducing fouling by
weakening deposit to tube bond thereby enhancing sootblower cleaning effective-
ness.
28-10
-------
Staged combustion resulted in significantly increased slagging for the high iron
Midwest coal. Careful thought should be given to the design of commercial low N0„
firing systems for high iron coals to avoid this problem.
With each coal upper limits for limestone addition were established based upon
deposit accumulation and/or heat transfer rates, limits were Ca/S between 2 and 4
for the low sulfur coal and less than 2 for the high sulfur coal. While limestone
did not adversely affect the high iron coal investigated, other high iron coals
should be examined on an individual basis to avoid potential fluxing effects of
calcium on the iron which can increase slagging.
Finally, a laboratory procedure to measure the slagging and fouling consequences
of furnace limestone Injection was demonstrated. Oue to the variability in par-
ticular coal properties, utility companies considering this technology would be
advised to consider laboratory tests to screen particular coals for their slagging
and fouling characteristics.
ACKNOWLEDGEMENT
Special thanks to members of CE's Fuels Research Group for test performance, data
acquisition and reduction. Thanks also to Chemical Systems, Research Services,
Advanced Systems Analysis, Performance Design and Secretarial Services groups and
to Art Plumley, Dick Borio, and JoEllen Allen.
REFERENCES
1. Gartrell, F. W. "Full-Scale Desulfurizatlon of Stack Gases by Dry Limestone
Injection," Volume I, II, and III Tennessee Valley Authority, Chattanooga,
Tennessee, August, 1973
2. Energy and Environmental Research Corporation presentation to EPA Contractors
Meetings, 1979, 1981, 1983.
3. Plumley, A. L., Whiddon, 0. D., Shutko, F. W., and Jonakin, J., "Removal of
SO- and Dust from Stack Gases," Proceedings for the American Power Conference,
Chicago, April 1967, p. 592-614.
4. Borio, R. W., Goetz, G. J., and Levasseur, A. A., "Slagging and Fouling Pro-
perties of Coal Ash Deposits as Determined 1n a Laboratory Test Facility,"
paper presented at the ASME Winter Annual Meeting, December, 1977, Combustion
Engineering publication TIS-5155.
5. Pollock, w. H., Goetz, G. J., Park, E. 0., "Advancing the Art of Boiler Design
by Combining Operating Experience and Advanced Coal Evaluation Techniques,
paper presented at the American Power Conference, April 1983, Combustion
Engineering publication TIS-7382.
6. Borio, R. w., Narclso, R. R., Jr., "The Use of Gravity Fractionation Tech-
niques for Assessing Slagging and Fouling Potential of Coal Ash," paper pre-
r«nt?d at th® ASM^ Winter Annual Meeting, December 10-15, 1978, San Francisco,
CA; Combustion Engineering publication TIS-5823, Windsor, CT.
7. Battelle Memorial Institute, "Fundamental Study of Sulfur Fixation by Lime and
Magnesia," Columbus, Ohio, June 1966.
8. Battelle Memorial Institute, "Investigation of the Reactivity of Limestone ana
Dolomite for Capturing SOg from Flue Gases," Columbus, Ohio, August, 1968.
28-11
-------
Hale, G. I., et al., "The Alkali Metals in Coal: A Study of Their Nature and
Their Impact on Ash Fouling," Presented at 3rd International Coal Utilization
Exhibition and Conference, November, 1980.
Goetz, G. J., and M. 0. Mirolli, "Fireside Consequences of limestone Injection
Under Low N0X Conditions," EPRI Research Project 889-2, 1984.
superheater
WATER &
AIR COOLED
SECTION 1
AIR COOLEO
SECTION II
LIMESTONE
ITOP)
OVERFIRE AIR
(TOP)
AIR COOLED
SECTION III
ir-4'A
1V COOL J IMG AIR ANNUL US
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SURFACE
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OVERF1RE AIR
IMIOOLE)
WATER t
AIR COOLED
SECTION IV
PROBE PORTS
L1ME5TONS (SIOE)
OVERFIRE AIR
(BOTTOM
AIR COOLEO
SECTION V
WATER COOLED
SECTION VI
Fig. 1: Fireside Performance Test Furnace
28-12
-------
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Fig. 3: Illinois *6 Coal Tests B. Cand D
Watervdl Panel Heat Flux Curves
28-13
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& c*» a Ttsr «
110*1
lUWMMtATMOA*T1I»«IUTVJ1U. ft C)
Fig. 6: SO2 Removal 7: vs Residence Time m the Temper- Fig. 5: Effect of Limestone Feed Rate (Ca/S Ratio> on
ature Range 2300-1800*F, (1260-980"C) During Superheater Probe Deposit Builtup Rate During
Illinois =6 Coal Testing
Low S'0X Firing of Illinois =6 Coal /Two Firing
Rates)
28-14
-------
Tttr a
•ktW PANCk
nwiwo cowomowt
¦UMNfft ZOM JTOtOMOMtTHV ¦ a?
•VMM! MA* )UUM
TUWfftATUM mtT' IMK*e)
Bin MOLX RATIO • 0
•kIW »AN|k
ill MNIk
— — —t.0Win MNIL
5 " 000 .
w II it 2* 10
CUMUkATIVI TUH. KOMI
S mm-
i 30.
MIHHG COWOITlQWt
MMK ZONi STOICMIOMfTftV Of
WUMil HM FlUII
timmhatum me** im«i
C4SM0U matio • :.o
MANUAkkV CUAMO
MMtL
vm* MML
«— k0MM»AMk
tut •
Dr w
CUMUkATIVI TMH HOUMI
tut e
www eawoiTiowf
•ummn xmn rrotCHOMirn* a?
AVtftAOI HA* FkAOt
TIM0MATUIIC JT%Ba* (IIIO'O
C~« MOlf MATIO • 10
H MML
»ANIk
»U» »»Ml
« ~V ts w 36
CUMUkATIVI KM HOURS
v-\
TUT 0
nmwc eowoiTiqim
MMNlft /0N( tTOICHIOMCTHV 07
MIMOl HAK lUM
timwiatu*i jw«*»
CM MOkt KATI0 • 4.0
—— —VOWM MNIl
ILIW PANtL
•kIW HKIL
W II » 21 30
CUMUkATIVI TIMI. NOUftS
fig. ?: Montana Subbiruminous Coal Watermll Panel Heat Fhut Curves
28-15
-------
z
//
• a to
Cwl MOkl RATIO
Fig. 3: Montana High Sodium Coal Deposir-to-Tube
Bonding Strength as a Function of CajS Mok
Ratio
4. TO
0*0 -
MB -
3
S t-*o
I
* 0.M
s
430
a io
CgWOITIQW:
11% MMgTU.W* COAL
WO Hl«
'cam(
»««oi»mo-J7W»»
STOICMlOMfTft'V
- Oujt»c*u
Otut »c*»
Qrurce**
_ &rtnse«s
e«t mou »*no ihho on cimutqm *«o
C* IN COM. Atm
lot 1.0* »0» !«
I0i
Mtouci tiwi naa-iMOX mmwi
OMSKOWI
&04 St CO HOI
mmho eowoinoNi
in MM«ru m» CMt
¦UftNCII JOM ITOICM • 17
Ha* '(.ami
TIMHMruM MNQI
iutrM** u«nis'«i
100 too J.ot
cm Mou Mm. who on uMCsrow aooition
lot
Fig. JO: Effect of CafS Mole Ratio on SO2 Removal at
7V) Residence Time In the Temperature Range
2300-1800"F While Test Firing A Montana Sub¦
bituminous Coal
1*00
1701
IIM
1 nam in
TttWtlUkTUM. ®* («C1
21«0
<11M
2300 1
<11001 II
Fig. 9: Effect of CafS Ratio on Superheater Probe Depos-
it Buildup Rate During Montana Subbiwninous
Coal Testing
28-16
-------
s
f
*
9
2
m
s ^
o «
I!
t
**¦
sk
S
«•
M
m
i
1
•MISIH
* M
m» Z
8-
J
Hoaiz. low
TIM»l H
radiant ncriow
OURATINC AT LOAO LIMIT1
moltin deposits
iv ir tmicki
•OS COVtRAfit 0*
HIAT TRANSHR
SURFACU
THICK I-1*-)
dntirio oipohti.
'MOUINT aLOWtNG
MOUIMO
huoomi.
OTINTtAl
inoooN
OURIS'llIO
U» TO 10- MIQM
iconomotri
icOMOMinn
MONIZ LOW
T1M»$ M
1. GRIATf R Of ROUT
1LMLOU* RATI
RAOIANT HCTIOM
1. ORIIR
OWOMTt
t ORUTIK
ocranr
cov«rag«
or HtAT
TRANSMR
KJR'ACU
1. IOOT»LOWtR*
mom ime
TlVt
4. innm
OUINtlkON-
N«a RIQUIRI0
*. nmu
Of LOAD GAIN
ihlaooino
limitid
ocratir
'RIAWklTV
IMTAkk MOM
nonioMM
4. MOM PRKMKNT
•lowing
RIOUIRM
*. •OSWLl
LIMITING
mctor
1. ORlATfR J
OWOBT <
ACCUMULATION
RATI
2. RtHACIWITW
•Ml TUM IN-
LM VfRSION
iFvonwki
J. MCTALL
INTIRBANK
IUMW
WTfNTIAL
»LlMt
CIATTO WITH LOW MO,
FIRING CAM >1 COUNTIRACTW
¦VOUMNMUIURU
Fig. U: Typical Utility Firing Illinois *6 Coal Baseline
Fig. 12: Utility Firing Illinois Coal with Limestone
Addition (Ca/S * 2.0), Under Low NOx Condi-
tions at Reduced Flame Tmperature (200°F
Reduction)
Twm
11/4*'
•W.TIN OITCSITS
i/ri
2*SiiS13ISI!22
THIN IIT' T'I MOLT1N
OlfOtlTI Q0Nl70UA«L|
•* 'mouint toomowma
thick ir iri
mOML» 1INTIRI0
fTRONOLV tOMOtO
nwtin 'Miaui nt
noTtbOwwe
RIOUIRM
HARD KALI ON
UMOING TUBCS
•OWOIR ON Rf MAIN
INO TUMI
MOMOMIItR
.
!
-
m
5
9
2
¦ »
m
LmmJ
1
i
m
Is
m
m
41
*»
£
«i8
c
thick, dntirio oiwsiti
MORI fRiOUlNT M.OW
INO RI0UIR1D
IOOT1LOW1M MORI
imerivi
RIBWCTIOW IN MAT
TRANWIR OUI TO
IMVLATlNO hmct or
DIWSITS POWILl
limiting factor
/
Rtoucto oirostt
to tun •onoino
ITRINOTMf
nemoiMM
MORI I»iaiV!
INCRIAU IN
Of WOT PRIA-
•inr*
INCRIAMD
OTOIIT tUILSU*
RATI1
'RIOUINT (LOWING
RHUIRID
HONORNIIR
leoNOMtnR
Fig. 13: Typical Utility
Coal Baseline
Firing Montana Subbituminous
Fig. 14: Typical Utility- Firing Montana Subbituminous
Coal with Limestone Addition (CatSm2M) Under
Low NOv Conditions at Reduced Flame Tempera'
tare (200 FReduction)
28-17
-------
TABLE 1
COAL, LIMESTONE ANALYSES (AS FIRED)
Proximal*, Weight %
Illinois s6
Coal
Montana
Coal
TABLE 2
EFFECT OF CONVECTION PASS DEPOSIT THICKNESS
ON S02 REMOVAL
Tlw gmwn
Moisture
3.2
9.7
1800-2300* P
0(9osrt
Fhie Om
so-
Voistiis Mattsr
40.2
40.2
Ca/S
TIvMnmm
so,
Ramov
Fixed Carbon
46.4
46.2
Ratio
S««
iMtiw (CM I
PPM
%
Ash
11.2
4.9
TotaJ
100.0
100.0
0
0.S
1 12.91
434
5
HHV, Btu/lb
12.070
11,160
0
0.6
2 19.11
3M
13
(Kcal/Kfl)
6,708
6,194
1
0.8
0.2S (0.6)
341
23
Ultimata, Weight %
1
0.8
2.2S (9.7)
274
40
Moisture
3.2
9.7
1.25 (3.2)
Hydrogen
4.8
4.9
2
0.7
310
31
Carbon
68.5
64.8
2
0,8
3.9 (8.9)
191
SB
Sulfur
3.4
0.5
Nitrogen
1.2
1.0
A
0.S
0.75 It 9)
308
33
Oxygen (dif.)
9.7
14.2
Aid
11.2
4
0.7
2.0 19.1)
223
91
Total
100.0
100.0
d/S Moie Ratio •
0.09
1.05
Alkali/S Mode Ratio'11
0.13
1.96
Ash Composition, Weight %
SiOj
Ai203
P«2^3
CaO
MgO
Ns20
KjO
Ti02
SO3
Total
52.2
18.6
14.0
3.9
0J
0.6
1.4
1.0
4.6
97.1
28.4
16.6
7.8
15.5
2.5
6.9
0.2
1.2
19.5
98.6
Ash Fusibility, *F (*C)
I.T.
S.T.
H.T.
F.T.
2130(1166)
2300 (1204)
2380 (1304)
2420 (1327)
2010
2070
2150
2170
(1099)
(1132)
(1177)
(1188)
Limestone Weight %
CaCOj
M9CO3
96.7
0.4
Note: 1. Alkali ¦ Ca, Mg, Na, K
28-18
-------
EFFECTS OF FURNACE SORBENT INJECTION ON FLY ASH CHARACTERISTICS
AND ELECTROSTATIC PRECIPITATOR PERFORMANCE
Robert S. Dahlln and John P. Gooch
Southern Research Institute
2000 Ninth Avenue South
Birmingham, AL 35255-5305
and
James 0. Kilgroe
Industrial Environmental Research Laboratory
US Environmental Protection Agency
Research Triangle Park, NC 27711
ABSTRACT
The effects of furnace sorbent injection on the electrical resistivity and the sire
distribution of particles suspended In flue gas have been studied at temperatures
near 149 C (300°F). In situ resistivity and impactor data have been obtained using
various sorbents and sorbent Injection modes while firing coal in a 1.06 GJ/hr
(1 x 10 Btu/hr) combustion system. Laboratory resistivity measurements have also
been made with fly ash/sorbent mixtures using various simulated flue gas condi-
tions.
When using a 2.3% sulfur Indiana coal, the fly ash resistivity was 1n the range of
i j to 1 x 103 ohm cm at a flue gas temperature of 147 to 153#C (297 to 308*F)
ana 1n the presence of 26 to 31 ppm of SO, produced from the coal. With burner
injection of Vlcron 45*3 limestone at a calc1um-to-sulfur ratio of 1.8, the resis-
tivity was increased to 1 to 2 x 1012 ohm cm with virtually no measurable S03 left
in the gas phase at 150 to 158*C (302 to 317*F). Experiments with flue gas condi-
tioning showed that the resistivity of ash/sorbent mixtures produced from limestone
injection could be reduced to less than 5 x 1010 ohm an with the injection of 30 to
40 ppm of S03, provided there was adequate residence time for uptake of SO,. Pre-
liminary data suggest that the effectiveness of S03 conditioning may be influenced
by sorbent injection temperature when hydrated Hme 1s injected downstream from the
burner.
The implications of these and other results on electrostatic precipitator perfor-
mance are discussed, together with potential corrective measures for improving the
collection efficiency of ash/sorbent mixtures.
29-1
-------
EFFECTS OF FURNACE SORBENT INJECTION ON FLY ASH CHARACTERISTICS
AND ELECTROSTATIC PRECIPITATOR PERFORMANCE
INTRODUCTION
Program Needs
Considerable effort has been directed toward the optimization of sulfur capture in
the LIMB (Limestone Injection Multistage Burners) process. This effort has included
laboratory studies of the calcination and sulfation processes (1-3) as well as
pilot-scale testing of various sorbents (4,5). The work that has been done to date
has been successful 1n identifying sorbents and sorbent Injection conditions that
are capable of meeting the program goals of 50 to 60% S02 removal at a Ca/S ratio of
2:1. At this stage of development, however, neither the sorbent nor the process
conditions can be said to be "optimized." There are also a number of unresolved
questions concerning the economic constraints on the LIMB process; the effect of the
process on boiler slagging, fouling, and reliability; and the effect of the process
on particulate control equipment. The last item 1s the subject of the ongoing study
described here.
In a retrofit application, the LIMB process will produce a significant increase 1n
the amount of particulate material that must be handled by the particulate collec-
tor. In most cases, the particulate collector will be an electrostatic precipitator
(ESP) since ESPs currently service about 92% of the coal-fired electric generating
capacity (6). The LIMB process may also alter the particle size distribution and
the electrical resistivity of the particulate matter. These are two parameters that
can play a critical role 1n precipitator performance. In addition to these key
factors, a retrofit application of LIMB may also affect the operation of the ESP
rapper system and the ash handling system. All of these effects must be studied and
quantified 1n order to assess the effect of LIMB on ESP operation. Studies of these
effects are also necessary to serve as a basis for making Intelligent recommenda-
tions concerning potential corrective measures.
Description of LIMB Particulate Research Program
The Environmental Protection Agency's LIMB particulate research program consists of
laboratory, pilot-scale, and full-scale measurement programs. Laboratory and pilot-
scale work has been underway at Southern Research Institute (SRI) since July of
1982. To date, this work has concentrated on the effect of sorbent injection on the
particle size distribution and electrical resistivity of fly ash from pulverized
coal combustion. These effects have been studied using various sorbents and sorbent
injection modes while firing coal in a 1.06 GJ/hr (1 x 106 Btu/hr) combustor.
Cascade Impactors, an optical counter, and an electrical aerosol size analyzer have
been used to make in situ measurements of the particle size distribution with and
without sorbent injection. The effect of the sorbent Injection on the electrical
resistivity has been determined from in situ measurements using a point-plane probe
1n the combustor flue gas at temperatures near I49°C (300°F). Laboratory resistiv-
ity measurements have also been made using fTy ash and ash/sorbent mixtures
29-2
-------
collected in the point-plane probe and equilibrated with simulated flue gas environ-
ments in the laboratory.
The laboratory and pilot-scale work mentioned above is the subject of this paper.
Larger scale work is planned, but will not be described here except to mention the
major remaining elements of the LIMB particulate research program. A larger scale,
~85 m3/m.1n (-3000 ft3/min), pilot precipitator test program 1s planned for 1985
using a modified version of EPA's mobile precipitator. Full-scale testing 1s also
planned for 1985 at the Weiher Station 1n West Germany as a part of the American-
German LIMB Technology Transfer Program. Utility-sponsored full-scale measurements
with limestone injection using cleaned coal as fUel may be conducted in late 1985 at
the Pennsylvania Electric Company's Homer City Station. Precipitator performance
and particulate characterization measurements are also planned for EPA's LIMB Demon-
stration Program at a full-scale power station during 1987.
Objectives and Scope of This Study
The goal of this study was to develop Information that could be used to assess the
probable effects of a LIMB retrofit on ESP performance, and suggest potential cor-
rective measures to restore acceptable ESP performance. An assessment of this type
requires data on the effect of sorbent Injection on: the particle size distribu-
tion, the electrical resistivity, the ESP rapping requirements and reentralnmerrt,
and the operation of the ash handling system. To date, the scope of this study has
been limited to the first two factors: particle size distribution and resistivity.
Larger scale studies will provide the information concerning the effects on the
rapping and ash handling systems.
One of the first major objectives of this study was to verify that the pilot combus-
tor produced a fly ash that was an acceptable representation of that produced when
the same coal was burned in a full-scale boiler. The characteristics of the fly ash
produced in the pilot combustor were compared to the characteristics of fly ash from
a full-scale (196 MW) boiler that was firing the same coal. This involved compari-
sons of the ash particle size distributions, electrical resistivities, morphologies,
and chemical compositions. These comparisons, which are described in detail else-
vhere (7), revealed excellent correspondence between the fly ashes from the pilot-
scale combustor and the full-scale boiler. Thus, 1t was concluded that the ash
simulation capabilities of the combustor were adequate for the follow-on studies
with sorbent injection.
TESTING PROCEDURES AND EQUIPMENT
Pilot-Scale Combustion Res«»rch facility
Figure 1 presents a schematic diagram ¦.fnedPfurnac^^ic^ca^f 1 re either coal
facility. The system Includes a refractory-Jin^ furnace wmcn^ ^ fur-
or natural gas at a rate of 0.63 to 1.27 W/hr £.6 ^ £ pulse jet
nace is followed by both air- and^water-cooled heat axcnange^,^ ^ system can
baghouse. A forced draft and an Induced tenneraturts and gas velocities
be operated as a balanced draft unit. System design temperatures a™
for the principal sections are glvtn 1n Table i.
The down-fired furnace 1s equipped * Srir^/Stofng^ lorbtnt^ Injection
Mixing Burner with outboard, tertiary air locations between the burner and
points are located at the burner con lLh ^#1 and the sorbent are
the outlet of the horizontal ductlsee Figure 1). ®*hj£%flip?ratad 1nt0 the
metered with AcHson gravimetric feeders. The sorbent may oe
29-3
-------
primary air line far burner Injection, or Into a separate transport a1rstrea*i far
Injection at other locations.
As shown in Figure 1, an isothermal residence chamber has been Installed in the
back-end of the system vrfiere the gas temperature is typically about 149aC (3GQ*F).
This chamber provides a gas residence time of about 1 sec in which the conditions
are nearly isothermal. This simulates the t1me-tamperature Interval between the air
heater and the ESP 1n a power plant. The simulation of this part of the ash thermal
history is critical to the uptake of S03 and Its effect on resistivity. The sam-
pling port for the particle size and resistivity measurements is located just down-
stream from the isothermal residence chamber. The effect of SO3 conditioning may be
studied using a conditioning system that has been installed upstream of the Isother-
mal residence chamber. This system consists of an electrically heated catalytic
reactor and injection line. Sulfur dioxide is metered from a gas cylinder and
passes through the catalytic reactor vrfiere ft is converted to S03. The resulting
SO3 is then Injected into the flue gas at a point upstream of the residence chamber
to allow adequate mixing and sufficient time for uptake on the particulate.
Sampling Equipment and Procedures
Particle Size Distribution Measurements. Particle size distribution measurements
were made using a combination of Modified Brink Model BMS-U Cascade Impactors, a
Thermo-Systems Model 3030 Electrical Aerosol Size Analyzer, and a Climet Model
C1-208C Optical Particle Counter. The general procedure for the use of cascade
Impactors has been described by Harris (6). The Brink impactors used in this study
were equipped with a precutter cyclone, six impactor stages, and a backup filter.
Lightweight glass fiber substrates were used on the impaction stages. The impactor
was inserted into the flue gas stream and allowed to reach gas temperature before
beginning the impactor sampling. The sampling rate was adjusted to sample Isoklnet-
ically with the centerllne velocity at the resistivity port. Each set of impactor
measurements (with and without sorbent) consisted of 12 impactor runs, 2 of which
were blank runs. The blank runs were performed with a filter ahead of the impactor,
so that any substrate weight changes caused by flue gas-substrate interaction could
be quantified and taken into account. The blank corrections were generally quite
small compared to the particulate mass collected on the impaction stages. The raw
Impactor data were reduced using the Cascade Impactor Data Reduction System (CIQRS)
developed by Johnson et al. (9,10). This yields size distribution data for parti-
cles 1n the range of 0.5 to 10 urn.
For finer particles in the range of 0.01 to 0.5 um, 1t was necessary to use an elec-
trical aerosol size analyzer (EASA) in combination with an optical particle counter
(OPC). The operating principles of these Instruments have been reviewed by Uu and
Pu1 (11) and Liu et al. (12). These instruments are designed to handle relatively
low particulate concentratlons at room temperature. Therefore, the sample to be
analyzed must be extracted from the flue gas, cooled, and diluted prior to examina-
tion in the EASA or OPC. The sample extraction and dilution system that was used 1n
this study has been described by Felix et al. (13). Extensive testing has been done
to verify that secondary aerosols are not produced 1n the sample extraction and
dilution system. The EASA and OPC data were obtained concurrently with the Impactor
data. All three data sets were combined to form a complete size distribution over
the range of 0.01 to 10 um, with and without sorbent injection.
In Situ Resistivity and SO, Measurements. A modified version of the SRI point-plane
resistivity probe was used to obtain in situ resistivity data. The in situ resis-
tivity test methods have been described by Nichols and Banks (14). The resistivity
was calculated from the voltage drop across the precipitated dust layer and the
electrical current density through the layer immediately prior to electrical break-
down.
29-4
-------
Measurements of the gas-phase S03 concentrations were made by the modified
control1ed-condensation technique described by Cheney and Homolya (15). A quartz
wool plug was used to remove particulate ahead of the S03 condenser. The quartz
wool plug was maintained at 274*C (525#F) to prevent uptake of SO3 on the particu-
late collected on the plug. This has been found to be satisfactory in sampling
ash-laden flue gas from coal-fired boilers (15). However, the loss of S03 to the
particulate may be a problem in the presence of reactive sorbent. Therefore, the
S03 data reported here must be regarded as lower limits on the levels actually pres-
ent in the flue gas.
Laboratory Resistivity Measurements. Samples of fly ash alone and mixtures of fly
ash in combination with reacted sorbent were taken from the cavity of the 1n situ
resistivity probe for laboratory analysis. The samples were placed 1n ASME PTC-28
test cells and heated to 450°C (842*F) 1n air containing 8* ty volume water vapor.
The oven was then turned off and the resistivity was determined as a function of
descending temperature over the range of 450 to 85°C (842 to 185°F). These measure-
ments wire made 1n accordance with IEEE Standard 548-1981.
For measurements made with SO, in the environment, the samples were placed in a
radial resistivity test cell designed by Blckelhaupt (16). The cell was placed in
an oven and maintained at a constant temperature near 150*C (302*F). A1r containing
8% moisture and a known level of S03 was passed over the test cell, and the resis-
tivity was monitored until an equilibrium condition was attained. The result
obtained by this method represents the minimum resistivity value that can be
attained 1n flue gas containing the prescribed level of S03. The in situ resistiv-
ity will be higher than the laboratory value 1f the dynamic Interaction of the
particulate and S03 in the flue gas does not approach the equilibrium situation.
RESULTS ANO DISCUSSION
Effect of Sorbent Injection on S0« Capture
The effect of sorbent injection on particulate properties 1s rtlated to the extent
of conversion of the calcined sorbent to a sulfated material. The conversion, or
utilization, of the sorbent is a function of a number of process variables Includ-
ing: sorbent type, chemical composition, surface area, particle size, sorbent
injection location, Injection rate (Ca/S ratio), mixing, and furnace conditions.
Since a detailed particulate characterization program cannot be performed with all
possible process options, sorbents and Injection modes have been chosen for study
which have a significant probability of practical application. Most of the data
obtained thus far 1n the particulate program have been with Vicron limestone as the
sorbent, although data with a conmerclal grade of calcium hydroxide, known as Long-
view hydrated 11me, are now being obtained because of the greater effectiveness of
this hydrated lime in reacting with S02. Characteristics of Vicron and Longvlew
sorbents are given 1n Table 2.
Figure 2 shows the percentage SO? removal obtained in the SRI pilot plant by injec-
tion at 5-3 at a temperature of approximately 1316*C (2400*F) with Vicron and with
two hydrated Hmes. These data were obtained with a 2.3% sulfur Indiana bituminous
coal. The proximate and ultimate analysts of the coal an given 1n Table 3. The
same coal was used for the particulate studies. Although the hydrated limes are
more effective than limestone, they are also more expensive on a cost-per-un'it-
weight basis. Southern Research Institute and the Oravo Lima Company are beginning
a project with the objective of developing cost-effective sorbents from limestones.
Precalcination, hydration, and the use of promoters to tnhance reactivity are
approaches which will be evaluated during the course of this project.
29-5
-------
Effect of Sorbent Injection on In Situ Resistivity
Since any furnace injection process will produce mixtures of fly ash and partially
sulfated calcine, results obtained with Vicron limestone are expected to be at least
qualitatively Indicative of the effects of LIMB on ash collectabllity. Therefore,
laboratory and in situ resistivity Measurements have been made to determine the
effects of Vicron Injection on resistivity and to evaluate the response of the ash
sorbent mixtures to S03 conditioning and moisture conditioning.
Figure 3 summarizes the 1n situ resistivity data obtained with the 2.3% sulfur
Indiana bituminous coal with and without burner injection of Vicron limestone at a
nominal caldum-to-sulfur ratio of 2:1. Table 4 gives the chemical compositions of
the fly ash and the ash/sorbent mixture produced with the Indiana coal with and
without Vicron injection. No S03 was added to the flue gas. The S03 concentration
variations shown without Vicron addition were obtained by varying the flue gas cool-
ing regime using the water-cooled heat exchangers ahead of the resistivity probe.
The lowest level of S03 corresponded to the greatest amount of water cooling. For
the measurements made with Vicron addition, the S03 level was adjusted by varying
the amount of excess air used in the furnace. An S03 level of <0.2 ppm corresponded
to 2.2% 02 in the flue gas, and an S03 level of 7.9 ppm corresponded to 6.5% 02 in
the flue gas.
Several observations can be made from an examination of Figure 3:
• The in situ data at the lower flue gas temperature without Vicron
approach the equilibrium resistivity values predicted by Blckelhaupt
(17).
• If no residual S03 1s present, ash/sorbent mixtures exhibit in situ
resistivities of ~10u ohm cm.
• Small residual S03 concentrations have a dramatic effect on the
resistivity of ash/sorbent mixtures. The presence of the sorbent
appears to increase the response of the fly ash to a given S03 con-
centration at relatively high flue gas temperatures (~199°C/390°F).
• Resistivity values in the range for good precipitator operation can
be achieved for Vicron/ash mixtures 1n the presence of relatively low
residual S03 concentrations, when the source of S03 1s oxidation of
naturally occurring S02.
Resistivity measurements have also been made with artificially added S03 for condi-
tions that result in negligible naturally occurrl-ng S03. These measurements Indi-
cate that resistivity attenuation can be achieved with the Injection of 30 to 40 ppm
of S03, but that the residual levels of S03 are sensitive to the residence time 1n
the flue gas and the Injection temperature, as well as the concentration of injected
S03. Additional experiments are planned with varying Injection levels, residence
times, and measurement temperatures.
In situ measurements with S03 injection for conditioning with hydrated Ume sorbent
have produced ambiguous results. In situ resistivity values of 3 to 7 x 10u ohm cm
in the presence of 1.5 to 2 ppm of residual S0« have been observed at temperatures
of 132 to 143°C (270 to 290*F) when hydrated lime 1s injected near the furnace exit.
Other data indicate that resistivity values of 3 to 7 x 10l° ohm cm 1n the same
temperature range are obtained 1n the presence of 0.5 to 1.2 ppm residual S03 when
the hydrate is injected nearer the flame zone. Additional work is planned to define
the dynamic relationship between resistivity measurement temperature, injection
location for the sorbent, injected levels of SO,, resistivity, and residual S03
levels for both limestone and hydrated lime. Tne preliminary data suggest that
29-6
-------
hydrated lime Injected near the furnace exit may produce a particulate mixture
difficult to condition because of the high reactivity of the unsulfated calcine
which remains when the mixture reaches the resistivity port.
A small wire-plate precipitator with conventional electrode geometry has been
installed in the pilot plant. Voltage-current relationships obtained with this
device will be used to augment the resistivity data 1n evaluating the effectiveness
of SO3 conditioning. Water conditioning at reduced flue gas temperatures, and other
potential conditioning agents, will also be evaluated.
Effect of Sorbent Injection on Laboratory Resistivity
Laboratory resistivity measurements were performed for Indiana fly ash from furnace
tests with and without Vlcron addition. These measurements were conducted with
standard procedures developed by Blckelhaupt (16). Water vapor concentrations were
varied between 7.9 and 18.7* by volume 1n air, and the sulfur trioxide concentration
was either zero or approximately 5 ppm. For the tests Involving sulfur trloxide,
the ash layer and the environment were assumed to be 1n equilibrium when the
resistivity value decreased at a rate of less than 30% 1n a 24-hr period. Figure 4
summarizes results obtained from these experiments. All ash samples were collected
in the combustion system resistivity probe. The chemical analyses of the ash
samples used 1n these experiments were given in Table 4. Several observations can
be made from these data:
• The presence of the partially sulfated sorbent increased the response
of the ash resistivity to a given SO3 concentration. This confirms
the trend shown by the 1n situ data in Figure 3. Five ppm of S03 1n
the environment decreased the resistivity at 149*C (300°F) by over 3
orders of magnitude.
• The ash/sorbent mixture responds to water conditioning, but 1t
appears that temperatures lower than 93#C (200°F) would be required
to lower resistivity into the low 1010 ohm cm range with water vapor
concentrations of 16 to 19* by volume if no S03 is present.
• Resistivities of -2 x 1012 ohm cm are measured for ash sorbent mix-
tures at hot-side ESP operating temperatures of 300°C (572*F).
Laboratory resistivity measurements have been performed with ash/sorbent mixtures
produced with injection of hydrated lime downstream of the burner with the Indiana
coal as fuel. Results from these experiments are similar to those shown 1n
Figure 4,
Effect of Sorbent Injection on the P»r*icle Size Distribution
Particle size distribution measurements have kw" J™*2200*F)^Mea-^
the burner ami downstream from the burner at approxlmateiyizu* \ tempera-
suramnts Mr. .1.0 «da with hydrattdll""
tura. Thi ultraflne sy.tn (EASA and OPC) drtTtStt Sown"!
und.r condition which aUowad acquisition of tha vlcron has no
Fljurn 5 and S. F19ur» 5 lllustratas that for, Injtctlw »• vieron ms
effect on the concentration of ultrafine particles with djwwt* concentration
tha fin. partlel. dlawtar ran*, of 0.1 to 0.6 u«. *«•»•<¦. »•
was Incraasad by a factor of 3 to * with burnar l"^™- "K? « incSS.ia
that downstream injection eliminates the fine h«.u. aDart under the
obsarvad with burnar miction, su99Mt1nS that tha llwstona braaM apart unoar^^
intense calcination conditions encountered 1nthe flame zone. Injec
29-7
-------
lime at the downstream Injection point produced results Identical to those observed
with downstream Injection of Vlcron 1n the ultraflne size range.
PREDICTED EFFECT ON ESP PERFORMANCE
Since downstream Injection of limestone generally produces superior S02 capture
compared to burner Injection, without the problem of excessive fine particle produc-
tion, this mode of sorbent Injection was chosen for precipitator performance simula-
tions using the EPA/SRI model (18). The model simulations were performed to evalu-
ate the effects of sorbent addition on ESP performance. The potential effects of
ESP design modification and S03 conditioning for counteracting the effects of
sorbent Injection were also Investigated.
A particle size distribution was constructed from impactor and ultraflne data with
downstream Injection of Vlcron limestone. The baseline and with-sorbent distribu-
tions art presented in Figure 7, on a basis of cumulative mass per unit volume of
gas as a function of particle diameter. Electrical data for the simulations were
defined from the following assumptions:
• The fly ash resistivity without sorbent was 2 x 1010 ohm cm.
« Vlcron addition produced 2 x 1012 ohm cm dust without conditioning.
• SO, conditioning restored resistivity of the ash/sorbent mixture to
2 x 1010 ohm cm.
The objective of these simulations was to examine the predicted precipitator perfor-
mance for existing and modified precipitators in a specific collection area range
likely to be encountered In a retrofit application of LIMB technology. Electrode
modifications were simulated which consisted of adding a precharglng section with
conventional electrode geometry, followed by three collecting sections with 0.95-cm
(3/8-1n«) diameter wires with 22.9-cm (9-1n.) plate spacing. These modifications
are Intended to Increase the collection efficiency within the constraints Imposed by
the existing precipitator Installation. The ESP mechanical parameters are provided
in Table 5, and the electrical parameters are summarized in Table 6. The parameters
assumed for the retrofit electrode modifications are given in Table 7. The particle
charge values calculated for the precharger exit are similar to those expected at
the exit of a cold-pipe precharger, which has been developed by Denver Research
Institute (19).
Figure 8 presents the results of the simulations of coll«ct1on efficiency for the
Indicated cases, and Figure 9 provides the ESP performance In terms of nanograms of
outlet mass loading per Joule, or pounds of outlet mass loading per 10* Btu. These
graphs show that, as expected, the high resistivity and increased mass loading asso-
ciated with III® sorbent addition produce unacceptably high emissions. If electri-
cal conditions are restored by S03 conditioning, the precipitator collection effi-
ciency is increased over the baseline case (as a result of space charge, and the
higher concentration of larger particles resulting from sorbent Injection), but the
outlet emissions are still approximately 45% greater than the baseline case. How-
ever, the two-stage retrofit geometry further Increases efficiency and results 1n
predicted outlet mass loadings which closely approach the baseline case.
These simulations must be regarded as preliminary, and they will be repeated when
experimental electrical data are available with LIMB-generated particulate for the
assumed electrode geometry. Additional simulations are planned for hydrate Injec-
tion when more definitive in situ resistivity data and particle size data are avail-
able for this process mode.
29-8
-------
CONCLUSIONS
Furnace injection of calcium-containing sorbents produces high resistivity ash/
sorbent mixtures in the absence of small residual concentrations of sulfur trioxlde.
With limestone as the sorbent, resistivity can be reduced to acceptable levels with
S03 conditioning. If hydrated Hme 1s the sorbent, the in situ response of resis-
tivity to-SO3 is dependent upon the location of sorbent Injection 1n the furnace.
With both limestone and hydrated 11me as sorbents, the resistivity of the resulting
ash/sorbent mixture 1s reduced to less than 1010 ohm cm at equilibrium with 5 ppm
S03 and 8% water vapor at 149*C (300°F). The resistivity of ash/sorbent mixtures
produced with limestone injection 1s also reduced by Increasing water vapor concen-
trations. Additional data are required to define the relationship between in situ
resistivity, Injected S03, and residual S03 levels.
Burner injection of Vicron limestone produces large Increases in submlcron particle
concentrations 1n the 0.1- to 0.6-um diameter range compared with coal firing with-
out sorbent Injection. Injection of either Vicron limestone or hydrated lime near
the furnace exit did not produce an increase in fine particle concentrations, as
determined by an ultraflne sampling system. Downstream injection of Vicron produced
a cumulative mass loading at 10-um diameter approximately 60% greater than the base-
line ease at a nominal calcium-to-sulfur ratio of 2 to 1.
Simulations of precipitator performance indicate that outlet emissions of less than
43 ng/j (0.1 lb/10® Btu) are achievable with sorbent Injection at a specific collec-
tion area of 59 m2/m3/sec (300 ft2/1000 ft3/m1n) 1f conditioning restores electrical
conditions to the values obtained prior to sorbent addition. Modifications of elec-
trode geometry( when combined with a successful conditioning process, have the
potential of significantly increasing performance over the values predicted for
conventional ESP designs.
ACKNOWLEDGMENTS
The authors would like to thank S. H. MW1m* Marchant, Jr., for
vision of the Impactor sampling and in situ res 1 stiv1 ,J J J|d assls-
Beittel for his conscientious operation of the pilot c^ustionfacimy andassis
tance in experimental planning. The authors are also Indebted to John Hester wno
performed all of the laboratory resistivity measurements.
This work was funded under EPA Cooperative Agreement No. CR81QQ12.
REFERENCES
B*^rchgessner, "Laboratory-Seale Production and Characterization of High-
Surface Area Sorbents," This Symposium, Session II, Paper 2-0.
2. R. H. Borgwardt, U.S. Environmental Protection Agency, IERL, Research Triangle
Park, NC, Personal Comnunlcation, 1984
3* R* Borgwardt, N. F. Roache, and K. R. Bruce, "Surface Area of Calcium* Oxide
and Kinetics of Calcium Sulfide Formation," Environ. Prog.. 3, 129 (1984).
4. R. Payne, p. l. Case, M. P. Heap, and 0. W. Pershfng, "The Use of Dry Sorbents
to Reduce Sulfur Oxide Emissions from Pulverized Coal Flames Under Low-NOx
Planted at the 1982 Joint Symposium on Stationary Combustion
N0X Control, Dallas, TX, November 1-4, 1982.
29-9
-------
5. J. T. Kelly, E. K. Chu, S. Ohnrfne, and R. J. Martin, "low-NOx Tangential
System S0X Control Through Sorbent Injection," Ibid.
6. W. J. Barrett, J. P. Gooch, R. S. OahHn, R. M. Riggln, and H. 0. Roth, "Plan-
ning Studies for Measurement of Chemical Emissions 1n Stack Gases of Coa1-F1red
Power Plants," Final Report, EPRI EA-2892, Electric Power Research Institute,
Palo.Alto, CA, March 1983.
7. J. H. Abbott, J. P. Gooch, and J. 0. Kllgroe, "Effects of Furnace Injection of
Sorbent for S02 Control on Electrostatic Precipitator Technology and Require-
ments," to be presented at the Second International Conference on Electrostatic
Precipitation, Kyoto, Japan, November 12-14, 1984.
8. 0- B. Harris, "Procedures for Cascade Impactor Calibration and Operation 1n
Process Streams," EPA-600/2-77-004 (NTIS PB 263623), U.S. Environmental
Protection Agency, Research Triangle Park, NC, January 1977.
9. J. U. Johnson, G. I. Clinard, L. G. Felix, and J. D. McCain, "A Computer-Based
Cascade Impactor Oata Reduction System," EPA-600/7-78-042 (NTIS PB 285433),
U.S. Environmental Protection Agency, Research Triangle Park, NC, March 1978.
10. J. W. Johnson, 8. E. Pyle, and W. B. Smith, "Extending Precision 1n a Computer-
Based Cascade Impactor Oata Reduction System," 1n Proceedings ofthe Second
Symposium on Advances in Particulate Sampling and Measurement. EPA-600/9-80-004
(NTIS P880-187487), U.S. Environmental Protection Agency, Research Triangle
Park, NC, January 1980, pp. 146-166.
11. B. Y. H. I1u and D. Y. H. Pui, "On the Performance of the Electrical Aerosol
Size Analyzer," J. Aerosol Sci.. 6, 149-164 (1975).
12. 8. Y. H. Liu, R. N. Berglund, and J. K. Agarwal, "Experimental Studies of Opti-
cal Particle Counters," Atrnos. Environ.. 8, 717-732 (1974).
13. I. G. Felix, R. I. Merritt, J. 0. McCain, and J. W. Ragland, "Sampling and
Dilution System Oesign for Measurement of Submicron Particle Size and Concen-
tration 1n Stack Emission Aerosols," TS1 Quarterly. 7, October-Oecember, 1981.
14. G. B. Nichols and S. M. Banks, "Test Methods and Apparatus for Conducting
Resistivity Measurements," Final Report, EPA Contract No. 68-02-1083, U.S.
Environmental Protection Agency, Research Triangle Park, NC, September 1977.
15. J. t. Cheney and J. 8. Homolya, "Sampling Parameters for Sulfate Measurement
and Characterization," Environ. Sci. Technol.. 13, 584-588 (1979).
16. R. E. Blckelhaupt, "Measurement of Fly Ash Resistivity Using Simulated Flue Gas
Environments," EPA-600/7-78-035 (NTIS PB 278758), U.S. Environmental Protection
Agency, Research Triangle Park, NC, March 1978.
17. R. E. Blckelhaupt, "A Technique for Predicting Fly Ash Resistivity," EPA-600/7-
79-204 (NTIS PB80-102379), U.S. Environmental Protection Agency, Research
Triangle Park, NC, August 1979.
18. M. G. Faulkner and J. I. Oubard, "A Mathematical Model of Electrostatic Precip-
itation (Revision 3): Volumes I and II," EPA-600/7-84-069a and -069b (NTIS
PB84-212679 and -212687), U.S. Environmental Protection Agency, IERt, Research
Triangle Park, NC, June 1984.
29-10
-------
M. D. Durham, G. A. Rinard, 0. E. Rugg, T. Carney, and L. E. Sparks, "Pilot
Plant Evaluation of the Cooled Electrode Precharger on a Utility Flue Gas
Slipstream with High Resistivity Fly Ash," presented at the 77th Annual Meeting
of the Air Pollut. Contr. Assoc., San Francisco, CA, June 24-29, 1984.
29-11
-------
OVERHEAD CRANE
ADJUSTABLE JOINT
TO PERMIT REASSEMBLY
AS AN UP-f IREO UNIT
HEAT EXCHANGER
COOLER
SECONOAflY AND TERTIARY A
MAY BE PIPED TO SEVERAL
ALTERNATE INPUT PORTS
COAL i
FEED *
1
BURNER
N
to
I
•-»
N
TOTE
IE
DOWN-FIREO
FURNACE
WORK PLATFORM
_ _ . _ V
ELECTRIC
HEATER
GB
WEIGH
FEEOER
VENTURI
MIXER
PRIMARY
AIR ft COAL
CONTROL
PANEL
FORCEO
DRAFT
BLOWER
spE33jECT
PROBE DOORS VI
(FOR FOUUNG It CORROSIONI
VENTURI
FLOWMETER
=¥=
ASH TRAPS
17 PLACES)
TO BAG
COLLECTOR
ISOTHERMAL
RESIDENCE TIME
CHAMBER
ACCESS PORTS
FOR INSTRUMENTS
RESISTIVITY MEASUREMENT
LOCATION
DOTTED LINES
INDICATE WATER
JACKETS
Figure f. Pilot plant used for particulate characterization studies.
-------
100
Ui
ce
S
I"
z
ui
u
ec
g
ALL SORBCNTS INJSCTCO 0 M
O VICRON UMIfTONC
O LONGVIBW HYDRATt
O CORSON PRISSURI HYDRATI
Ci/tiMW SORBKNT/MW (UCO3
Figun 2 Comparison of various sorbants on § mats basis.
0
29-13
-------
TEMFtRATURi,®*
183 234 291 360 441 541 688 828
1012
10"
S
I
>
j-
1 1010
5
10®
10«
84 112 144 182 227 283 382 441
TEMPERATURE, °C ,„M,
Figura 1 Effaet of burner injection of Vicron on tha in situ rasistivity obtainad with
23% sulfur Indian* bituminous coal.
PREDICTED
WITHOUT VICROW
IN SITU
WITH VICROW
<0.2 ppm SO3
—-3.2 ppm $03
^4.1
SO3
7.9 ppm SO3
5.9 ppm SO3
IN SITU
WITHOUT
VICRON
29-14
-------
TEMPERATURE. ®F
N
r
H
o*
¦¦¦¦¦¦¦¦¦mil
w
£ lo'V
SO3, ppm E, kV/cm
O WITH VICRON 7.9
WITHOUT VICRON 7.9
O WITH VICRON It. 7
WITHOUT VICRON 11.7
O WITH VICRON 7.9
~ WITHOUT VICRON 7 9
MM-Ml
U Is.* M (4
200
TEMPERATURE, *C
Figure 4. Comparison of resistivities with and without Vicron addition - Indiana 2.3% sulfur
bituminous coal.
-------
10®
0 BA4SUNC
o V1CRON # BURNCR
10*1
i t i i i i i I
J »ilt
«r2
10*1
OlAMiTSn, jura
Mfi
iPii-r»
Pigura 5. Effaez of turner injaction of Vicrort on tha panic!a siza distribution obtained with
23 % su/fur bituminous coal.
29-16
-------
"I
1
a
§
O VtCRON • BURNER
O VICRON • S-4
Figurt 6. Effect of Vieron injtction stS-4 on th» ptrtieh tin distribution comptrnd to
th* rfitt of bumf injection.
2f-X7
-------
WITH VICRON.
INJECTED
OOWNSTREAM
(®S4|
BAS8LJNE (WITHOUT VICRON)
1 x 10° Btu/hr
9.2%
3J%
1.58
3090 ppm
33%
LOAO
COAL ASH CONTENT
FLUE OAS 02 CONTENT
Ca/S MOLE RATIO
8AS8UNE S02 LEVEL
SULFUR
RE
PARTICLE DIAMETER, um
Figura 7. Comparison of cumulative matt loading curvas for Indiana fly ath with
and without Vlcron sorbant addad downstraam.
29-18
-------
20
"r
&
«<
§ .
•9.4
»•
88.8
100
30
SCA,m2/m3/MC
40 SO
60
1S0
10
A
~
COAL AND UMCSTONf
-------
20
30
SCA,m2/m3/«M
40 SO
60
0.S
a 0.4
%
I
9*
-------
Tabic l. System Design Temperatures
and Gas Velocities
Average
gas temp,
*C ( F)
Furnace
Simulated superheater/reheater
Refractory-lined water jacket
A1r preheater
Heat exchanger No. 2
Air-cooled loops
Water-cooled loops
1621-1149
1149-943
943-829
829-477
477-313
313-183
183-127
(2950-2100)
(2100-1730)
(1730-1525)
(1525-890)
(890-595
(595-362)
(362-260)
Average
velocity,
m/sec (ft/sec)
1.3 ( 4.2)
7.0 (23)
(66)
(35)
(31)
(60)
20.1
10.7
9.4
18.3
16.8 (55)
Table 2. Properties of Vlcron limestone and
Longview Hydrated Hmea
Vlcron Lonovlew
Ca as CaCO,, wt % 98.7 . —b
Ca as Ca(0H)2t wt X —0 95.2
Surface area, n^/g 0*82 16.6
Mass median diameter
by sedimentation, um 15 2.3
a. Prior to furnace injection.
b. Not applicable.
29-21
-------
Table 3. Proximate and Ultimate Analyses
of Indiana 2.3% Sulfur Bituminous Coal
Proximate Wt percent
Molsture 8.92
Ash 7.56
Volatile matter 34.23
Fixed carbon 49.29
Btu/lb 12,146
Sulfur 2.29
Ultimate Wt percent
Moisture 8.92
Carbon 68.02
Hydrogen 4,42
Nitrogen 0.97
Chlorine 0.43
Sulfur 2.29
Ash 7.56
Oxygen4 7.39
a. Oxygen determined by difference.
Table 4. Chemical Analyses of Fly Ash and Fly Ash/Sorbent Mixture
Produced from Indiana Coal and Vicron Limestone
Without Vicron, With Vicron,
weight percent wight percent
11,0 0.03 0.02
Na20 0.08 0.07
K20 0.59 0.35
MgO 0.19 0.44
CaO 0.28 39.4
Fe203 25.3 12.7
A1203 26.1 13.8
S102 44.5 25.1
T102 0.91 0.46
P20« 0.07 0.03
S03 0.54 7.7
29-22
-------
Table 5. Precipitator Mechanical Parameters
Three electrical sections in the direction of gas flow
Three baffled sections 1n the direction of gas flow
Gas sneakage per baffled section • 10%
Weighted wires in 22.9-cm (9-in.) ducts
Mean gas velocity • 1.52 m/sec (5.0 ft/sec)
Relative standard deviation of mean gas velocity ¦ 0.Z5
Gas flow rate « 165 in3/sec (350,000 ft3/min)
Plate area per section • 2,434 m2 (26,200 ft2)
Specific collection area « 44.3 m2/m3/sec (225 ft2/1000 ft3/min)
Table 6. Precipitator Electrical Parameters
• High-sulfur bituminous coal
Ash resistivity 2 x 10l° ohm cm at 149#C (300#F)
Section kV nA/cm2
—i— is Jwm
2 42 29
3 40 30
• Coal and limestone
Ash resistivity 2 x 1012 ohm cm at 149*C (300*F)
Section VcV nA/cm2
—I— U TCT"
2 29 1.2
3 30 2.5
• Coal and limestone, with S03 conditioning
Ash resistivity 2 x 1010 ohm cm at 149*C (3Q0*F)
Table 7. Precipitator Retrofit Parameters
• Flue gas conditioning with S03
Ash resistivity 2 x 1010 ohm cm at 149*C (300*F)
• One precharging section, 0.61 m (2 ft) long,
with 0.254 cm (0.1 1n.) wires in 22.9 an (9 1n.) ducts
Section: 45 kV, and 50 nA/cm2
• Three collection sections,
with 0.95 cm (3/8 1n.) wires 1n 22.9 cm (9 in.) ducts
Each section: 50 kV, and 10 nA/cm2
29-23
-------
EVALUATION OF TEMPERATURE HISTORIES IN THE RADIANT AND
CONVECTIVE ZONES OF A PULYERIZED COAL-FIRED STEAM GENERATOR
B. M. Cetegen, J. L. Reese, K. Kurucz and W. R1enter
Energy and Environmental Research Corporation
18 Mason Street, Irvine, CA 92718
and
D. G. Lacnapelle
U.S. Environmental Protection Agency
Industrial Environmental Researcn Laboratory
Research Triangle Park, NC 27711
ABSTRACT
Tne effectiveness of 1n-sltu desul fun ration by direct injection of calcium-
based dry sorbents 1s sensitive to tne thermal environment m boilers. More
specifically, the temperature mstorles of gases and sorbent particles in tne
radiant zone and tfte mgn-temperature convective pass sections play an important
role in tne sulfur capture process. Estimation of temperature mstorles
requires a detailed description of tne furnace neat transfer and flow field.
Tnu paper discusses tne detailed field measurements of temperatures and
velocities m « wall-fired utility ooller. Tne temperature measurements at full
boiler load Indicate tnat an assumed sulfation temperature window (800
-------
tins process, two main seeps are Involved. These are thermal decomposition,
often referred to as calcinat:on(2,3) in tne form
CaC03 (solid) — CaO (solid) + CQ^ (gas), (1)
and sulfation^ wnicn overall can be represented by
SO2 (gas) + CaO (solid) + 1/2 O2 (9»s) -»CaS04 (solid) (2)
Tne CaS04 particulate can oe removed wltn the existing particulate removal
systems sucn as cyclones, Daghouses,and electrostatic precipitators. This
technology, often referred to as LIMB (for Limestone Injection with Multistage
Burners), is intended primarily as a retrofit technology. The two steps of the
process, calcination and sulfation, have been shown to be highly sensitive to
the time-temperature profiles experienced by the sorbent.^) For instance, the
sorbent reactivity is strongly dependent on the peak temperature experienced by
tne sorbent particles, and tne sulfation kinetics has been found, from bencn-
scale studies'6', to be most favoraole 1n tne overall temperature zones between
80Q and 120Q°C. Therefore, effective implementation of tne process in boilers
requires knowledge of tne temperature field and tne temperature histories 1n a
boiler to maximize sorbent utilization. This can be acnleved by detailed
experimental characterization of thermal environment and flow field in field
operating boilers. However, such an approach would be difficult, time consuming
and expensive. Alternatively, a predictive methodology, tested against field
data for representatlve sample boilers of most common types, would provide a
more attractive solution. This predict!v« methodology could be used to study the
thermal environments and flow fields In many different boilers to assess tne
potential for LI^ application. Currently, an EPA funded program is underway to
study tne adequacy of a predictive approach for evaluation of thermal-and flow
characteristics in boilers. The main objectives of tnls stud/ are *0:
e Review tne available furnace thermal prediction methodologies and
flow models and to select the prediction method most suitable for
evaluation of temperature and flow fields in boilers").
e Conduct field tests at tne two most common type boilers (wall-
fired and tangentlally fired) and compare the test data with tne
predictions of the selected methodology.
• Determine the adequacy and accuracy of such an approach for future
predlctlve evaluations.
The review of predictive methodologies and the field tests at two boilers nave
been completed. These boilers are the wall-fired unit of Ouck Creek Power
Station near Canton, Illinois, owned and operated by Central Illinois Llgnt
Company, and tne tangentlally fired boiler unit 5 of Conesville Generating
Station in Conesville, Qnio, owned and operated by American Electric Power
Company. The detailed results of tftt field tests will be published in separate
EPA reports. This paper summarizes tne field tests conducted at tne wall-fired
unit.
30-2
-------
EXPERIMENTAL
Test Boiler
The field tests reported here were conducted at the *J^"22*b^iiJrt«'*^ront-
Creek Power Station located near Canton, Illinois, p1* r 1$ #nown m Figure
wall fired Riley unit. The general arrangement of tne boiler 1s shown in Mgure
1. Tne boiler is coupled with a generator producing 420
at full boiler load. The boiler characteristics *[*• 6urntr area. Tne 24
furnace 1s 11.6m (38ft) deep and l6*8m (55ft) wite in - fuei w xsw
Burners, arranged in 4 horizontal rows of 6 burners * MCh «u00iving
furnace. The coal is pulverized in 3 Riley Df^ toiler w1tn superneat
8 burners. The steam generator 1s a natural «3 cnn k«/nr (3xio6 10/
and reheat steam cyclei. It 1s designedUtilled at
hr) steam at 178 atm (2600 pslg) and ^ Jrrvi^urners^)
this unit are low-NO* Controlled Combustion Venturl (CCV) burners •
The coal fired at tnis unit 1s received from theJlS* ana 1 ysis*and heating8value
long term contract. A typical proxiiMw and uUimate ana y ^ 201
of tne coal are listed m Table 2. These values aia no* c CQal> Tne
during the test period. The coal 1is a nig J ^rouan 200 mesh screens (74
coal fineness varied between 73 and 85* by ma5S w »
micron mean size).
Test Objectives and Operating Conditions
mm*. ncMturv test data on the furnace
The primary test objective was to P™/1*?^iBMrison with m predictions of a
thermal environment and flow field JL. wt location of tne sulfation
furnace heat transfer/flow model. In add • ZQne caR M evaluated from
temperature window and tne res 1 dence tlmes temperature and velocity
tne test data. This paper reports tne furnace J" te7^tn the low load
measurements made at tne full 00 ^Jnnf'the boll«f ** also presented. At
(approximately 60* of full load) operation^ ^ 0f six burners and tne
60S load, one of tne pulverizers suppymfl This 1s the base load at
two middle burners on tne next row was out or ^ Tests conducted at this
wnicn the unit operates during low 1lir thermal environment dueto
load allow comparisons of tne f1ring rate. The temperature
the different firing configuration and the planes tnrougnout tne radiant
measurements included traversesjwde in va P^ #J since tne region of
furnace and tne upper portion of vmj:^^2reTdoSn to 800°C. Someoftne
interest for tne UHB process extends to tey« 3 for 100% and 60* loads,
monitored input/output parameters are listed
n»v4Afi flf aacn test condition
Due to tne large number of raeasuremen» careful V^^wermal
required several days of testing. This ,,1^na cycles) in tne thermal
tne long-time transients (daily and betw«in the boiler input
environment because of tne soot Jlf*!£5ed on £» measurements of
conditions. A preliminary evaluation, based on ** ¥tCt1vt WCk pass, reveaUd
furnace exit temperatures and ca|,cul"1®JL 2low1nfl were small. In f*ct» ***?J
that tne temperature variations due wsoot&lo fl ^ wtre clean, with only
observed during the tests Wat tne r#^4J*o*uC?QWl0g took place 1« tne radiant
*»» po.«,y Jpum. Tn.r.for. no „y lO-lS* o».r m
furnace. In the back pass, tne flue gas temperawrw
30-3
-------
soot blowing cycle. Tnese fluctuations were small and did not justify tne
coordination of tne measurements w1tn tne soot blowing cycle. Tne variations m
tne input parameters were also kept witMn prespeclfled limits.
Measurement Techniques And Locations
Gas temperatures were measured witn conventional water-cooled suction pyrometer
probes. A few velocity measurements were also made witn two-nole impact probes
to determine the magnitude and direction of tne velocity vector 1n tne plane
perpendicular to tne probe axis. During tne tests, otner measurements included
local and economizer outlet species concentrations, radiative neat flux
measurements and particulate size distributions. Tne test equipment and
measurement procedures are described in detail (9).
It snould be pointed out tnat 1n-furnace temperature and velocity measurements
are difficult in a large coal-fired boiler since tne furnace environment is
extremely nostlle and sampling at distances up to Sm (26ft) into tne furnace is
generally required. Tne accessible locations adequate for probe insertion are
also major constraints in making 1n-furnace measurements. In general, all
boilers are equipped witn furnace observation ports located near tne furnace
corners. Sometimes even tnese locations are obstructed, by tne equipment
outside tne boiler, for adequate insertion deptns into tne furnace witn probes.
All tnese problems and constraints required sampling witn several probes witn
lengtns varying from 3m (10ft) to 7.6m (25ft). In areas of major Interest, some
wal 1 soot blowers were removed for additional access into tne furnace. Because
of tne interest in tne upper convective back pass, sampling ports were also
installed in tnis area. Tne following section mgnHgnts some of tne results
obtained during tnese field tests.
RESULTS
Figure 2 snows tne temperature measurements made 1n tne radiant furnace. Tne
maximum temperature of 1539°C was measured in tne region above tne fourtn burner
row. Tne temperatures along tne back wall at lower elevations were made beyond
tne tails of tne flames and were somewnat lower. However, s1de-to-s1de
variations 1n tne temperature levels were observed. In tne zone above tne
nose,m tne vicinity of tne pendant radiant superneaters,tft« gas temperatures
start to decline gradually. However, tne gas temperatures m tne central
portion of tne boiler are still aoove 12Q0°C at Z equals 37.9m. At tne
uppermost sampling elevation (Z equals 44.7m) wnere tne flow starts to bend
toward tne screen tubes, tne temperatures were cooler, but still higher tnan
300°C. Some variations in tne temperature levels across tne furnace wldtn were
still present. Tne temperature measurements were continued 1n We back pass
until tne temperature levels dropped below 600°C. Tnese measurements are snown
1n Figure 3. Tne two uppermost locations would nave tne most representatlve
temperatures at tnose locations; wnereas, tne otner sampling locations were
unfortunately eltner too close to tne water walls or m tne recirculation zone
benind tne screen tubes. In tne back pass, tne gas temperatures drop fairly
quickly to 7QQ°C.
Based on tnese temperature measurements, tne approximate location (upper and
lower boundaries) of tne assumed temperature window (800
-------
Sine* tne potential Interest fro. tne LIMB application •"J"*™"
region of tne 001 ler, velocity measurements were »«»•[• ™ !" "*JV,
residence times. Tne average vertical ^:dj.rectj,°j! ?re snown m Figure 5.
vector at tne two elevations (Z equals 37.9m iflr#t w1tn the plug
It should be noted tnat tne measured velocities,1n9*n®™'9 tnrougnput rate,
flow velocity values <7Z) calculated based on tne f
estimated average gas temperature at tnat elevation, ^ Mgnest
area. Som variation. In tne velocity acros. WeJ^™«e at tM^ijnMt
elevation are observed. This 1s the regionand tne recirculation
screen tuoes to enter tne 6*ckPa"'*5#Si?/2 determine velocities and
zone benlnd tne screen tubes, It is ^!??!%!°#£1lIiate tht temperatures and
tne residence times. However, 1t is possible westima _umlng mt tne x
residence times based on measurements and cilc"]iL1on 1n ^ regions
component of tne velocity is nejHjiole. THIS assumption nolo. in tne rej.ons
between the pendant superneaters.
Because of the cooler temperatures close tothe5J|J^Jns"deno,1 an?"
temperatures across tne furnace calculations. Based on the
snown in Figure 4 were chosen for time--c«mp«rarur«_ 1n p1guP# 5 trie
average measured vertical velocltles ln tnese sl » of w# total mass flow
mass flow distribution corresponds to 12,36,32, «* time-temperature
1« slice. 1.2,3 and «. '"I*"1 v?'y V, "!£!,'f?SS llevatlon Z equal. 35.7.
profiles for tnese four slice.. J™ 5 ~ ,n on temperature levels
(117 ft), labeled 1n Figure 5. /**["* !4 aDove l200°C. For tne two center
with tne exception of tne fourth slice the residence times In
sections (2,3) througn «^cn 68S (®J2^SC?°Si Swt 1 second. In section 1, tne
tne temperature zone (300<>C Figure
residence time for sactlon A appears to be re1"]!!ionsnio for the full and tne
7 snows the buli mass-mean time-temperature rtlatlonship w we^ru^^
60% boiler loads. Altnough the temperature ^ residence times are
initially, compared to the full load temperature i^V^ned result is somewhat
longer due to tne reduced furnace wrougnput. The cojainec resu ni of
longer residence times m the sulfation temperature winoow. »
this zone 1s upstream of tnat for the full load.
CONCLUSIONS
The results of tne field tests conducted at this particular wall fired
suggest that:
• Tne temperature zone wnicn 1s most conducive to ^^^"j^fting'ln the
-------
acknowledgments
rm* Mark was conducted under United Sums Environmental Protection Agency
(EPA) ConwK^l£-0Z™K7. MUy Stoktr »u « iwjor subcontractor to Emrjy Md
itraj uonw«;*. w> ~ "7' r^/ftfation (EER). The authors are pleased to
Environmental Reseapcn C p ^ polsoni as EER's program manager. The
acknowledge the A® *d T Semolynas of Riley Stoker Research and tne
?aopirI?"n "f tni Lk Crt* Pow.; Station ptnonn.1 during tMs. fl.ld «.«
are also greatly appreciated.
REFERENCES
D.C. (1983).
2.
Boynton, R. S., Chemistry and Tecnnology of limestone, 2nd ed. J. wn«y 4n
-------
\y+r.:
Figure 1. S«nera1 arrangeawnt of Duck Crttk bo11«r
30-7
-------
Burner
Zona
Flgurt 2. Gas temp«ratur« nwasurad 1g tha radiant furnace at
full load (tnnptraturas 1n C).
30-8
-------
High Temperature
Superheater Pendants'
Figure 3. Gas temperatures Measured tn the convectlve back pass at full load
(temperatures In C).
-------
'4
Time/Temperature
Calculation Sections
Screen Tubes
Pendant Superheaters
Full load
60S load
Figure 4. Approximately location of 800 T 1200°C temperature zone 1n the
boiler.
30-10
-------
Z • 44.7 m
Z - 37.9 m
Z ¦ 35.7 m.
14.4 m/s
¦ 15.9 m/s
Figure 5. Measured velocities in the upper rtdlant furnce (ill velocities
1n m/s).
30-11
-------
1600 -
T, °C
1400
© 12% of Total Mass Flow
© 36% of Total Mass Flow
© 22% of Total Mass Flow
@ 20% of Total Mass Flow
- 3000
£
Z - 35.7 m
Pendant Superheater Region
t (seconds)
Figure 6. Temperature histories in the upper furnace at full load.
3000
1600 -
Full load
602 load
T,
1400
2500
1200
1000
800
1500
600
,1000
0.5
2.0
t (seconds)
Figure 7. Averaged bulk temperature - residence times at full and 60S boiler loads
30-12
-------
Table 1
DUCK CREEK BOILER CHARACTERISTICS
Parameter
Firing
Configuration
Firing Rats
Pulverizers
No. of Burners
Rows
Burners per row
Dimensions
Firing Depth
Width
Depth above nose
Knuckle to Nose Height
Nose Angle
Hopper Angle
Total Vertical Height
Thermal Environment
Heat Release/Cooled surface
Heat Release/Volume
Villi*
Front-wall fired
1250 MW^ (4.27 X 109 Btu/hr) full load
3 Riley Ball-Type
24
4
6
11.6 m
16.8 m
7.3 m
2U5 to
48°
55°
50.4 m
(38 ft)
(55 ft)
(24 ft)
(70.5 ft)
(165 ft)
0.66 MW/ib2 ( 2.04 X 105 Btu/hr-ftV
0.41 MW/m3 (3.87 X 104 Btu/hr-ft3) **
* In the radiant furnace below the pendants at full load.
** In the burner zone at full load.
30-13
-------
Table 2
OUCX CREEK COAL ANALYSES
Proximate Analysis (dry): Yolaclles : 40.51
Fixed C : 49.55
Asa : 10.9%
Ultimate Analysis (dry):
C
H
N
S
Asn
0
Moisture: 16.6%
Heating Value (dry): 29.20 HJ/kg (12,580 3tu/1b)
30-14
-------
Tabic 3
INPUT/OUTPUT PARAMETERS
Parameter
1005 Load
601 Load
Burners 1n Service 24
Electrical Load, MW# 360-385
Excess O2. % dry 3.5-4.0
Coal Flow Rate, tons/hr 145-155
Primary Air-Coal
Temperature, °C 55
Wlndbox Air
Temperature, °C 316-324
Primary Steam Flow,
tons/rtr 1140- UK)
Supertieat Steam
Temperature, °C 535-541
Drum Pressure, atm 168-177
Drum Prtssun, psig 2460-2590
16
230-235
3.3-3.8
91-95
51-55
279-285
690-750
500-540
164-176
2400-2575
30-15
-------
IMPACT OF SORBENT INJECTION ON POWER PUNT HEAT RATES
Dan Y. Giovanni
El metric Power Technologies, Inc.
P.O. Box 5560
Berkeley. California 94705
Hike W. McElroy
Electric Power Research Institute
3412 H111 view Avenue
Palo Alto, California 94303
ABSTRACT
In-furoace SOg control via sorbent Injection Impacts boiler performance as a result
of heats of reaction of chemical processes and Increased auxiliary power deimnds.
In addition, dry injection may effectively reduce flue gas acid dew points and
thereby permit low-level heat recovery. This paper summarizes the effects of the
chemical reactions and quantitatively evaluates ttte potential for heat rate
Improvement through supplemental heat recovery.
INTRODUCTION
As illustrated In Figure I. there are a variety of alternative process
configurations and sorbents for 1n-furnace SOj control. For the purposes of this
analysis, the thermal effects of external {to the boiler) calcination, hydration,
and pulverization were not Included. Rather, the effect on boiler efficiency of
calcination/dehydration and sulfation w1t1n the boiler were quantified. These
calculations were performed for the several sorbents as listed in Figure 2. In this
context, the sorbents were assumed to be Injected Into the main furnace cavity
wherein calcination occurs. In the calcination process, which 1s endothermic,
carbon dioxide and/or water vapor evolves and calcium oxide (Hme) results. A
portion of the lime reacts with SO2. which is an exothermic reaction, to form
calcium sulfate. These reactions are illustrated in Figure 3.
In addition, SO3 formed In the combustion process will be absorbed by the calcium
byproducts. The removal of SO3 provides an opportunity for operation of post boiler
equipment at temperatures below typical acid dew point constraints. Since a 40*F
decrease In stack gas outlet temperature Is worth approximately 1 percent 1n boiler
effieieney, 1n-furnace sorbent Injection will facilitate Improvements In power plant
heat rates.
ANALYTICAL METHODOLOGY
Boiler efficiency calculations were' performed based on standard combustion
calculations for a hypothetical unit.(1) A simple computer model was constructed
for this purpose. Calculations were perfomred for three coals as listed 1n
Figure 4. The baseline conditions were for no sorbent Injection, 300*F outlet flue
gas temperature, 2 percent loss on ignition of the flyash, and 20 percent exeess
air. For Illinois no. 6 coal, the baseline boiler efficiency was 88.16 percent.
31-1
-------
Similar calculations were then performed in which the calcination and sulfation
reactions were incorporated in the computation. For this purpose, the heats of
formation and heats of reactions (Figures 5 and 6) were built Into the model. In
addition, assumed SO2 removal efficiencies for each sorbent as a function of
calclum-to-sulfur molar ratio were factored into the analysis. The net effect of
sorbent injection upon boiler efficiency was determined by comparison to
computations for baseline conditions.
RESULTS AND DISCUSSION
The net effect on boiler efficiency and heat rate for the calcination and sulfation
reactions is shown in Figure 7 for Illinois no. 6 coal. It can be seen that the net
effect is not slgnflcant; typically less than 0.3 percent for most conditions. This
is primarily due to the balancing of exothermic and endothermic reactions which
occur in the boiler. At low Ca/S ratios and for lower sulfur coals, the net effect
would be typically less than 0.2 percent.
In general, the carbonates resulted in a net decrease in boiler efficiency and the
hydroxides and free lime resulted in a net Increase. This beneficial heat rate
impact for the calcium hydroxide an/or lime will help offset higher costs for this
material as compared to limestone.
All of the dolomitlc materials w1l produce a net decrease in boiler efficiency.
This is due to the energy requirements for calcination/dehydration of the magnesium
compound without a commensurate sulfaction reaction occurring. In Figure 8. the
detrimental effect on boiler efficiency 1s Illustrated for dolomitlc carbonates and
hydrates as a function of magnesium content. It can be seen that a 50 percent Mg
sorbent will reduce boiler efficiency by about 0.1 percent more than an equivalent
sorbent with no Mg.
The effect of lowering stack gas temperature (due to SO3 removal) on boiler
efficiency is shown in Figure 9. If the flue gas sensible heat can bt utilized
within the boiler (air, feedwater or sorbent preheating), reducing the stack gas
temperature by 150*F will result in a nominal 4 percent Improvement In boiler
efficiency. As shown on Figure 10, each 40*F Increment 1n flue gas temperature
reduction will result In 1 percent improvement in boiler efficiency and
100 (Stu/kWh) decrease 1n unit heat rite. The fuel cost Impact for this Itvel of
heat rate improvement is very site-specific, but would be substantial and attractive
for most power plants.
There are other impacts of sorbent Injection on unit heat rates, including:
auxiliary power requirements for sorbent preparation and conveying, increased
sootblowlng, auxiliary power for handling and disposal of Increased solids In the
boiler and electrostatic precipitator, onslte external calcination and/or hydration,
and redistribution of heat transfer within the boiler. The magnitude of the
combined effect of these impacts 1s very site-specific. However, it is estimated
that it may result In a 1 to 2 percent decrease In unit heat rates.
CONCLUSIONS
1. Met calcination/sulfation energy requirements do not significantly affect
boiler efficiency. At anticipated Ca/S ratios, it is typically less than
0.2 percent.
2. CaO and CatOHJj result in net increases in boiler efficiency; CaCOs and
dolomitlc sorbents result in net decreases.
3. Increases in calcium utilization result 1n Increases in boiler efficiency.
31-2
-------
4. Flue gas temperature reductions (and heat recovery) are possible due to SO3
removal; this provides a significant opportunity for heat rate Improvements.
5. Site-specific design factors will Increase the auxiliary power requirements for
furnace sorbent Injection independent of calclnatlon/sulfatlon effects.
REFERENCES
1. Babcock ft Wilcox, STEAM Its Generation and Use. 38th Edition, 1972.
2. Hodgman, C. D. et al.t Handbook of Chemistry and Physics. The Chemical Rubber
Publishing Co., 44th Edition, 1963.
31-3
-------
CALCIUM
HYOflATOR
•r^-4!!BAT
CKOHV
CALCIUM
Figure 1. Sorbent Injection Alternatives
LIMESTONE
DOLOMITE:
CALCIUM HYDROXIDE:
(HYDRATED UME)
DOLOMIT1C HYDROXIDE:
(PRESSURE HYDRATED LIME)
UME
(PRECALCINED)
CaCO,
CaCO,MgCO,
Ca(OH)t
Ca(OH)IMg(OH)t
CaO
Figure 2. Dry Sorbent for Furnace Injection
31-4
-------
SORBENT
^CaO+SO, x;
£ - CaSO. S*
CALCINSR
S " V
Svwvwvvw
r> ISORB - CaO
¦ CALCINATION / DEHYDRATION
0 SULFATION
C HEAT RECOVERY
WTl
Figure 3. Sortoent Injection Heat Rate Impacts
Powder Appalachian
River Medium Illinois
B««in Sulfur No. 6
Carbon (% bywt)
47.85
69.7
srjs
hydrogen •
3^0
4JB
3.7
iulfur
(US
2d
4.0
Ixygen "
10.82
8.1
5.8
Htrogen "
0J2
1.3
0.9
loisture *
30.4
6.0
110
ah
8.43
8.0
16.1
Ming Value (Btu/lb)
8,020
13,400
10,100
f/10* Btu)
1JB
2.32
1.89
Figure 4. Coals
31-5
-------
(Btu/tb-moW
Ca
0
CaO
-273,480
CaCO,
— 519,300
Ca(OH),
-424,440
CaSO,
-816,320
Mg
0
MgO
-258,840
MgCO,
—478,800
MgtOH),
-397,800
H,0
-104,040
CO,
-169,290
SO,
-127,730
Figure 5. Heats of Formation
CaCO, - CaO + CO,
CaCOH), - CaO + H,0
CaO + SO, + V40, - CaSO,
MgCO, - MgO + CO,
MgfOHfc - MgO + H,0
CaCO, + SO, + %0, - CaSO. + CO,
Ca(OH), + SO, + %0, - CaSO, + H,0
AHR(Btu/lb-moia)
+ 76,590
+ 46,980
-215,172
+ 50,870
+ 34,920
—138,582
-188,192
NOTE: - HR DENOTES AN EXOTHERMIC REACTION.
Figure 6. Calcination/Sulfation Reactions
31-6
-------
!
3
8
SS iaooo-
3
s
5
2
ILLINOIS NO. 6 COAL — 4V. SULFUR
CMS
MOLAR
AATJO
Una (KM)
OoMnHvOMO)
Figure 7. Net Effect on Boiler Efficiency and Heat Rate for Calcination and
Sulfation Reactions
«UB»-
m wno<
1
MIS'
~ J
~ J-
£
-.1
-i-
-J'
ILLINOIS NO. 6 — 4% S COAL
I I I I.
40 V
C«00>» MgCOt
^ CMOMh • MgfOH))
Figure 8. Net Effect on Bollar Efficiency and Heat Rate For Dolour!tic
Sorbents of Varying Mg Contant
31-7
-------
pOHotKma
5
10
£
*•
BASSJNg CONOmONS
STACK OA* TfMP ¦ 300'F
cxcsssam . am
ny AMU 101 a s*
Cjco, sohwmt iNjccnoN
Ct/S * 2
Ca UTlUZATtQN a as%
10
<3
too
»
so
SOCK OM TOW!**
Figure 9. Effect of Lowering Stack Gas Temperature
hut rati
uv. «mm cocr op nm. mmuvm
ILLINOIS NO. 6 COAL
eveu wmemtett <%i <—
a
UHUMi M«ATIUT« a 10000 0MIWM
30 VJl UV. 0U& COST W PUO. a UltH
STACK OAS TCMP ¦ XBTT
(XCSSS AM ¦ 10%
H.YASHLOI a 2%
CQN0CNSCRM(SS.a JmHfl
M.O
-P-
4/
T
30
—T-
10
-T—
a
si
-r-
u
31
IA WWcai. 1 %T2
Figure 10. Impact of Plant Operating Conditions on Heat Rate
31-3
-------
BOILER DESIGN CRITERIA FOR ORY SORBENT SO*
CONTROL WITH LOW-NOx BURNERS
A. Kokkinos, 0. C. Borlo, R. W. Koudcy, d. P. Clark, C. Y. Sun
Combustion Engineering, Inc.
1000 Prospect H111 Road
Windsor, Connecticut 0609S
0. 6. Lachapelle
Industrial Environmental Research Laboratory
Environmental Protection Agency
Research Triangle Park, North Carolina 27711
ABSTRACT
A program to develop boiler design criteria for application of dry sorbent
SO control technology with low-NOx burners is being conducted with EPA
sponsorship. A comprehenslve review of past and current research 1n the area
of sorbent SO control was performed to provide a basis for evaluating the
implications of this technology on boiltr design, cost effectiveness, and
operability. Historical and projected design trends were analyzed for all
tangentially fired pulverized-coal utility boilers built Airing the period I960
to the present, Including the effect of coal rank. The design changes
necessary to incorporate dry sorbent S0X control for utility pulverized coal*
fired boilers were evaluated. Among the design and operating factors
considered were coal and sorbent type, sorbent-to-sulfur molar ratio,
time/temperature history, and back-end effects. Limestone preparation
requirements were defined.
INTRODUCTION
Increasing concern for the environmental effects of acid rain has led to a
reexamination of the fossil fuel burning electric utility Industry.
Previously, only new plants were mandated to Install pollution control
equipment for gaseous emissions under federal New Source Performance Standards
(NSPS), although some existing plants were retrofitted with equipment due to
local requirements. However, new legislation 1n response to the acid rain
question may require at least a portion of existing oil and coal burning plants
to limit emissions of sulfur dioxide •
Due to the possibility of regulation of existing plants, various alternative
sulfur oxide (SO ) removal processes are being examined in addition to the
tail-end lime or limestone systems predominantly employed to meet NSPS.
Because of the combined requirements of "retrofltabi lity", economics, and
moderate sulfur removal efficiency, the concept of furnace limestone injection
has received renewed interest and study. In the early 1960's, furnace
32-1
-------
Injection originated as a method for controlling SOj emissions without
involving utilities in sophisticated chemical flue gas treatment systems.
However, trials in small-scale furnaces and full-scale utility boilers
generally failed to demonstrate sufficient 1n-fumace SO? removal at
reasonable sorbent-to-sulfur ratios.
In retrospect, it appears that the high temperatures and oxidizing conditions
typical of conventional utility boilers created conditions unfavorable for
SOg absorption. The development of advanced low NO utility boiler
combustion technologies may provide new combustion conditions and lower furnace
gas temperatures which may be more suited for 1 n-fumace absorption of SOg by
limestone or other sorbents. The combination of these two technologies has
been given the acronym LIMB, representing Limestone Injection with Multistage
Burners for N0X control.
As part of its overall program to evaluate various pollution control
technologies, the Environmental Protection Agency, together with Combustion
Engineering, Inc. (C-E), initiated a study to assess the impact of dry sorbent
furnace Injection for controlling sulfur emissions on boiler design and
economics. This study comprised a review of sorbent injection data generated
to date, past and future boiler design trends, and determination of possible
design changes due to the dry sorbent Injection and its economics. The
preliminary results of this study are presented herein.
HISTORY OF DEVELOP^ NT
Removal of SO from boiler stack gases by direct, dry injection of alkaline
earth compounds into the furnace chamber has been discussed and tested for the
past 30 years. During the 1950's, C-E, Ref. (1), developed a process for
furnace injection of MgO for control of molten phase vanadium-related high
temperature oil ash corrosion and SO-?-related cold end corrosion and acid
smuts fallout. Injection of both MgO and dolomite was by means of air
aspirators in the furnace cavity and through sooth lowers. The SO 3 emissions
were usually controlled below 6 ppm, which prevented low temperature metal
wastage and air heater plugging. These techniques had little effect on removal
of SO9, which 1s emitted at a level about 20 to 100 times greater than SO*,
but did provide beck ground for the large-scale injection of dolomite and
limestone.
In 1955, a patent Issued to John W. Beckman covered a process that would remove
SO9 and SO3 from combustion gases at temperatures of at least 350*F through
the use of finely divided solid calcium carbonate, Ref. (2). In the early
1960's, considerable development work was performed by Wlckert 1n West Germany,
as well as Wahnschaffe and associates of Volkswagenwerk in Wolfsburg, West
Germany. At Volkswagenwerk, Ref. (3), a hydrated calcined dolomite was
injected into a boiler just downstream of the coirbustlon zone. Considerable
success was achieved 1n the removal of SO9. Wo boiler fouling problems were
encountered. Only limited S02 removal was measured when limestone was used
as the reactant. These tests were later discontinued due to the high cost «f
raw material in the plant area.
During the latter part of the 1960's, further Investigations were conducted 1n
Japan, Europe, and the United States. Both pilot and full-scale Investigations
were conducted by the Central Research Institute of Electric Power Industry in
Japan, under the direction of Y. Ishlhara, Ref. (2). Limestone performed well
in the pilot plant, producing 32* to 40% sulfur removal with a calcium-to-
32-2
-------
sulfur (Ca/S) molar ratio of 1. In the plant tests, hydrated lime was found to
perform better than limestone.
In Essen, West Germany, Bergbau-Forschung GmbH, Ref. (4), constructed a 23-foot
by 4-inch burner tube to study limestone and dolomite injection. At
temperatures up to 1650°F, 801 to 401 S02 removal was obtained at a Ca/S
molar ratio of 3.
In the United States, bench-scale research was conducted by Battelle Memorial
Institute, Ref. (5), under contract to the National Air Pollution Control
Administration (NAPCA, an EPA predecessor). In this stu<*y, primary emphasis
was on additive properties and their behavior under various time/temperature
conditions, with respect to both calcination and SOg absorption capabilities.
Under sponsorship of NAPCA, and later the Environmental Protection Agency
(EPA), R. H. Borgwardt and associates, Ref. (6,7), conducted bench-scale tests
on the reaction kinetics of various limestones and dolomites during the late
1960's and early 1970's.
In larger scale tests during this time period, Wisconsin Electric Power
Company in 1964 initiated studies of direct injection at their Port Washington,
Wisconsin, plant. Oolomltic limestone was mixed and fed with the coal. Most
tests were conducted at about 130* of the stoichiometric calcium-to-sulfur
molar ratio. Removal averaged 50% at this feed rate for coal with 2.8%
sulfur. Deposits which could not be removed by sootblowing were formed on the
superheater tubes.
Also on a conwercial scale in 1966, C-E, Ref. (8), 1n conjunction with Detroit
Edison, conducted field tests on the injection of both dolomite and limestone
Into one furnace of a 325 MWe twin furnace unit, followed by wet serubbfng.
While introducing sufficient additive to react with all the sulfur in a 2.51 to
3.5% sulfur coal, in-furnace removal efficiencies of about 25S were obtained.
No adverse effects on furnace operation were recorded.
Following the C-E tests, the Tennessee Valley Authority (TYA), under contract
to the U.S. EPA, conducted limestone injection tests on a IS) MWe pulverized
coal-fired boiler at TYA's Shawnee Steam Plant, Ref. (9). In contrast to the
earlier bench-scale results and the preliminary findings at Detroit Edison,
overall SOg removal performance was poor and furnace fouling was significant.
Further work conducted by C-E at Kansas City Power and Light, Ref. (10), Kansas
Power and light, Ref. (11,12), and Union Electric, Ref. (12,13), with furnace
Injection followed by wet scrubbing, was more in line with the TVA results.
Although furnace fouling was not a problem 1n either case, being dependent on
coal ash properties and boiler design, additive reactivity was a problem at
both locations and appeared to be reduced by "deadburning" of the additive,
caused by calcination at excessive temperatures. Furnace injection was
subsequently abandoned at both power plants.
In 1970, Babcock and Wilcox, Ref. (14), issued a research report covering
extensive pilot plant work done under NAPCA funding. In the pilot study, a
total of 415 tests were conducted with 129 different additives and 7 pulverized
coals. Up to 60* removal was obtained at Ca/S molar ratios ranging up to 4,
Many process variables were investigated. Based on the behavior of the ash-
additive particulate in these tests, it was predicted that furnace fouling
would not be a problem. However, resistivity measurements of the particulate
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matter emitted indicated that electrostatic precipitation performance could be
adversely affected.
During the remainder of the 1970's, interest 1n direct additive injection
subsided and was replaced by development of other flue gas desulfurlzatl on
techniques. However, Investigations have again begun, Initiated by changes 1n
boiler operating conditions which have the effect of lowering combustion zone
temperatures. The changes are due to the high moisture content of low rank
coal currently being used and the fact that recently designed boilers are
larger to accomplish the same heat transfer. This combination of lower
combustion temperatures and increased residence time of the combustion gases in
the boiler has proven to be beneficial for SO- removal by direct additive
injection. Hein and associates, Ref. (15,16), at the Rhe1n1sch Westfaellsches
Elektrizltaetswerk, Essen, West Germany, have reported test results from
additive Injection in a 60 MWe boiler. At a Ca/5 molar ratio of 2, better than
75% S02 removal was accomplished, and no boiler slagging or fouling problems
were reported.
8ecause of regulations limiting the NO emissions, work was also performed in
recent years to develop combustion techniques for reducing the formation of
NO . The techniques involve controlling the amount and location of primary
and secondary combustion air and have the overall effect of reducing peak flame
temperatures. While operating these burner systems, investigators found that
the reduced flama temperature and fuel-rich contoustlon conditions Improve S02
removal by direct additive injection.
In tests conducted by Energy and Env1ronmental Research for the EPA, Ref.
(17), results from 1ow-N0„ burner facilities have demonstrated the Importance
of the time/temperature hfstory experienced by the sorbent. Sulfur capture
was affected by design parameters, sorbent injection location, and thermal
environment and was facility dependent.
Mitsubishi Heavy Industries (MHI), Ref. (18), under contract to the Electric
Power Research Institute (EPRI), recently completed a study of limestone
furnace injection using a low-NO burner. In preliminary reactor tube tests,
It was concluded that hydrogen sulfide (H-S) absorption from fuel-rich
conditions was not as effective as S02 absorption from a gas containing
excess oxygen (O?). In the 4-ton/hour test furnace, 30* to <0* SO- removal
was obtained w1tn high sulfur coal (3.31) and low sulfur coal (0.75%) using
limestone at a Ca/S molar ratio of 2 under low-NOx firing conditions.
C-E, Ref. (19), recently completed a 4 x 10s Btu/hr pilot scale test for EPRI
1n which furnace slagging and fouling behavior with Hmeitone injection during
low-NOx firing conditions was Investigated. Two coals were evaluated. For
the case of a high sulfur Eastern coal, slagging behavior and deposit
friability Improved with limestone addition, although deposit buildup was at a
faster rate. Slagging and fouling deposit characteristics also benefited from
limestone addition for a high sodium Western subbitunrlnous coal. In both
cases, SO2 removal efficiency was dependent on particle residence time at
favorable temperatures.
In recent tests reported by Radian Corporation, Ref. (20), limestone was
injected into a 52 MWe tangential-f1 ring lignite boiler at Hoot Lake Station of
Otter Tall Power Company. Most tests were conducted in a low-NO„ firing
mode. S0« removal ranged from 20% to 50% at Ca/S molar ratios of from 1.6 to
5. Boiler fouling behavior was also improved.
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PROCESS DESIGN CRITERIA
The most Important factors which must be considered 1n evaluating dry sorbent
Injection as an S02 control alternative are coal type and characteristics,
sorbent type and characteristics, and its effect on boiler performance.
Coal Type and Characteristics
There are five basic types of coal which are presently being used in the United
States and which will continue to be used for at least the next 25 years.
These coals are Eastern and Midwestern bituminous flow and high sulfur), sub-
bituminous, Texas lignite, and Northern Plains lignite (low sulfur). Typical
analyses for these coals are shown 1n Table 1. Ory sorbent Injection will
impact each of these coals differently, generally as a function of sulfur
content and coal ash properties.
Coal contains a sizeable percentage of noncombustlble ash material, the amount
varying with the coal grade. When fired, this material can accumulate on the
boiler tubes and, 1f uncontrolled, can reduce heat transfer and consequently,
boiler efficiency. The ash properties are important in determining the
performance, slagging, and fouling tendencies of a particular coal. The most
important properties are generally considered to be:
Ash fusibility temperature
Base/add ratio
Si 11 ca/alumina ratio
Iron/calcium ratio
Active alkali content
Sodium content
Gravity fractionation
Slagging 1s the deposition of molten or partially fused ash particles on tube
surfaces. The particles are carried by the gas to the furnace walls as well as
up to the radiant surfaces in the upper furnace. When the particles strike a
cool tube surface, they chill and solidify. Radiant surfaces in the furnace
are most susceptible to slagging, but convective surfaces can also slag if gas
temperatures exceed prudent levels. Normally, coals with low ash fusion
temperatures have a high potential for slagging.
Fouling results from the condensation of the volatile coal ash constituents
which have been vaporized during combustion (e.g., sodium sulfate) onto flyash
particles and boiler tubes 1n areas where temperatures are below the dew points
of the constituents.
Sorbent Type and Characteristics
Several of the sorbent properties which Influence the effectiveness of SO*
capture and utilization of the sorbent are sorbent type (e.g., lime, limestone,
sodium carbonate), calcination reactions (1f applicable), particle size,
porosity, and time/temperature Mstory experienced by the sorbent. The
additive also influences overall SO2 capture according to the calc1um-to-
sulfur molar ratio employed and the quality of dispersal of the additive in
the flue gas.
Additives used for furnace Injection normally are calcium, magnesium, or sodium
alkalis. By far the most common alkali employed has been calcium-based, and
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of these compounds, calcium carbonate has been most extensively used. As a
result, most of the Information presented concerning sorbents deals with
calcium carbonate (limestone), with other compounds discussed where information
is available.
The general term "limestone" covers a broad range of materials varrying in
calcium and magnesium content—from calcit* or argonlte (CaC03) to dolomite
(MgCOj.CaCOO. The terms "high-calcfum limestone" (very low Tn magnesium
carbonate (wgC03) ) and "dolomite limestone" (approaching dolomitft in MgC03
content) are commonly employed. MgC03 content affects S02 absorption
because it does not behave like CaC03, in regard to either calcination or
reaction with S02.
Limestones vary widely 1n their chemical composition and crystal structure,
with the result that material from one source may differ from another in degree
of porosity developed during calcination and, therefore, 1n absorption
effi dency.
For the three compound types mentioned—calcium, magnesium, and sodium—the
calcination reactions are as follows:
CaC03 H*at CaO + C02
MgC03 MgO +• C02
Na^ "S** Na20 + C02
In an early fundamental study by Battelle, Ref. (5), the equilibrium
dissociation pressure of carbon dioxide (C02) maintained by limestone was
plotted as a function of temperature. These data, shown in Figure 1,
demonstrate that a temperature of about 1400°F Is necessary to keep the
calcined limestone from recomblnlng with C02 at a typical furnace C02
concentration of U.5*.
In addition to the kinetics of additive calcination, tenperature and residence
time play a major role 1n determining final particle size, porosity, and,
therefore, total available surface area. Based on reports of Battelle and
Borgwardt, Ref. (6,7), the most Important factors in determining the reactivity
of a given limestone are the surface area and porosity developed during
calcination. These factors directly determine the availability of 11 me for
reaction, the accessibility of the 11me, and the space which 1s available
within a given particle for reaction products. The surface area and porosity
are determined by calcination rate and sintering rate. The latter 1s more
important In determining the decreased reactivity of limestones at high
temperatures. Sintering itself 1s a conplex process, depending on grain size,
impurity content, lime temperature, and calcination time.
Testing by MHI 1n a l-1nch diameter tube reactor demonstrates the siytiflcant
effect of residence time on S02 removal. As shown 1n Figure 2, Ref. (18),
S02 capture increased dramatically with increasing residence time.
Additive calcination and reactivity as related to particle size and porosity 1s
a conplex phenomenon. Most investigators have observed a leveling off in
performance as particle size 1s decreased. This nay be due to the interaction
of pore diameter and particle diameter. For larger particles, pore diameter
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may be Important, while for smaller particles, the effect 1s minimized.
Another factor which may limit the effectiveness of smaller particles is mass
transfer. The fine particles should have less slippage 1n the gas stream than
larger ones, and less relative motion between solid and gas.
Selecting the appropriate sorbent/sulfur ratio can have a significant effect on
the economic viability of LIMB for a particular unit. Tests have shown that
high-and low-sulfur coals can require significantly different amounts of
sorbent per mole of sulfur. The selected ratio determines the Impact on all
other components and subsystems. Including gas cleanup, limestone preparation,
and the boiler itself.
For this study, a Ca/S molar ratio of 2 was used for high-sulfur coals, and a
Ca/S molar ratio of 4 was used for low-sulfur coals. These ratios were
selected after considering several trade-offs between Incremental SO? removal
and the penalties associated with increased sorbent requirements. For low-
sulfur coals, tests have shown that little additional SO* removal Is achieved
at Ca/S molar ratios above 4. The added requirements for pulverizing and
transporting additional sorbent, plus the increased back end requirements, more
than offset the benefits of added SO2 removal. For high-sulfur coals, the
major consideration is solids carryover. At a Ca/S molar ratio of 2, for a
3* sulfur coal, the solids loading would be 150* greater than without sorbent
injection (conpare with 50* greater loading for a 0.5* sulfur coal at a Ca/S
molar ratio of 4). This solids loading Increase will have an adverse effect on
ESP performance. Increased sootblowing will be required to remove the
(anticipated) increased deposits in the convective sections.
Sorbent Preparation
Sorbent handling and storage can be carried out with essentially the same
equipment conventionally utilized for coal. Commercially available components
have been combined in the various demonstration systems, all of which have
operated successfully.
Pulverizers are designed to provide a selected particle size when grinding
materials of a similar hardness and density. Because limestone, for exanple,
is denser than most coals, simultaneous pulverization of limestone and coal
would result 1n excessive mill rejects if adequate control on limestone
particle size was maintained. Therefore, a limestone preparation system would
be designed to include separate mills dedicated to limestone pulverization
alone.
From the mills, the sorbent is sent to storage silos, from which it is
transported via dense* or dilute-phase transport pumps to the boiler. A dense-
phase system delivers about 20 lb sol1d/Tb air. The advantage of this system
is the small amount of air required to transport the sorbent. The major
disadvantages are the high pressure loss (roughly 40 to 60 ps1g) and associated
sealing problems. A dilute-phase system requires about 1.5 lb air to deliver
1 lb of sorbent. The pressure drop is In the range of 10 to 20 1n w.g. The
split between primary air, overfire air, and sorbent transport air win have to
be carefully controlled to maximize combustion and SOg removal efficiencies.
Figure 3 shows a typical limestone preparation and Injection system.
Sorbent Injection Considerations
Many different schemes have been tried for Injecting sorbent into boilers for
sulfur removal. From these tests, several criteria for injecting sorbent to
32-7
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achieve the most beneficial results have been determined: (1) maximize
sorbent particle residence time 1n the "critical" temperature region (between
1400*F and 2200*F, where the calcium/sulfur reaction to form calcium sulfate is
most favorable); (2) minimize the time the sorbent particle 1s subject to hard
burning (above 2700°F); (3) maximize the particle surface area; and (4)
maximize the mixing between sorbent and flue gas.
Because of the short retention time in most utility boilers, it is inportant
for the sorbent to be distributed rapidly over the boiler cross section 1n
order to contact all areas of the gas stream. If time 1s lost in achieving the
proper distribution, then some portions of the stream will not have enough time
for good absorption after the sorbent becomes available.
Distribution 1s a difficult problem because of the very large cross section of
modem boilers, the rapid flow of the gas, and the small size of the
particles. In most Injection systems, the particles are carried 1n a body of
Injection gas, so that the problem becomes one of fluid dynanrics —the mixing of
one body of gas with another.
In addition to mixing considerations, the location of sorbent Injection also
determines the temperature encountered, gas mixture (reducing or oxidizing) and
particle residence time. These factors can influence both calcination of the
additive and the reactions between sulfur species 1n the gas phase and the
additive.
MHI has carried out a comprehenslve series of tests at their 4-ton/hr pilot
plant during which they evaluated four methods of introducing the sorbent into
the furnace as shown 1n Figure 4: (A) with the coal, premixed; (8) through
auxiliary air nozzles; (C) through overflre air nozzles; and (D) through gas
recirculation nozzles, Ref. (18). The best performance wis achieved by
introducing the sorbent through the overflre air nozzles, with 57% SOj
removal at a Ca/S molar ratio of 3.
Steam Generator Efficiency
Sorbent Injection Introduces several additional losses which adversely affect
the overall steam generator efficiency. These are:
1. Heat required for calcination
2. Increased dry gas loss
3. Increased flyash heat loss
4. Increased ash pit loss
The magnltud* of the efficiency reduction depends on the sulfur content of the
coal and the ca1c1um-to-sulfur molar ratio. For high-sulfur coals, these
losses will be offset to a degree by an efficiency gain resulting from a
decrease In the allowable gas temperature leaving the steam generator
envelope. This relates to the fact that boiler eff1d#ncy Is very sensitive to
the gas exit temperature, which 1s largely dictated by the coal sulfur
content. Typically, this temperature 1s about 155"F for coals containing up to
IX sulfur and 180*F for coals containing 3% to 5% sulfur. A reduction in the
concentration of SO^/SOj at the boiler exit will reduce the potential for
cold-end corrosion and permit a lowering of the exit gas temperature.
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Effect of Sorbent Injection on Overall. Steam Generator and Consonant
Performance
Sorbent injection grsatly Increases the quantity and changes the character of
the solids passing through a steam generator. As a consequence, because the
slagging and fouling characteristics are changed, the overall steam generator
efficiency and the performance of the individual components (e.g., superheater
and reheater outlet temperatures) are affected.
It 1s expected that a low-N0x firing system plus sorbent injection will
result 1n an inprovement 1n waterxall deposit friability (ease of removal) and
sootblower effectiveness for most coals. For retrofit units firing coals which
exhibit severe slagging in the presence of sorbent, the steam generator
capacity may be adversely affected. If slagging 1s excessive, it may inhibit
waterwall absorption, reducing evaporation and raising the furnace outlet gas
temperature (FOT, defined as the temperature at the bottom of the vertical
radiant surfaces (panels) suspended 1n the upper section of the furnace). If
increased sootblowlng frequency is not adequate to alleviate this problem, the
unit capacity may have to be reduced. For new units, these potential waterwall
slagging problems may be minimized by including larger furnaces 1n the design.
Superheater and reheater outlet temperatures are determined by FOT, gas flow,
and the degree of fouling on the heat transfer surfaces. An FOT which 1s
higher than the design value results in higher superheater and reheater
temperatures. These temperatures are normally controlled by manipulating
burner tilts, excess air, and superheater/reheater spray. However, since the
latter two options have considerable influence upon the overall plant
efficiency, their use should be minimized. As in the lower furnace section,
the increase in solids loading with sorbent Injection will result in an
increase 1n the deposit rate on superheater and reheater surfaces. This will
require an increase in the sootblowlng frequency. For new units, design
considerations may include the use of wider spacing in the convectlve section
to prevent tube bridging from deposit buildup and/or the addition of widely
spaced superheater panels to reduce the gas temperature before the gas enters
the convectlve sections.
Sorbent Injection will result in an increase in the gas/solids mass flow
through the steam generator. In retrofit applications, this will result 1n an
increase 1n the mass velocity through the unit. While this increased velocity
will causa an Increase in the convectlve heat transfer coefficient, it is
important to keep the velocity within acceptable limits to minimize tube
erosion. The maximm allowable gas velocity depends on the erosion
characteristics of the flyash and the quantity of flyash. For conventional
coal-fired units, the general practice 1s to limit the maximum velocity to
approximately 50 to 70 feet par second. With sorbent Injection, this
velocity may have to be reduced, due to the Increased solids loading and the
ash erosion characteristics (not yet known). In a retrofit application,
widening the spacing between tube elements to later gas velocity may not be
economical. A reduction in unit capacity may, therefore, be required to keep
the gas velocity within acceptable limits. For new units, the convectlve
section can be designed with wider transverse spacing to keep the gas velocity
below the maximum value.
The final heat transfer sections located within the steam generator envelope
are the economizer and the air preheater. Prior to the early 1970's, most
economizers were of a f1nned-tube staggered arrangement design. The
significant increase 1n solids loading with sorbent injection would make this
type of economizer very susceptible to plugging. Therefore, for retrofit units
32-9
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which Incorporate finned economizers, it may be necessary to replace the
economizer with one featuring bare tubes with an in-line arrangement. This
will generally result in a larger economizer to accomplish the same amount of
heat transfer. In some cases, Installation of a larger economizer may be
impractical due to space limitations. Insufficient economizer surface results
in a reduction in the quantity of steam evaporated in the steam generator. For
some coals, this may be fully or partially overcome by tilting the coal nozzles
downward and/or increasing the frequency of soctblowlng in the furnace to
remove accumulated deposits and increase waterwall absorption*
Studies performed on air heaters during limestone or dolomite Injection have
shewn that, with reduced SQ^ levels in the gas stream, plugging, as Indicated
by pressure drop across the air heater, is reduced to a minimum. While the ash
loading is increased, the actual buildup decreaseis, and that which forms tends
to be fluffy and readily removable. Low temperature probe studies conducted
during full scale limestone furnace injection tests showed that SO* was
reduced to a level sufficiently low to eliminate corrosion and produce deposits
which are dry and generally non-adherent.
For units which will require increased sootblowing frequency and/or sootblower
coverage, 1t may be necessary to upgrade the capacity of the sootblowing
system. It should be noted, however, that the additional steam or air
consunptlan required to aceonpUsh this will have an adverse impact upon steam
generator and overall plant efficiency.
The increased gas flow rate through the convective sections which is associated
with sorbent injection will result in higher draft losses for retrofit units.
These facts must be considered 1n evaluating the capacity of an induced draft
fan.
Solids Removal
Sorbent injection dramatically increases the particulate loading leaving the
boiler. This quantitative change is coupled with changes in the chemical and
physical properties of the solid material. These changes Impact the
performance of existing back end equipment In retrofit situations and dictates
the selection of equipment for new units.
There is relatively little Information available on the effect of sorbent
injection on ESP performance, although there 1s ongoing work in this area by
the EPA. For retrofit applications, some improvement 1n ESP performance can be
realized by SO^ conditioning. Tests have shown that LIMB flyash resistivity
can bt significantly reduced by injecting small amounts of SO* ( ^5 ppm),
increasing the flue gas moisture eontent, and/or decreasing tne outlet
temperature to less than 250*F. Additional research Is needed in this area
before the extent of ESP modification can be defined.
Units equipped with wet scrubber systems are not viable candidates for LIMB
retrofitting. Besides providing little added S02 reduction, the reactive
alkaline oxides could create scaling problems unaer certain conditions.
The concept of dry scrubbing is a preferred method for tall-end S02 removal
1n certain situations. This technique offers the potential of a "combined
system" - furnace Injection followed by dry scrubbing. Calcined sorbent could
be recycled from the spray dryer bottom or particulate collection device Into
the spray dryer. It has been demonstrated that this collected sorbent can be
successfully used as a spray dryer feed stock, albeit with reduced
effectiveness.
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With sorbent Injection into the furnace, #11 ash hoppers will experience a
higher loading. In general, ash hoppers are oversized to accommodate a range
of ash loadings from various coals* It 1s reasonable to assume that no
modifications will be required to compensate for additional ash. Approximately
20* to 30* of the total solids are expected to be collected in the Hoppers.
The operational frequency of the ash removal systems will have to be Increased
with $he higher solids loadings.
HISTORICAL AND PROJECTED DESIGN TRENDS
A survey of key design parameters for C-E coal-fired boilers was undertaken to
provide guidelines for establishing criteria for site selection and for
identifying those parameters which are influential 1n designing for dry
sorbent injection. The survey covered a total of 273 units sold from I960 to
1982. Of this total, 179 coal-only units sold between 1960 and 1980 to
domestic utilities were defined as the basis for study.
Among the parameters considered were unit size, coal rank and emission control
capabilities. These data are presented in Tables 1 and 2 and Figures 5 and 6.
As discussed earlier, there are five basic types or ranks of coal which have
been used during the last 25 years. As can be s«en in Table 1, there is a wide
variation in heating value as well as moisture, ash, and sulfur content. The
ash analyses vary considerably • These differences significantly influence
boiler design and operation. Figure 5 shows tho selected sample of boilers
segregated by primary coal fired and contract year. Note the shift from
Eastern bituminous to subtoitunrinous and lignite coals. The factors most
directly responsible for effecting this shift 1n coal fired were the advent of
more stringent federal emission regulations 1n 1^70 and Industrial eaqsansion
of the Western and Southern United States. The low sulfur content of the sub-
bitunri nous and lignite coals makes them more attractive from a capital outlay
standpoint, since this greatly reduces the amount which must be spent on
expensive cleanup equipment. Figure 6 shows the breakdown by fuel type as a
percentage of total sample generating capacity.
Table 2 shows the emission control capabilities of the sample units. Over 905
of the units incorporate some form of particulate control device, with the
electrostatic precipitator the overwhelming choice. Over half of the units are
equipped with overflre air capability for N0X control. This method for
controlling NO , which lowers the flame temperature by burning the fuel in
two stages, has proven to be both successful and economical on units equipped
with tangential burners. Only about 29* of the sanple units art equipped with
flue gas desulfurlzatlon capability. As can be seen from Table 2, thore ar*
many processes available for removing SO? from flue gas, with limestone
scrubbing being the most frequently selected method In this^sarnple. Of 52
units incorporating some type of FGD., only two wtre ordered'before 1970.
GENERIC PROCESS DESIGN AND ECONOMICS
From the sample of C-E coal-fired units described above, three candidate
retrofit units were selected 1n the 200 MWe, 400 MWe, Mid 600 MWe size ranges.
All three units bum high sulfur Midwestern bituminous coal, are equipped with
ESP's and do not presently have FGD capability. At present, work is in process
to define the boiler modifications and additional equipment required to
retrofit these units for dry injection S0X control. In addition, six new
units in the same size ranges (three high sulfur coal, three low sulfur coal)
are being evaluated to determine the added costs of Incorporating dry sorbent
S0X control.
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Following the completion of the generic process design for these new and
retrofit units, detailed cost analyses will be carried out to determine the
economic viability of LIM8 as a S0X control option. The results of these
economic analyses will be reported at a later date.
ACKNOWLEDGEMENTS
This work is supported by the EPA under Contract 68-02-3915. David S.
Lachapelle is the EPA Project Officer.
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12. Jonakln, J., and Martin, J., "Applications of the C-E Air Pollution Control
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13. Martin, J. R.t Taylor, W. C., and Plumley, A. L., The C-E Air Pollution
Control System," presented at the 1970 Industrial Coal Conference,
Lexington, KY, April 1970.
14. Attig, R. C., et al., "Additive Injection for Sulfur Dioxide Control - A
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15. Hein, K., and Glaser, VI., "Dry Additive Process for SO, Removal During
the Combustion of Brown Coals," Sixth Members Conference, Advanced
Combustion Technology, Noordwljkerhout, May 1980.
16. Schiffers, A., and Htin, K., "The Use of Dry Additives for Improving the
Emission Behavior of Lignite (Brown Coal) Firing," translated for EPA by
Literature Research Company, Annandale, VA, 1980.
17. Energy and Environmental Research Corporation, "Use of Sorbents to Reduce
Sulfur Oxide Emissions from Coal Combustion," presented at EER, Maiy 1983.
18. Tokuda, K., et al., "Evaluation of Tangential Fired Low-NO Burner, Phase
IT, Furnace Limestone Injection," Final Report for EPRI Research Project
1836-1, July 1983.
19. Goetz, G. J., and Mlrolli, M. 0., "Fireside Consequences of Furnace
Limestone Injection under Low-WL Conditions," Final Report for EPRI
Research Project 889-2, August 1983.
20. Blythe, S. M., "Dry Limestone Injection Test at a Low-Rank Coal-Fired Power
Plant," Final Report for DOE Contract No. AC18-80FC10200, November 1982.
21. Plumley, A. L., et al., "Feasibility of Furnace Limestone Injection for
S09 Control," Final Report for EPRI Research Project 1836-3, Septertser
1983.
32-13
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TABLE 1
Typical Coal Analyses
Eastern
Bituminous
Midwest
Bituminous
Sub-
bituminous C
Texas
L1on1te
Northern Plains
Lionit*
Total Moisture, 2
Ash, i
Volatile Matter, S
Fixed Carbon, t
Total 5
5.0
10.3
31.6
53.1
100.0
15.4
15.0
33.1
36.5
100.0
30.0
5.8
32.6
31.6
100.0
31.0
10.4
31.7
26.9
100.0
39.6
6.3
27.5
26.6
100.0
Btu/lb, as Fired
Btu/lb, Moisture
I Ash Free
13,240
15*640
10,500
15,100
8,125
12,650
7,590
12,940
6,523
12,050
Fusion Temperature
(reducing), °F
Initial Deformation (ID) 2,170
Softening (ST) 2,250
Fluid (FT) 2,440
1,990
2,120
2,290
2,200
2,250
2,290
2,075
2,200
2,310
2,027
2,089
2,203
Ash Analysis, S
5102
Al203
F«203
CaO
MgO
fla^O
K?G
T102
P2O5
SO3
Not Accounted For
40.0
24.0
16.8
5.3
2.0
0.8
2.4
1.3
0.1
5.3
1.5
46.4
16.2
20.0
7.1
0.8
0.7
1.5
1.0
0.1
6.0
0.2
29.5
16.0
4.1
26.5
4.2
1.4
0.5
1.3
1.1
14.8
0.6
46 a
15.2
3.7
16.6
3.2
0.4
0.6
1.2
0.1
12-. 7
0.2
23.11
11.29
8.48
23.75
5.87
7.38
0.70
0.45
17?69
1.28
Sulfur, S
1.8
3.2
0.34
0.6
0.75
Lb Moisture/10® Btu
Lb Ash/10« Btu
Lb Sulfur/10® Btu
Base/add Ratio
Hardgrove Srindabllity
3.8
7.8
1.36
0.426
55
14.7
14.3
3.05
0.473
56
36.9
7.1
0.42
0.784
43
40.8
13.7
0.79
0.392
48
60.7
9.7
1.15
1.33
25*
(•) With 39.6S mo1 Stuff at pulverizer Inlet, rang* 1s 20-50.
32-14
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TABLE 2
Number of Units Installed with
Air Quality Control Systems
Particulate Control
Fuel Gas Desulfur1zat1on
N0X Control
NO. OF UNITS % OF TOTAL
Electrostatic Precipitator 146
Wet Scrubber 7
Fabric Filter 12
Mechanical Cyclone Collector i
Total 166 93
Limestone 22
L1me 11
L1me/L1mestone 4
L1me/Alkal1 Flyash 9
Double Alkali 1
Sodium Carbonate 1
Lime/Spray Drying 4
Total 52 29
Overflre A1r 91
Total 91 51
32-15
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WMMIUTUW. V
Figure 1 Effect of furnace atmosphere on dissociation
of CaC03 (Ref. 5).
i*
Mawamet rtm • «a* sac
s
Figure 2 Relation between SO2 removal and Ca/S
molar ratio {Ref. 18).
32-16
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PHMH,
Figure 3 Limtstone preparation and injection sy«tam (Raf. 21).
«
40
a
MTt
U
u
MWUMUTM
Figure 4 Comparison of SOj removal rata with various mathodi
of injaetion (high-sulfur coal) ( Raf. 18).
32-17
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N. PLAINS
.LIG.
TEXAS
LIG
SU8BIT-
68IT-
MW
BIT
58
SO
40 -
a
a
a
a
a
a
o o _
a a a
a
a a a
§
a
a
BOO
o B a B
o a g g o
a
o a a a
a a
B 0
B B | a | | |
B
62
68 70
CONTRACT YEAR
T
74
a a
78
Figure 5 Coal rank vs. contract yaar
82
3
3
z
u
u
c
Ui
a.
30
20
10
MW BIT
East bit
subsit
COAL RANK
-EZ£Z2
. TEXAS UG N PLAINS
LIG
Figura 6 Distribution of total generating capacity by coal
rank (Total MW -96,322).
32-18
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WALL-FIRED BOILER DESIGN CRITERIA FOR DRY SORBENT
S02 CONTROL WITH LOW-NOx BURNERS
R. K. Mongeon
Riley Stoker Corporation
Worcester, Massachusetts
and
J. P. Mustonan
Stone & Webster Engineering Corporation
Boston, Massachusetts
and
D. 6. Lachapelle
U.S. Environmental Protection Agency
Triangle Park, North Carolina
abstract
Limestone injection multistage burner (LIMB) technology is being actively investigated aa a potentially
economical and attractive means of reducing SO2 and NOx emissions in coaMired boilers. Although primary
emphasis is on the retrofit potential for existing boilers that mi not currently equipped with scrubbers,
application to new boilers is being investigated as well.
This paper concentrates on LIMB technology for new and existing coal-fired power stations and also
discusses historical and projected design trends which have an effect on it. Advantages and disadvan-
tages of various LIMB methods are discussed, including the effect on steam generator design criteria.
A suggested approach ia developed, and its ramificationa on the boiler and the balance of plant design
are discussed.
INTRODUCTION
injection of dry sor&ents into the furnace area of steam generating units is not a new technology. Many
years ago, limestone was injected in an attempt to reduce low temperature corrosion and high temperature
fouling in the convection passes of steam generators.' While it may have helped, it was expensive and
its use was not widespread.
More recently, during the late 1960s and early 1870s, limestone injection was evaluated for removal of $02
from the products of combustion.J > Removal efficiencies varied from 15 to SO percent. However, the ma-
jority of cases averaged about 20 percent SO2 removal. Teats were run on horizontally fired, vertically fired,
and tangentially firms units during this period. Limestone was generally introduced into the furnace with
the fuel, although injection above the burners was also tried on a wail-fired unit. Some of the problems
encountered included "deadbuming" of the sorbent (thermal deactivation) along with fouling of the con-
vective paaaes and loas in electrostatic precipitator removal efficiency. The programs were abandoned
but, with the advent of low-NOx burner technology, were revived around 1979.
Low-NO x burner technology stages the combustion process, producing iower flame and gas temperatures
in the lower portions of the furnace. U.S. Environmental Protection Agency (EPA) pilot scale tests con-
ducted around 1979 indicated the possibility of 70 percent removal of SO2 with limestone injection through
33-1
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low-NOx burners at reasonable Ca/S molar ratios. In 1980, the EPA initiated it's limestone injection
multistage burners (LIMB) program to identify the process variables that resulted in the high capture observ-
ed in the pilot scale studies. The program's objective is to develop LiMB and low-NOx burner technology
for both retrofit and new applications.
BACKGROUND
Riley Stoker Corporation conducted a survey of its pulverized coal-fired utility boilers greater than 100 MWe
sold during the last 25 years. Riley has constructed two basic types of wall-fired boilers during this period:
one conforms to the wall-fired configuration for the general boiler industry and the other is a unique type
designated the Riley TURBO* furnace. These design types are illustrated in Figure 1 for comparison. Wall-
fired units can have burners installed on either or both of the front and rear waterwails and also on one
or more levels, in contrast, the Riley TURBO furnace always has burners installed aa opposed pairs and
at one elevation. The survey was directed at compiling general design and operational parameters, including
but not necessarily limited to:
• Boiler population as a function of start-up year and coal rank
• Operating characteristics
• Boiler design trends including furnace geometry and heat releases
• Slagging and fouling characteristics
• Impact of NOx control
The general trends noted during this survey indicate that the period from 1965 to 1970 contains the units
with the least amount of overages or leeways in design. Units were physically smaller and heat release
volumes and rates were higher during this period. Also, the majority of units were designed for pressuriz-
ed operation. The costs of induced draft fans and their associated controls were eliminated on pressuriz-
ed units. By the mid-1970s, this trend had reversed, and nearly all units designed for coal firing were for
balanced draft operation.
Figure 2 shows a plot of unit capacity versus start-up year. The unit capacity is in pounds of steam per
hour, and there is a definite trend to increasing steam capacities up to 1970 where it has leveled off. There
are a number of reasons for this, including the drop-off in supercritical unit designs and the switch to
oil- and gas-fired units for the larger capacities.
Another consideration for the leveling off of the unit capacities is the advent of nuclear power. During
the 1970s, nuclear units coming on line would handle the base load capacity requirements of the utilities.
This left cycling and peaking type boilers, which were generally smaller in capacity than base loaded cen-
tral station units, to meet the peak load demands.
Volumetric heat release rate has been plotted in Figure 3 for both Riley designed units and the general
boiler population. The volumetric heat release rate is defined aa the gross heat input to the furnace divid-
ed by the furnace volume (sea Figure 4). The volumetric heat release rate is used as an indication of availabili-
ty of space to complete the combustion process. Both trends are similar and show a gradual increase
in heat release rate until approximately 1970 when the value started coming down in magnitude.
The effective projected radiant surface (ERRS) is calculated by creating an imaginary plane through the
center line of waterwail and radiant superheater tubes. The flat surface is then calculated considering both
sides of the plane on radiant superheater or waterwail platens and the furnace side of the waterwails pro-
per. The heat release rate on a square foot of effective projected radiant surface, shown in Figure 5. follows
the same trend aa volumetric heat release. There is a tendency to increase during the 1960s and to taper
off during the 1970s. While part of this reduction can be attributed to air pollution requirements, the re-
mainder can be explained by the reductions in coal quality. Lower rank Western sub-bituminous coals are
low in both heating value and sulfur content, and more units are being designed for these coals during
the 1970s.
Coal rank can affect many parameters in boiler design. During the 1960s and early 1970s, bituminous coal
was used for the bulk of units designed for solid fossil fuel firing. During the middle and late 1970s, Western
subbituminous and lignite coals permeated the market to the point that they represent approximately 50
33-2
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percent of the coals used for new designs during that period.
Furnace exit gas temperatures have not changed significantly between the various ranks of coal. As shown
in Figure 6, the furnace exit gas temperature range is plotted against the type of coal used in Riley Stoker
designs. The predominance of the data is between 1900 and 2000" F. Part of the variance is due to an effort
to maintain the furnace exit gas temperature well below the ash softening temperature of the coal. (Riley
Stoker does not have any pulverized lignite fired units so lignite is not shown in Figure 6.)
In the early 1970s, government regulations for air quality control forced a turnaround in the size of the
furnaces. Ouring that period, one of the first methods of NOx control was to lower peak temperatures in
the flame zone, requiring larger furnaces to cooi the combustion process and complete burnout of the
fuel. This resulted In a decrease in heat release rates and furnace exit temperatures.
Currently, there is essentially no new fossil fuel utility boiler construction. When the utility industry does
pick up, it is expected that the trends that were observed in the late 1970s will continue. Units will be
of moderate size due to high interest rates and a slowdown in the growth rate of load demand.
The remainder of this paper discusses the approach to achieving both low-NOx and iow-S02 emissions
using LIMB technology (see Figure 7). The effect on the boiler and the balance of plant equipment associated
with the limestone injection technology is also discussed.
APPROACH
The goal of the ongoing EPA-sponsored UMB program is to develop in*fumace sorbent injection combin-
ed with low*NOx burner technology leading to industry demonstration and commercialization of LIMB
technology in the near term. In consideration of this, specific UMB objectives include a 50 to 80 pereent
reduction from uncontrolled levels of both SO2 and NOx in retrofit applications. Objectives for new UMB-
equipped plants would include a 70 to 90 percent reduction in SO2 and a 70 to 80 percent reduction in
NOx in retrofit applications from uncontrolled levels. These objectives are believed to be achievable with
LIMB alone in the retrofit case and LIMB in combination with additional sulfur removal technology (if re*
quired) for new units.
LIMB appears to be particularly attractive since it is not space, hardware, or maintenance intensive and
is therefore retrofittabie to many existing plants at a fraction of the cost of scrubbers. Costs are expected
to be at least SlOO/kW less than for scrubbers.* UMB cost predictions to date have varied from ten to fifty
pereent of scrubber cost.'-1-'
Much basic research and pilot scale work has been and continues to be done toward the achievement
of these objectives, and a full scale utility demonstration project is scheduled to commence late this year
with start-up in late 19%.
Various configurations of UMB-equipped plants have been conceived to meet the SO2 and NOx removal
objectives discussed above at a cost significantly leas than that of scrubber-equipped plants. Significant
variables affecting plant design include:
• Boiler/firing configuration
• Burner design for low NOx
• Coal type/sulfur content
• Sorbent type/size
• Calcium-to-sulfur molar ratio
• Time/temperature requirement for sorbent/S02 reaction
• Sorbent injection method
• Slagging/fouling/erosion potential
• Ash loading and resistivity
• Ash constituents' effect on disposal
Discussion in this paper is directed toward utility size pulverized coal boilers equipped with low-NOx burners.
Effects of various coal sulfur contents are discussed where they we expected to have a significant impact
33-3
-------
on UMB design. The sorbent considered is high calcium limestone with caicium-tosuifur molar ratios rang-
ing from approximateiy 2 for high sulfur coal to 4 for low sulfur coal, where a higher percent sulfur capture
is feasible. Limestone is finely ground and pneumatically introduced in the furnace separate from the coal.
Soot blowers are provided as necessary for control of fouling. Existing particulate removal equipment is
expected to be maintained on retrofit application. Because of increased ash loading and increased ash
resistivity, modifications such as added mechanical collectors, precipitator renovation/expansion, and/or
flue gas conditioning will be required on many applications with older precipitators. New units are ex-
pected to be equipped with fabric filters. Ash must be handled dry to avoid the cementitious characteristics
of the alkaline material when wetted, and ash disposal will be complicated by the increased ash quantity
and unknowns relative to LIMB ash disposal requirements.
EFFECT ON BOILER
The heart of the UMB system is the low-NOx burners and the sorbent injection system. Low*NOx burners
are generally designed with combustion air added in a staged manner, ensuring a fuel-rich zone early in
the combustion process. This chemically reducing zone tends to lower NOx production from oxidation
of the nitrogen in the fuel and combustion air. Figure 8 illustrates a Riley Stoker tow-NOx burner concept
and shows how combustion air is added in a staged sequence with the coal. This burner, which incor-
porates tertiary air ports for staging, was designed according to criteria developed under EPA low-NOx
burner demonstration programs. Although not shown in Figure 8, the coal nozzle incorporates the same
venturi discharge section and conical coal spreader as that used in a retrofit low-NOx burner design called
the Controlled Combustion Venturi (CCV) burner.1
The CCV burner is shown in Figure 9. The design is very similar to pre-NSPS equipment (single-register
flare burner) with the exception of a smaller diameter modified coal nozzle and spreader. The round coal
nozzle discharge was modified to include a venturi section while the original multi-vaned coal spreader
was replaced with a four-bladed conical shaped spreader. Both the spreader position and the nozzle set-
back position can be adjusted during operation. These modifications produce the mixing and combustion
characteristics necessary for low-NOx. Figure 10 shows the flame shape produced by the CCV burner as
compared to the flame shape typical of the pre-NSPS (flare type) burner. The CCV burners have been retrofit-
ted to existing units, with test results showing a 50 percent reduction in NOx levels achieved with accep-
table unit performance.
New unit designs could incorporate the CCV burner with tertiary air ports installed to get even greater
reductions in NOx levels based on uncontrolled measurements with pre-NSPS burner equipment.
The use of tertiary air ports or overfire air ports with low-NOx burners provides alternate locations for in-
jection of the sorbent. As mentioned previously, initial work with sorbent injection showed low SO2 cap-
ture due to sorbent deactivation. This occurred when the sorbent, which was injected directly with the
fuel, reached high temperatures and sintered, forming a hard crust which prevented the SOj from reaching
the sorbent pores and reacting. With injection through tertiary or overfire air ports, the limestone particles
are allowed to cross the flame without crossing the highest temperature zone.* This aids in producing
inert calcium compounds which can be removed in a particulate collection device and disposed of in an
environmentally acceptable manner. These calcium compounds sre formed in proportion to both sulfur
content in the fuel and calcium-to-sulfur molar ratios for the sorbent injection process.
Figure 11 shows a conceptual view of the UMB process. The limestone is calcined rapidly to lime which
then combinea with SO2 to form calcium sulfate. The chemical reactions are shown in the following
equations:
CaC03—CaO + CO2 (1)
CaO * SO2 + Vi O2—CaS04 (2)
The sorbent should be in the gas temperature regions above approximateiy 2200* F for a very short period
of time to prevent deactivation or deadburning. Conversely, the limestone will only minimally calcine below
approximateiy 1400*F. The optimum then is to produce sufficient residence times in the 2200*F to 1400'F
temperature zone within the boiler.'* This temperature zone usually occurs between the entrance to the
radiant superheaters to a point approximately half way through the convection passes of the boiler, as
33-4
-------
noted in Figure 12. Typical residence times in these areas are from 1 to 2 seconds, depending on the unit
design, the slagging and fouling characteristics of the fuel being burned, the erosion and corrosion tenden*
cies. and fan capabilities. Some units, especially in the mid to late 1960s, were being designed in a very
competitive market, and fewer leeways were incorporated in an attempt to Keep costs down.
New unit designs are more conservative with larger furnaces and lower heat release rates to accommodate
low-NOx burner requirements. Also, the use of Western subbituminous fuels with their inherently high
ash content has necessitated wider tube spacings and lower velocities through the tube bundles. New
unit designs lend themselves well to the sorbent injection technology.
The calcination reaction is endothermic, which means that the process will absorb heat during the reac-
tion. The heat required for calcination of pure limestone is approximately 2,000 Btu/lb. The sulfation pro-
cess is exothermic and releases approximately 4,000 Btu/lb of lime (CaO). However, only about V4 lb of
CaO is produced for every 1 lb of limestone, and only 25 percent of this is sulfated. This can result in a
small energy penalty and reduce overall flue gas temperatures slightly.
Based on a 10* Ib/hr steam boiler with turbine conditions of 1000/1000* F and 2400 psi throttle pressure,
approximately 25,800 Ib/hr of limestone is required, based on a high (3.4 percent) sulfur Midwestern
bituminous coal, to produce a Ca/S molar ratio of 2. The basic quantities for these conditions are tabulated
below. It is readily apparent that the ash quantities passing through the unit under these conditions are
more than doubied.
Note: Coal fusl—10,650 Btu/lb HHV
3.4% S
8.4% Ash
This high aah quantity can affect heat transfer within the boiler in different ways. High ash loadings can
affect flue gas emissivities as well as physically blocking radiation whioh might normally go to the water*
walls. In sddition, the added particulate loading may increase slagging tendencies within the furnace. This
slag layer can reduce the heat absorption in the waterwalis, preventing absorption in the generation side
of the steam process. Field tests performed approximately 15 years ago did not reveal any significant pro-
blems due to slagging because of the addition of sorbent injection. However, there is only a limited amount
of data, and some questions have been raised as to whether or not the units were on line long enough
to produce slagging problems. More information is needed to be able to predict the slagging tendencies
of various coals with sorbent injection with any degree of certainty.
The Increaaed flyash quantities produced by sorbent injection can also affect fouling tendencies of the
fuels. Again, the results of the field tests some 15 years ago are inconclusive, showing influences of
limestone injection on fouling from slight to severe. Some of the deposits were hard and difficult to remove
while on other units there were more deposits but they were softer in nature and easily removed. In general,
however, fouling deposits are increased because of the increase in particulate flowing over the convec-
tion surface. For existing units, increased numbers of soot blowers, increaaed blowing pressures, or in-
creased blowing frequency may be needed to handle increased ash flows. For new units, the tube .spacing
in a transverse direction from side to side cm be incressed, preventing the fouling buildups from plugging
the convection passes by bridging over between the various assemblies of tubes. While increased tube
spacing will not prevent fouling, it does allow more time between soot blowing cycles so that the gas
flow lanes can be kept open (see Figure 13).
Erosion tendencies are increased with the higher loading of particulate in the flue gases. For existing units.
Basic Quantities
Main steem flow
Reheat steam flow
SH/RH outlet steam temperature
Turbine throttle pressure
Fuel flow
Fuel ash flow
Sorbent flow
1,000,000 Ib/hr
853,900 Ib/hr
1005*F
2400 psig
128,000 Ib/hr
10,750 Ib/hr
25,800 Ib/hr
33-5
-------
this can be troublesome because of the difficulty in altering heat recovery surface spacing and configura-
tion while stilt maintaining adequate heat transfer surface to perform the required duty. Shields can be
installed on tubes but these are only a temporary stopgap and the erosion will continue, making the shields
a maintenance item. For new units, the designs can incorporate wider tube spacings or increased depth
of the gas passages to bring flue gas velocities down to a safe level. Below 3600 ft/min, erosion tenden-
cies are generally negligible based on the design of the unit and the turns which the flue gases must make
before entering a bank of superheater, reheater, economizer, or other heat recovery tubes.
The increased particulate loading also has an adverse effect on air preheaters. The tight spacing of preheat er
baskets can lead to pluggage because of the increased dust loadings. More material is deposited on the
plates, and bridging between the heat transfer elements is increased. As with the convection passes, part
of this pluggage can be attributed to a lowering of the ash sintering temperature by the sorbent ash particles.
Bottom ash quantities and bottom ash removal may not be adversely affected by sorbent injection. In
general, the limestone will be injected around or above the burners aod conceivably in a much finer size
than pulverized coal. It is expected that this small, lighter material will be swept upward with the flue gases,
especially if injected above the burners through overfire air ports, and not increase the amount of ash in
the bottom of the furnace hopper.
A complementary technology that may substantially decrease the concerns about particulate flows from
the UMS process is coal cleaning. This process, one study of which is now underway at EPRI's Waltz
Mill facility, can substantially reduce the ash and sulfur content of the coal fuel. Ash and sulfur removals
of 70 and 30 percent, respectively, have been reported. These reductions tend to cancel out the additions
to solid waste flows associated with sorbent injection."
EFFECT ON BALANCE OF PLANT
Sorbent Handling
One of the major impacts of retrofitting UMS to an misting plant is the need for a sorbent handling system.
Based on the 10* Ib/hr boiler discussed earlier, which burned 3.4 percent sulfur_ coai with a Ca/S molar
ratio of 2. approximately 25,800 Ib/hr (as limestone) is required at the boiler. Although optimum sorbent
selection criteria, including grind size, are the subject of continuing research, it is expected that a high
surface area (i.e.. high reactivity) stone will be required, finely ground to approximately 90 percent passing
through a 325 mesh screen.
It is expected that most retrofit plants would receive the sorbent by truck. It would be stored in a pile
with a roof over it to prevent unnecessary moisture contamination. Depending on the as-delivered size
and moisture content of the stone, it may then require crushing to an intermediate size (3/8 to 3/4 x 0 in.)
and drying prior to final fine grinding. Candidate mills for pulverization include ball, roller, high speed ham-
mer, attrition, and pin mills. Grinding power to produce a finely ground product such as 20 mm mean size
will be high. Agglomeration of finely ground sorbent accompanied by its adherence to inner mill surfaces
and consequent reduced mill efficiency, is a known problem. If an extremely fine sorbent is necessary,
it may become appropriate to consider other grinding techniques.
Following final milling, the sorbent would be stored in one or more outside day silos and would be
pneumatically injected into the furnace. The pneumatic system is expected to be dilute phase with fairly
high injection velocities to promote adaquate penetration and dispersion within the furnace.
Special care would have to be taken with the design of equipment handling the finely ground product
because of its agglomeration tendencies. Silos, for example, would be mass flow design with slot bot-
toms to prevent bridging. Heating would be provided where necessary to prevent condensation. For ex-
tremely fine sorbent, it may be better to directly inject the product as it leaves the mills to avoid silo storage.
It is expected that new units would have similar sorbent systems. Some units would have provisions for
rail or barge delivery of sorbent, and portions of the receiving facility might be used in common with the
coai handling system.
33-6
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Particulate Removal
A second major impact of retrofitting LIMB to an existing ptant is a markedly increased flue gas particulate
loading. For the 10' Ib/hr steam boiler discussed earlier, the flyash load increased by a factor of 2.4. This
assumes a finely ground sorbent, essentially all of which is entrained in the flue gas. Although flyash par*
tide size distribution is expected to change very little, earlier tests' have indicated increases in resistivity
by about two orders of magnitude. These factors present problems for older installed precipitators, most
of which have specific collecting areas (SCAs) well below 400 ft'/lOOO acfm. Many of these units would
require renovation, expansion, and/or flue gas conditioning to maintain effective particulate removal.
It is believed that SO3 injection can effectively reduce resistivity to manageable levels on retrofits. There
are also several older plants that have recently been retrofitted with larger precipitators. These units may
be able to handle increased UMB ash loading without conditioning and without major modification. The
use of cleaned coal together with UMB could prove to be an economical retrofit solution in precipitator'
limited eases.
N«w unit applications are expected to favor the use of fabric filters which would be insensitive to the in-
creased resistivity. Fabric filters could also see application on some retrofits in combination with an ex-
isting precipitator, should this approach prove economically attractive.
Ash Handling and Removal
The increased fly ash loading affects the ash handling equipment of the particulate removal device as welt.
Necessary modifications to this system on a retrofit may include larger size and/or increased number of
precipitator hopper ash removal lines and increased capacity pressure or vacuum producing equipment,
including any added support facilities/systems required. Larger or added ash silos would be required, as
well as provision for dry handling of the alkaline ash because of its cementitious properties.
Since essentially all sorbent injected into the furnace is expected to be entrained in the flue gas. the bot-
tom ash system should see minimal impact. Any sorbent in the bottom ash is expected to be sintered
and relatively unreactive; however, bottom ash sluice/pond water pH would require scrutiny, and suitable
pH controls should be installed, If necessary.
The ash disposal site envisioned would consist of a property designed landfill, although possibilities for
commercial use of the product (e.g., as an aggregate fill) exist as welt. Although there is little data on hazards
associated with UMB ash disposal, it has been found that ash in alkaline matrices, including fluidized
bed combustion ash and dry scrubber ash has, in general, not presented hazardous leschste problems.
More research may be neceaaary to resolve this issue for UMB.
As in the ease of the particulate removal equipment, the use of lower ash content or cleaned coai would
help reduce the impact of LIMB on the ash handling system by reducing overall ash quantity.
Sorbent Postcombustion Treatment
In order to achieve 70 to 90 percent SO2 reduction, as required by NSPS on new units, UMB (in combina-
tion with additional sorbent post combustion treatment devices) may be necessary. With this configura-
tion, UMB would capture the majority of the SO2 in the furnace and provide a highly reactive calcined
sorbent product in the flyash thst could be effectively used by a downstream device such as a spray dryer.
It is anticipated that the flyash would be caught in a mechanical collector, slurried, and sprayed into the
absorption chamber of the spray dryer where about 80 percent or more capture of the inlet SO2 is possible.'3
A fabric filter would be used for final particulate removal, and this could contribute tb another 5 to 20 per-
cent inlet SO2 capture.
The combination of these SO2 capture techniques would result in the NSP8*required 70 to 90 percent SO2
reduction in what is expected to be a cost-effective manner. The system couid be optimized by bypassing
a portion of the flue gas stream around the spray dryer to the extent that the required SO2 capture is achiev-
ed. This would reduce spray dryer costs and avoid the need for flue gas reheating. Operating costs are
33-7
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expected to be comparatively low because the equipment is relatively uncomplicated and the sorbent
(assuming limestone) cost is low.
Soot Blowing
As discussed earlier, LIMB retrofits are expected to require additionai soot blowers to control fouling.
Also, the required blowing pressures and blowing frequencies may have to be increased. Either air or steam
soot blowers may be used. If air is the selected medium, new soot blowing air compressors and distribu-
tion systems would be required at many installations. Steam soot blowing may prove to be a more
economical solution in many cases.
COST
EPRi has estimated the incremental cost of UMB on new units equipped with fabric filters to range from
$15 to S3Q/kW, depending on coal sulfur content and Ca/S molar ratio.* Retrofits could cost two to three
times as much to account for upgrading of soot blowing, precipitators, and ash handling and disposal
systems. EPRI estimates 30-year, levelized operating costs of 3 to 12 mills/kWh, depending on coal sulfur
content and required Ca/S molar ratio.
More detailed cost estimates are currently being prepared by the authors of this paper and others on behalf
of the EPA. These estimates will address a wide range of utility plant sizes, both new and retrofit, with
high and low sulfur coals. It is expected that these estimates will confirm that the cost of UMB will be
at least S100/KW less than that for scrubbers.
CONCLUSIONS
Sufficient field information is not available on sorbent injection to determine its effectiveness as a viable
means of reducing air pollutants. Pull-scale demonstrations of the sorbent injection process using various
coals, sorbent s, and boiler designs, could provide this information.
An area of concern is not whether sorbent injection can remove SO2 before the flue gases discharge into
the atmosphere from the stack, but rather how much of the SO2 can be removed. This paper has noted
various areas which must be considered in any sorbent injection installation. These include sorbent handling
and injection, fouling in the convectlve passes and air preheaters. particulate removal in electrostatic
precipitators or fabric filters, and disposal of the products of combustion and sorbent injection. Although
these concerns are significant, the alternatives to sorbent injection for SO2 removal may be more costly
and present more problems. UMB technology offers the potential for low cost reductions in NOx and SO2
in response to acid rain concerns, and this should be evaluated carefully for both retrofit and new units.
AKNOWUEDGEMENT
This work is supported by the U.S. Environmental Protection Agency under Contract 88-02-3912.
O.G. Lachapeiie is the SPA Project Officer.
33-8
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REFERENCES
1. Attig, R.C. and Sedor, P. "Additive Injection for Sulfur Dioxide Control • A Pilot Plant Study,"
Report APTD 1176 (NTIS PB 226761), March 1970.
2. Plumley, A.L, Jonakin, J., Martin, J.R., and Singer, J.G. "Removal of SOj and Dust from Stack
Gases." Presented at Southeastern Electric Exchange, Richmond, Virginia, April 1968.
3. Gartrell, P.E "Pull-scale Desulfurlzation of Stack Gas by Dry Limestone Injection, Volume I,"
EPA-650/2-73-019a (NTIS PB 228447), August 1973.
4. Drehmei, D.C., Martin, G.B., and Abbott, J.H. "Results from EPA's Development of Limestone
Injection into a Low NOx Furnace." In: Proceedings: Eighth Symposium on Flue Gas
Desulferization, New Orleans, LA, November 1983, Volume 1, EPA-600/9*84-017a (NTIS PB
84-226638), July 1984.
5. Drehmei, D.C., Martin, G.B., Milliken, J.O., and Abbott, J.H. "Low NOx Combustion Systems
with SO2 Control Using Limestone." Presented at the Annual Air Pollution Control Associa-
tion Meeting, June 1983.
6. Electric Power Research Institute (EPRI). R&D Status Report. Coal Combustion Systems Divi-
sion, EPRI Journal, March 1984.
7. Andes, G.M., Becker, D.F., and Klett, M.G. "Capital and Operating Costs for Retrofitting UMB
Equipment to Coal-Fired Power Plants." Presented at the Joint Power Generation Conference,
October 1984.
8. Usauskas, R.A. and Rawdon, A.H. "Status of NOx Control for Riley Stoker Wall-fired and
TURBO-fired Boilers." Presented at the EPA/EPRI Joint Symposium on Stationary Combustion
NOx Control, November 1982.
9. Flament, G. "The Simultaneous Reduction of NOx and SO2 in Coal Flames by Direct Injection
of Sorbents in a Staged Mixing Burner." International Flame Research Foundation Research
Report G 19/a/lO, September 1981.
10. Payne, R., Case. P.L, Heap, M.P., and Pershing, D.W. "LIMB Testing: The Use of Dry Sorbents
to Reduct Sulfur Oxide Emissions from Pulverized Coal Flames Under Low-NOx Conditions."
Presented at the Joint EPA/EPRI Symposium on Stationary Combustion NOx Control,
November 1982.
11. Larson, J.W. "Burner Developments to Meet Potential Acid Rain Reduction Requirements,"
Presented to the Committee on Power Generation, Association of Edison Illuminating Com-
panies, April 1984.
12. Doyle, J.B. and Jankura, B.J. "Furnace Limestone Injection with Dry Scrubbing of Exhaust
Gases." Presented to the 1982 Spring Technical Meeting of the Central States Section of the
Combustion Institute, March 1982.
33-9
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Figure 1. Riley Coal-fired Boiler Designs
— SURVfV W GtNPUl COAl-FtflfO BOlUft POPULATION
(WWW MMAZINC. PUNT OESKM. IMU£S 19M TO t«1»
• «lev oisignio coAi-nmo units
«o u 70 n 10
STARTUP YEAR
Figure 2. Steam Capacity vs. Startup for Riley Wail-fired Units
33-10
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2 SUtVfr OF GENOA MILE* HORUUA
•
-------
10.01
I
I
3
3
a 5-0-4
2
M
S.O-
2-0'
U
«
A)
STARTUP YEAR
S
Figure S. EPRS Heat Release Rate vs. Startup Years for Riley Wail-fired Units
bituminous - a
TV* OF com
BITUMINOUS <
SUBBITUMINOUS
Figure 6. Furnace Outlet Temperature vs. Type of Coal for Riley Oesigned Units
IM
Figure 7. LIMB System Schematic
33-12
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PWOAATtD
MOisTin
OAUHM
ftifilSTl*
lUKNIft _
NOZZkl
•umnin .
WATS* WALL SVMM«rmeAL
ABOUT CiMtlM UNI
fir TtRTlAAY
ami row
IIP MO B)
Figur® & Riley Stoker Distributed Mixing Burner
wintuhi Noma w
«4uon comeAk coal spnmoin
Figure 9. Riley Stoker Controlled Combustion Venturi (CCV) Burner
33-13
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*u*«-TrPt auftNt*
eoNmeun csimustion v«ntu« ki**m
Plgura 10. Typical Plame Shapaa
(MISSION CONTROL TtCMNOLOOV
Honcuwri actum now »»«ncu mactivatiq* «awwi
Flgur# 11. Umaatona Transformations in a Pulverized-Coai Flame
33-14
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a 1N'-0* . KHIAm ( SUKMCATO
TWmilAl hcamd twos
1 . b*t
MOUNT i
SUPfMfATO
1400**'
ato'f
mliy ounin uivntftw
Figure 12. Approximate Temperature Zone for Optimum Sorbent Reaction
33-15
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ioao „„
•oo
400
s
s
so
I
= 4»
10
10
SMM
to
moo "3
Wit OAS TtMflSUIUM.
IOO OOO aoo
Figure 13. Tube Bundle Clearance vs. Flue Gas
Temperature for Oifferent Fouling Potential Coats
33-16
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ORY SORBENT EMISSION CONTROL PROTOTYPE
CONCEPTUAL OESIGM ANO COST STUOY
0. T. Gallaspy
Southern Company Services, Inc.
Research and Development Department
P. 0. Box 2625
Birmingham, Alabama 3S202
ABSTRACT
The Ory Sorbent Emission Control (DSEC) program conducted by the Electric Power
Research Institute (EPRI) 1s aimed at developing the DSEC technology 1n three
successive steps: a fundamental pilot- and bench-scale test program, a prototype
or Intermediate-scale test program at a small production boiler, and a full-scale
demonstration at a 400-HW or larger utility boiler. The first step of this process
has been 1n progress since mid-1983 under the Joint sponsorship of EPRI and
Southern Company Services (SCS), Inc. One product of the current program 1s a
conceptual design and cost study for a one- to two-year prototype evaluation of
DSEC technology at a 40-HW utility boiler. This paper reports the results of the
prototype study, which 1s based on Gulf Power Company's Plant Scholz Unit 2. A
prototype design based on an evaluation of major process performance and
engineering Issues 1s described. Estimated capital and O&M costs for the prototype
are presented. A feature of the study 1s Its organization by process subsystems,
which allows a variety of test scenarios to be constructed. The projected capital
cost of an alternate test scenario 1s reported.
INTRODUCTION ANO BACKGROUND
W11W
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As a practical matter, some of these steps may be omitted 1n specific retrofit
applications because of technical, economic, or compliance considerations. Based
on development work by EPRI and SCS, low-NOx burners are not considered necessary
for In-furnace SO^ control. The implementation of post-furnace sodium Injection
requires that a baghouse be Included to achieve acceptable utilization of the
sodium-based sorbent.
The OSEC development program 1s aimed primarily at the Investigation of 1n-furnace
sorbent Injection as the major SCb~control step 1n the process. This emphasis 1s
reflected 1n the present paper. Tests of the sodium Injection step conducted by
EPRI at Public Service Company of Colorado's Cameo Station achieved SO2 removals
from 40 to 60 percent with trona at a Normalized Stoichiometric Ratio (Ha^:S) of
1 to 1.1. However, the use of sodium compounds 1s assumed to be constrained 1n an
Eastern application of OSEC because of waste disposal considerations.
0$W PrWftffl 99?crlpt;1ofl ^n
-------
aimed at quantifying the effects of a number of process parameters on 1n-furnace
sulfur removal. Parameters investigated to date have Included sorbent type,
calcium/sulfur ratio, limestone particle size, fuel type, t1me/temperature history
(through load and Injection location), jet mixing, and combustion zone
stolchlometry (staged combustion). The most Important conclusions from the
standpoint of the prototype design can be summarized under three headings: SO2
removal .efficiencies, time/temperature effects on calcination and sulfation, and
the influence of sorbent characteristics.
S0? Removal Efficiencies. The EPRI/SCS pilot work to date has indicated that a
calcium-to-sulfur ratio of 2.5 to 3 may be necessary to achieve 50-percent SOj
removal with limestone. For hydrated lime, removals of 50 to 60 percent are
possible at a Ca/S ratio of 2. Dolomite and dolomltlc hydrated Hme have
demonstrated higher calcium utilizations 1n the pilot tests, but these sorbents
offer no advantage over limestone and hydrated lime on a mass or sorbent cost
basis.
In order to meet a 50-percent reduction target, the Plant Scholz prototype design
1s based on a maximum calc1um-to-sulfur ratio of 3 with limestone for a coal
containing 3.S percent sulfur. The system designed on this basis 1s readily
adaptable to the handling of hydrated 11rae and prepulverized limestone. The
effects of high sorbent loadings on the boiler and Its auxiliaries, and Increased
capital and operating costs argue against designing the prototype system for feed
rates greater than Ca/S«3.
Time/Temp#ratur* Effects. The fundamental mechanisms which govern the capture of
sulfur dioxide by calcium 1n the furnace are still under Investigation 1n the
EPRI/SCS pilot program. However, 1t appears from work to date that there Is an
injection region 1n the furnace which maximizes the sulfur capture efficiency of a
given sorbent. For both limestones and hydrated limes, this maximum generally
occurs at Injection locations downstream of the flame zone corresponding to peak
injection temperatures between 1800*F and 2300*F. This effect Is Illustrated for
two limestones and one hydrated Hme 1n Figure 1.
While a full discussion of the phenomenon shown 1n tht figure 1s beyond the scope
of this paper, the following conclusions have a direct effect on the prototype
design:
• The primary mechanism of sulfur capture 1s through the reaction of
calcium oxide and sulfur d1ox1d« 1* the presence of oxygen rather
than through a reducing zone mechanism in the flame zone.
• For Injection at temperatures above 2300*F, loss of sorbent
reactivity (as measured by BET surface area) 1s very rapid due to an
Increase 1n the rate of sintering (merging of calcium oxide
crystals) as temperature Increases.
• The sulfation reaction 1s theraodynamlcally unfavorable above
approximately 2400*F; therefore, residence time above this
temperature does not contribute significantly to sulfation.
• At temperatures below approximately 1800"F, both calcination and
sulfation rates slow markedly. This 1s compounded by the fact that
useful residence time becomes very limited when s«rbent 1s Injected
below 1800*F (e.g., less than 1 second 1n the SRI combustor).
34-3
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• Between approximately 1800*F and 2300'F, tradeoffs among calcination
rats, development of sorbent reactivity, sulfation kinetics, and
useful residence time for sulfation determine an optimum calcine
utilization. The precise optimization point varies with sorbent
type and sorbent properties.
8ased on' these conclusions, the following design decisions were made for the Plant
Scholz prototype: (1) Sorbent will be Injected 1n the upper furnace (below
23Q0-24G0*F) for maximum SO? control. (2) Several Injection levels between
approximately 2400*F and 20C0"F will be Included to allow for optimization of
sorbent utilization over a range of boiler loads. (3) Lower-furnace injection
(Including Injection through the burners) will be excluded. (4) Low-NOx burners
do not appear to be necessary for optimization of sulfur capture and will not be
installed.
Sorbent Type and Properties. A range of sorbent-related parameters has been
investigated 1n the EPRI/SCS pilot program. The most Important parameters to date
have been sorbent type (e.g., limestone, hydrated 11me), chemical and morphological
properties, and particle size (particularly for limestones). With regard to
sorbent type, the ranking of various sorbents from higher to lower average calcium
utilization under similar conditions is as follows: hydrated dolomitlc I1»e,
hydrated lime (Ca(0H)2), dolomite, and limestone. (However, note that this 1s
also the ranking of the sorbents from higher to lower cost per mole of calcium).
Differences in performance due to chemical and morphological properties were found
primarily among limestones. For example, the two limestones shown 1n Figure 1
differ significantly In pereent Insolubles, grain size, degree of crystallinlty,
and initial surface area. Some of' the evident differences 1n performance are
apparently attributable to these factors.
Limestone particle size exhibits a strong effect on sulfur capture efficiency,
particularly as mass mean diameter (MMQ) falls below approximately 10 microns. In
a recent series of experiments, utilizations ranged from approximately 20 percent
to nearly 40 percent as the limestone particle mass mean diameter dropped from 15
microns to under 0.1 microns. From a practical standpoint, the cost of fine
grinding limestone undoubtedly becomes prohibitive at some mean particle size.
However, the ultimate tradeoff between grinding costs and process efficiency cannot
be fully evaluated without testing in the field.
In sum, sorbent-related parameters have implications for the design of a prototype
test facility. Ideally, such a facility should be designed for flexibility with
respect to sorbent type and properties. This includes the ability to receive and
test a variety of hydrated limes and limestones which vary 1n cost, geographical
location, and commercial availability. Because relatively few limestones are
available 1n prepulverlzed form, on-site pulverization equipment my be required to
test those limestones of most interest to utilities. On-site pulverization also
allows the tradeoffs between particle size effects and grinding eosts to be
evaluated at an appropriate scale.
Engineering and Operational Issue*
The true commercial potential of a process such as OSCC depends not only on the
process science but also on the engineering embodiment of the technology and the
effects of the process on power plant performance. The prototype facility
described in this paper 1s designed to allow the evaluation of the most important
engineering and operational issues from the processing and storage of sorbents to
34-4
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the disposal of the process waste product. These Issues Include the following:
• Reliability and operation of materials handling systems and the
Integration of these systems with boiler operation over a range of
boiler loads.
• Feasibility, cost, and reliability of limestone pulverization.
• long-term effects of furnace sorbent Injection on the boiler and Its
auxiliaries, particularly In the areas of slagging, fouling,
plugging, corrosion, and boiler efficiency.
• Effects of sorbent Injection on precipitator performance, and means
of compensating for the expected decrease In precipitator
efficiency.
• Effects of sorbent injection on baghouse performance, particularly
in the areas of baghouse pressure drop, filter cake characteristics,
cleaning cycles, and bag life.
• Characteristics of the DSEC waste product and evaluation of waste
disposal options with respect to feasibility and cost.
The decision to design the Plant Scholz facility to examine issues such as these
has several implications. First, there 1s the obvious effect on the scope and type
of equipment specified in the design. For example, the evaluation of on-site
limestone pulverization adds significantly to the prototype equipment list and
cost. Second, most of the issues mentioned above require an extended test period
for thorough evaluation. This in turn calls for the specification of process
equipment that will perform satisfactorily over the duration of the test period, as
well as adding to total project Q&M costs.
Another important factor addressed 1n the Plant Scholz prototype design is disposal
of the waste solids produced by the OSEC process. The waste resulting from dry
sorbent Injection has several characteristics that make It fundamentally different
from typical Eastern bituminous coal ash. These Include:
• High levels of alkaline compounds, Including large amounts of free
lime (CaO).
• Cementitlous behavior 1n contact with moisture.
• Relatively high water solubility of certain constituents.
The chemical and physical properties of the OSEC waste will vary depending on a
number of factors. General1y, the chemical properties are expected to be s1n1lar
to those of th« waste from i high-sulfur spray dryer application. The physical
properties are expected to be similar to those of high alkalinity lignitic coal
ash. As an example, the pH of the OSEC waste 1s expected to be above 10 and as
high as 13 depending on the level of available alkalinity. The mobility of metal
ions from the waste when placed 1n a disposal site will be a complex function of a
number of factors Including pH, coal composition, and free lime content, among
others. Post-furnace sodium injection further complicates waste disposal dut to
the high solubility of sodium compounds. Because of these characteristics of the
OSEC waste and the increasing emphasis on waste disposal regulations and
groundwater protection measures at the federal and state levels, landfill disposal
has been specified in the Plant Scholz prototype design. The disposal area design
34-5
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provides for Isolation of the sod1um-contaln1nq waste, a runoff ditch system and
holding pond, and a series of monitoring wells to facilitate evaluation of the
landfill disposal method.
SCS Prototype Test Experience
Finally, the prototype conceptual design reflects a test philosophy developed by
SCS through experience with several prototype test programs. One such program was
the evaluation of three F60 prototypes conducted at Plant Scholz during the
1970's. Two.major conclusions concerning test approach have emerged from these
programs." First, SCS's experience has demonstrated the advantages of specifying
test equipment whose performance and operation will readily scale to the next level
of development. The added Investment 1n capital cost can yield valuable process
Information that will reduce costs and development time 1n future process scale-ups
and provide meaningful data for the refinement of process economics. Second, SCS
experience points to the Importance of designing a test system for test continuity
and flexibility. Oeslgn short-cuts on the front-end of a test program may result
1n poor equipment reliability, poor data quality, or the Inability to change test
procedures as the test program evolves.
Summary af the Plant Scholz Design Approach
The previous paragraphs have provided some background on the design decisions made
for the Scholz prototype. The preliminary conclusions drawn from the OSEC pilot
work call for upper-furnace Injection of sorbent at multiple boiler levels and rule
out the necessity of low-NOx burners for SO? removal. The effects of sorbent
differences on SOj removal efficiency call for flexibility In receiving and
processing sorbent materials. Including on-site pulverization of limestone. The
importance of engineering and operational Issues for the success of the OSEC
process broadens the scope of the research program and dictates a process design
similar to that which might eventually be applied 1n a commercial facility. A
landfill waste disposal system 1s Included 1n the conceptual design based on a
consideration of the nature of the OSEC waste product. Finally, SCS's experience
1n designing and conducting prototype test programs places emphasis on design
flexibility and the specification of utility-grade equipment to assure test
continuity and quality data.
OETAILS OF THE PROTOTYPE CONCEPTUAL OESIGN
Oeslan Basis and Criteria
The design approach described above was applied to a conceptual design for a
prototype OSEC test facility at Gulf Power Company's Plant Scholz. This plant
consists of two Identical Babcock & Wilcox boilers with nameplate ratings of
40 mm. The boilers, which began commercial operation 1n 1953, were designed for
steam throttle conditions of 900"F and 350 ps1g with a boiler rated capacity of
425,ooo pounds of steam per hour. Unit 2 was chosen for the design study because
it is the host unit for the EPRI/SCS h1gh-sulfur-coal pilot baghouse, which
provides an Ideal opportunity to test the Integrated OSEC concept. Features of
PTant Scholz Include a wide load range (20 to 48 MW), good control of steam
temperature by flue gas recirculation and superheater bypass, and a large cold-side
•^ctrostatlc precipitator (544 ft2/kcfm), as well as a long history of
^nyolvement 1n research programs.
34-6
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Table 1 lists the major design criteria used to size the equipment for the
conceptual design. The coal specified for the study 1s a hypothetical
3.5-percent-sulfur bituminous coal such as might be found 1n the Illinois Basin.
Sorbents used 1n the study Include limestone and hydrated lime for furnace
Injection, and trona, a naturally occurring sodium-based compound originating 1n
the Western United States, for Injection ahead of the slipstream baghouse. Table 1
also lists the design reactant/sulfur molar ratios and SO? removal efficiencies.
The stoichiometrics specified are the peak stoichiometrics to be tested under the
design conditions (40 MW, 3.5-percent-sulfur coal) and are not necessarily
representative of economically or technically acceptable performance for the
commercial technology.
Table 2 summarizes the operating basis and storage capacities for process equipment
and areas. Raw limestone handling and waste disposal are assumed to operate with
one shift per day to reduce manpower requirements and avoid nighttime operation of
mobile equipment. The limestone receiving hopper and solid waste storage silo are
given sufficient storage capacity to allow for continuous testing throughout the
unmanned shifts. The pulverized 11mestone/l1me silo is sized to accommodate the
receiving and storage of preprocessed sorbents such as prepulverlzed limestone or
hydrated Hme. Waste landfill areas are sized for a combined total of two years of
waste production at 60 percent of the process design point. This provides for an
extension of the test program beyond one year without new construction.
Process Design
The general design criteria were used to define the conceptual process design for
the prototype facility. The process flow diagram (PFD) 1n Figure 2 shows the major
equipment and process flows. Equipment items are Identified more specifically 1n
Table 3, and continuous process flow streams are quantified in the material balance
given in Table 4. Five process subsystems are identified in the PFO. Three
additional subsystems not Identified 1n the PFO provide general support for the
process. Following 1s a brief description of each of the subsystems. Equipment
numbers mentioned 1n the text refer to designations in the PFD and Table 3.
Limestone Handling and Pulverization. The purposes of this subsystem are to
receive, store, dry, and pulverize crushed limestone and deliver the pulverized
product to storage. The crushed limestone (nominally 3/4" x 0") is stored 1n two
15-day piles, one of which 1s covered to provide sufficient residence time for
partial drying. The crushed limestone 1s transferred by a front-end loader from
the covered pile to a bucket elevator (E-101), which fills the 150-ton hopper
(H-101). The 150-ton hopper provides some 20 hours of limestone feed to the
pulverizer at the process design flow of 6.7 tons of dry limestone per hour. The
pulverizer 1s a roller-and-race type vertical-spindle mill with Internal classifier
sized to produce 10 tons per hour of limestone at finenesses up to 90 percent
passing a 325-mesh screen. The grinding process used here is a closed-circuit
grinding approach 1n which the pulverized limestone 1s recycled until the desired
fineness 1s achieved. The pulverized product is separated from the mill air by a
primary cyclone and bag filter and emptied Into a small feed hoper (H-102) which
supplies a gravimetric feeder. From this hopper, the limestone may be loaded
pneumatically Into a storage silo or conveyed to the boiler for direct Injection.
Pulverized Sorbent Storage and Conveying. The purpose of this subsystem 1s evident
from the title. The heart of the system Is a 500-ton storage silo (S—102) supplied
from pulverizer P-101 and a 2000-scfm sorbent conveying and Injection blower
(8-102) which pneumatically transports the pulverized sorbent to the boiler
Injection system. Also Included in this system is a welgh-belt feeder which 1s the
34-7
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primary metering device for the sorbent. As mentioned 1n discussing the previous
subsystem, air from Injection blower B-102 can also be supplied with limestone
directly from the pulverizing system for direct Injection of sorbent. The storage
and conveying equipment 1s designed to provide flexibility with regard to sorbent
type and source. A separate fill line on silo S-102 allows hydrated Him or
prepulverlzed limestone to be received from hopper trucks. The silo will
accommodate approximately 2.5 days' supply of hydrated lime and 3 days' supply of
pulverized limestone at the design feed rates.
Furnace Sorbent In lection. This subsystem consists of the equipment required to
distribute the pneumatically conveyed sorbent to three boiler levels and to
multiple injection points at each level, and to accomplish the Injection of the
sorbent Into the boiler to achieve complete mixing 1n the flue gas stream. This 1s
a critical area of the design in terms of the process fundamentals. The choice of
injection location, for example, largely determines the residence time and
temperature history that the sorbent experiences 1n the furnace. Injection
location combined with Injection nozzle design and sorbent transport air rates may
also have a major Impact on the extent and rapidity of sorbent-flue gas mixing 1n
the furnace. The general arrangement of the Injection system 1n shown 1n
Figure 3. A central Injection header feeds the three Injection levels. The
Injection header 1s supplied directly by the sorbent Injection blower, B-102. Only
one Injection level 1s 1n use for a given test. Manually operated gate valves are
used to Isolate the remaining levels. Each Injection level has four Injection
ports which penetrate the boiler wall. The a1r-sorbent stream from the main header
1s split using an available Impact splitting technology. The nozzle sizes and
sol1ds/air ratio for the Injection system are based on preliminary jet penetration
calculations. It was found that sufficient jet penetration could be achieved with
four 2.5-1nch nozzles and a total air flow of 2,000 scfm {500 scfm per nozzle).
However, the Importance of mixing requires that a detailed analysis of sorbent
injection be undertaken prior to a detailed process design. Work 1s currently
under way on this topic within the EPRI/SCS program.
Trona Handling and Injection. The trona Injection subsystem provides for the
receiving, storage, and injection of prepulverlzed trona in the 25-percent
slipstream ahead of the pilot baghouse. In the Plant Scholz conceptual design, the
trona—which consists primarily of sodium bicarbonate and sodium carbonate 1n a
hydrated m1xture—1s assumed to be available in a prepulverlzed form. The
pulverized trona 1s received 1n hopper trucks and 1s loaded into a 7-day storage
silo (S-105). The trona Injection stream 1s discharged from the silo to a
welgh-belt feeder which meters the sorbent Into the Injection line. A blower
(B-105) provides up to 115 scfm of air for Injection Into the baghouse slipstream.
The equipment for this subsystem 1s similar to that used for limestone storage and
conveying. However, Information from a commercial supplier of trona Indicates that
testing of the handling properties of the material should be undertaken before
final design.
Solid Waste Handling and Disposal. The waste handling subsystem is designed to
remove solids from the economizer, air heater, precipitator, and baghouse ash
hoppers on a continuous basis via a conventional vacuum conveying system. The
waste Is conveyed to a covered storage silo (S-106) providing 2 days' storage at
the process design point. The cementltlous nature of the material dictates that a
certain amount of storage be provided 1n order to avoid having to place the
material 1n the landfill during prolonged periods of heavy rainfall and to prevent
the waste processing equipment from being critical to dally process operation.
From the silo, the waste is metered into a pugmill in which it 1s mixed with
34-8
-------
water. A water addition rate of 28 percent by weight of the waste solids flow 1s
assumed in this study based on laboratory tests of ash collected during OSEC pilot
work. The mixed effluent from the pugmill fills a dump truck. Two trucks
alternate hauling and filling cycles to allow continuous waste processing in the
pugmill.
As indicated previously, a dry landfill disposal system has been selected for
purposes of the conceptual design 1n order to minimize site Impact and test the
landfill disposal concept. The assumed arrangement of the landfill areas 1s shown
in Figure 4. As the figure indicates, separate landfill areas hav« been designated
for sodium containing waste and waste without sodium. The drawing also gives
details of the runoff ditch system, holding pond, pumping system, and monitoring
wells as well as showing a section through the landfill area. Note that lining of
the landfill areas 1s not Included 1n this study because of the expected stability
and low permeability of the compacted OSEC waste. Major design assumptions are
noted on the drawing.
Central Instrumentation and Controls. Instrumentation and control requirements
have been addressed specifically to ensure that their effect on cost 1s not
neglected. Major measurements required for the prototype program Include gaseous
species concentrations, continuous coal flow rate, continuous sorbent flow rate,
total air flow rate, and various air and flue gas temperatures and pressures to
monitor unit operation. The large number of data Inputs to be monitored can best
be handled by a computerized data logging and recording system to facilitate
real-time data collection and processing. An extractive flue gas sampling system
is Included in the process design to provide critical Information on process
efficiency and supply data for process control. Accurate coal flow rates are
obtained by modifying existing coal feeders to yield continuous gravimetric
outputs. Weigh-belt feeders are used to provide continuous sorbent flow rates.
The centralized control functions for the process are handled'by a programmable
controller with an active mimic panel. This equipment 1s a microprocessor-based
system that provides for manual or automated control of all equipment. It 1s more
compact, more versatile, and less expensive than a relay-based control system. A
duplicate active mimic panel will be Installed In the plant control room.
Miscellaneous and Shared Facilities. This subsystem was Included as a "catch-all"
to account for equipment shared by multiple process areas. Examples include main
transformers, process area lighting and communications, and a process area sump.
Unit Modifications. This subsystem consists of two modifications to the existing
unit: a precipitator flue gas conditioning system and an upgrade of the existing
boiler sootblower system. Pilot tests at Southern Research Institute indicate that
the resistivity of OSEC flyash may Increase by up to two orders of magnitude during
dry sorbent Injection. The high flyash resistivity may lead to degraded
precipitator efficiency at the same time that the precipitator inlet grain loading
1s doubled or even tripled by sorbent injection. For the OSEC prototype design, it
has been assumed that flue gas conditioning with SO3 will be necessary to
maintain compliance with particulate emissions standards. The type of system
recommended 1n this study 1s a liquid SO2 conversion system. To minimize capital
costs. 1t 1s assumed that the main components of the system—the vaporizer and
converter—will be rented. The rest of the system consists of an Injection systen,
electrical wiring and controls, and a rail tank car or other vessel for storage of
liquid SO2. These Items are Included as capital cost Items.
The dry sorbent injection process has the potential to Increase furnace wall and
34-9
-------
convection surface deposits because of the Increase 1n ash loading and potential
changes in flyash chemistry. Therefore, an evaluation of the existing sootblowlng
system at Plant Scholz was undertaken 1n preparation for the prototype study.
Sootblowlng capabilities were judged to be adequate 1n most respects to cope with
furnace sorbent Injection. Three relatively minor modifications to the existing
system are assumed 1n the study to provide an extra margin of performance: an
Increase in sootblowlng pressures beyond present levels (125 to ITS psi), an
Increase 1n sootblowing frequency, and the Installation of four additional
wallblowers 1n existing bent-tube openings 1n the lower furnace. Only the last of
these modifications has significant capital costs associated with it.
PROTOTYPE FACILITY CAPITAL ANO Q&M COSTS
aased on the process design outlined In the preceding sections, a conceptual cost
estimate was prepared for a prototype demonstration of the OSEC process at Plant
Scholz. The costs addressed in this study consist of a grand total capital cost
and operating and maintenance (O&M) costs for the project. Major project costs not
addressed include project management, test consultants and subcontractors, system
production costs, and site restoration. The assumptions employed in the study are
specific to the Plant Scholz site and are not necessarily consistent with generic
assumptions recommended by EPRI. The following sections summarize the more
Important cost assumptions and present the results of the estimate.
Prototype Capital Casts
Capital Cost Assumptions. The components of capital cost employed 1n the estimate
are shown 1n Table 5. These are the standard components used by SCS in estimating
costs for Sulf Power Company. The table indicates how the grand total capital cost
1s calculated from the components. The Indicated percentages are based on SCS cost
estimating guidelines and experience. Direct project costs were estimated based on
the process flow diagram and design assumptions presented previously. All direct
and engineering costs for the project were estimated 1n April 1, 1984 dollars and
were escalated to January 1, 1986 dollars using annual escalation rates of
7 percent for direct costs and 8 percent for engineering costs.
Capital Cost Estimate. The results of the capital cost estimate are shown in
Table 8. The total capital cost for the prototype 1s estimated to be $5.75 million
1n dollars as of January 1, 1986, which represents a time near the projected
midpoint of the design and construction efforts. The table breaks the capital
costs down by the process subsystems described 1n the preceding section. Indirect
costs, however, are added to the total direct costs for the project. Several
points should be made about the figures presented 1n Table 6. First, the
estimation of engineering costs 1s based on a maximum of home-office engineering
and a minimum of field engineering and field routing by subcontractors. This
approach tends to shift some costs from the category of directs (through
subcontractor overheads and profits) Into the category of engineering, although the
total of the two should not change appreciably. Second, the capital cost estimate
does not include any charges for operating-company engineering and review, which
was difficult to estimate because of the research status of the project. Third,
the breakdown of costs by subsystem 1s somewhat artificial from an engineering
standpoint and subsystem costs are expected to have a greater range of error than
the total cost estimate. Finally, the costs shown are for a research facility at a
small plant and should not be extrapolated to a full-scale production facility.
34-10
-------
Prototype O&H Costs
O&H Cost Assumptions. The components of O&M cost are identified as fixed and
variable costs in Table 7. The notes to this table provide a brief summary of the
basis on which the O&H costs were estimated. However, several points should be
emphasized. As indicated In note (7), limestone and hydrated 11me costs include
shipment by truck approximately 300 miles under the assumption that sorbents from a
range of geographic locations will be tested. Sorbent costs could be reduced by
specifying locally available limestone and lime. With regard to O&M labor, the
staffing specified in this study is assumed to be In addition to the plant staff
for budget estimating purposes. No effort was made to examine the use of existing
plant personnel to perform process O&M functions. It should also be noted that all
labor Includes appropriate overheads and profit and is based on union labor rates.
Both labor and consumables were priced specifically for a Plant Scholz test and may
not be typical of costs at other sites in other regions. Annual escalation rates
based on SC5 projections range from 5.5 percent for energy to 7 percent for
sorbents and chemicals.
O&M Cost Estimate. The estimated O&M costs are tabulated in Table 7. The costs
apply to a one-year test 1n 1987 and are reported 1n dollars as of July 1, 1987.
However, unit costs are given 1n dollars as of April 1, 1984. The total annual O&M
cost of the prototype facility is estimated at $3.25 million.
ALTERNATE PROTOTYPE CONFIGURATIONS
The prototype cost estimate indicates that a facility designed for an extended test
of the Integrated OSEC concept at Plant Scholz would require some $6.75 million In
capital costs and S3.25 million per year 1n O&H costs. Such a facility clearly
represents a major Investment of resources which must be evaluated in light of the
potential benefits of the test program. To assist 1n this evaluation, 1t 1s
worthwhile to consider how prototype costs could be reduced and what Information
would be lost by such a reduction.
Alternate Plant Scholz Oeslon
Figure 5 shows in schematic form the Plant Scholz design presented In this study
along with a lower-cost alternative design to support a reduced-scope test
program. The lower-cost design eliminates two major subsystems, viz. on-site .
limestone pulverization and sodium injection, reducing the capital cost to
approximately 15 million. The elimination of on-site pulverization has several
Implications. First, 1t means that prepulverized limestone must be purchased for
the test program, which will probably increase sorbent costs. Second, 1t limits
flexibility 1n testing different limestones since many limestones are not available
in prepulverized form. Third, 1t precludes the possibility of evaluating tradeoffs
between grinding costs and the effect of limestone grind size on the process. The
elimination of sodium injection has the obvious effect of precluding the Integrated
testing of 1n-furnace calcium Injection and post-furnace sodium Injection. On the
other hand, post-furnace sodium Injection has been tested extensively by EPRI 1n
other programs, and the sodium injection step as specified here contributes
relatively little overall SOj removal 1n the DSEC process. An evaluation of 08M
costs for the lower-cost test facility was beyond the scope of the prototype cost
study. However, a comparison of the costs of raw versus prepulverized limestones
purchased for the EPRI/SCS pilot program suggests that savings 1n O&M costs due to
the reduced scope would possibly be offset by the higher cost of the prepulverized
34-11
-------
product required by the elimination of on-site pulverization.
Generic Prototype Cost Reductions
While the costs associated with the Plant Scholz prototype should not be viewed as
generic costs for a prototype facility, they can be used to suggest the most
effective ways of reducing costs for prototype OSEC work done elsewhere. An
examination of the cost data given 1n Table 6 Indicates that materials handling and
processing represent over 50 percent of the prototype capital costs. This suggests
the following possible means of cost reduction:
• Select a smaller prototype boiler (e.g., an Industrial facility) to
reduce the size of the materials handling equipment.
• Select a prototype test site with existing materials handling
facilities such as limestone/11me handling equipment or a dry ash
disposal system (e.g., a small unit at a site which Includes large
scrubbed units).
CONCLUSIONS
SCS has used Its research and engineering experience along with the results to date
of the EPRI/SCS pilot program to conduct a conceptual design and cost study for a
OSEC prototype facility at Plant Scholz. The design provides for on-site
pulverization of limestone, the receiving and storage of prepared sorbents,
Injection of calcium-based sorbents at three levels 1n the upper furnace, the
Injection of a sodium compound ahead of an existing slipstream baghouse, and the
storage, processing, and landfill disposal of the OSEC waste product. The design
1s characterized by flexibility and similarity to a commercial system. The
estimated prototype costs are 56.75 million 1n capital and $3.25 million 1n annual
operating and maintenance costs for a test program conducted 1n 1987. Capital
costs can be reduced to approximately $5 million by the elimination of on-site
limestone pulverization and sodium Injection. While the elimination of sodium
Injection should not significantly affect the program, the elimination of on-site
pulverization of limestone will reduce flexibility with respect to limestone
supply, complicate the evaluation of grinding costs and limestone particle size
effects, and perhaps Increase limestone costs.
ACKNOWLEDGMENTS
The author gratefully acknowledges the substantial contributions of SCS design,
cost, and research engineers to this study. Appreciation 1s also extended to the
personnel of Gulf Power Company's Plant Scholz for their cooperation 1n all phases
of the OSEC project. Finally, the author wishes to thank representatives of the
Electric Power Research Institute, Southern Research Institute, and KV8, Inc., for
their input and guidance.
34-12
-------
100
80
¥ 60
>
o
S
0)
c
fM
o
CO
40
20
Longview Lime
Marianna
St. Genevieve
1600 1800 2000 2200 2400 2600
Maximum Gas Temperature, °F
2800
O Marianna, Low Load With Gas
• Marianna, Low Load With Coal
~ Marianna, High Load With Gas
t St. Genevieve, Low Load With Coai
k. St. Genevieve, Low Load With Gas
~ Longview Lime, Low Load With Coai
* Longview Lime, High Load With Coai
Figure 1. Relationship of observed SO2 reduction and maximum
gas temperature at the point of Injection for Marianna and
St. Genevieve limestones and Longview hydrated 11me tested 1n
Southern Research Institute's research combustor.
34-13 '
-------
Ili'UJillitVVi'M'i'i'i'i'i ^ ll'l M I I I 1 I I I 41 tii I—I I ||| i ;
I *' "• ' i 4 1 • I
• wqj
llUUaMUMt I
lutuja
I tf-m
lltMl
NIIVIII
WflMll
lltflillMMll
¦J &
uuuttiu esitiitt
l liim ;
i
Ift IfttH* |(«
IA
lldUkk
f " V
tt»rai< shun siuut
Irlftft
=£1
u« mi
H—rnm
ApTT'FPPWSpP'm
unlit aft
MUMl
Ir* S >!f?
Ml SUHNl IN|»I0« (ONlMl
« ASfC >
MKMISS (OMU'lUAt now/
CAUirKwl OUUIAtt
ayV —>tf>i
***** I 1
Figure 2. Dry Sorbent Ealsslon Control Prototype Process Flow/Equtpaent Dtagraa
-------
EL. 1ST
n
m
LOCATION 3
4 NOZZLES
s a EACH »OE)
EL. 1
LOCATION
EL. 1ST
EL. lit*
LOCATION 1
4 NOZZLES »i- ^
EL. 11*
I
FINtSHCO OKAOE
EL.tr
Figure 3. Location of sortent Injection
levels 1n Plant Scholz boiler.
34-15
-------
-/t
I . A tMtf A AAA A IM ' * ••
I MpKl •••« *4
\ m;m4Ll?e
at-.uS tr.r^v (i
K* »!•• *
- jwawr.- .
\ "1
llfKM W(MM (0* *M(MOriUf
i
\
\ - .; V ¦ v *" ¦' •
. \ \ 'A ¦> •
\\*>S\./ **•!
1
• MM* MH« — » — H<*«*
l*MHi MlN Mti Willi
WM*(« MMf m*«mM M
| « >W* IIMM4 ««M mtM
f-Mt M NMHb (#
IftlilM* WNMI Mil H •
MMMI UWil MM
I W MtMtffci MlrtM #•«*
*i«Ui iMMtin *•«<*
«v«t ii>v« Hit»M iMfii
C«llM<••••( 'M M Mk k»4M
(l« M# • «*ohtt«*a M
IHl «Ut <| d>«»M m |M
VMililIU «»H W *4
MMIII •• »I|M
MlilaK MM|M
% t W4t> M'llt Mtt Nt«
» ui>iiM4 iWiimT
m i Mtfm Am
Figure 4. Conceptual design and arrangement of OSEC waste disposal areas.
-------
FULL-SCOPE RESEARCH PROGRAM
DM
IMKSIONE
KINCm
wormed ume
BUNCHY
ruvtnuip
SORBEM OEtNEHV
L
QNBIf
UMESIOtC
NMnum
SOflKttl
FUMMCf
SOMEN!
MSCMM
VIASIC
STORAGE
SPAOCCSSMQ
UMVU
WASH
nsrasM
SIOMGE
MJCCflQN
M REDUCED-SCOPE RE8EARCH PROGRAM
-si '
HTHWrUtME
KIMW
Figure 5. Dlagran of two scope options for a OSEC prototype research prograa at Plant Scholi.
-------
Table 1
OSEC Major design Criteria
Boiler Performance Criteria
Qesign Output (Gross)
Heat Rate (Gross)
Excess A1r (Economizer Exit)
Coal Sulfur Converted to SOx
Top/-Bottom Ash Split:
Coal Ash
Injected Sorbent
Coal Analysis
Moisture
Ash
Sulfur
Volatile Matter
Carbon
Hydrogen
Nitrogen
Oxygen
Coal heating value
Sorbent Analysis. X bv wt.
40,000 IcW
11,000 Btu/kWh
30*
lOOt
85X/1SX
1002/0%
5.5X
12.OX
3.5X
35. OX
68. OX
4.OX
1.0X
6.OX
12,000 Btu/lb
Limestone
Hydrated L1me
Trona
CaCOi or CafOHl?
90
94
MqCO* or Mq(0Hl?
2
90
inarsi
5
4
10
Sorbent Sto1ch1ometr1es and Removal Efficiencies^)
Sorbent
V9«t1op
Molar Ratio
AS0?
Limestone
Furnace
Ca/S - 3
60X
Hydrated Lime
Furnace
Ca/S - 2
60X
Trona
Slipstream
Na/S - 3
60X
Unreacted L1me
Baghouse
(3)
25X
Removal 8as1s
Uncontrolled emissions
Uncontrolled emissions
SO2 at point of Injection
SO2 at baghouse Inlet
(1) Sodium sesqulcarbonate: Na9C03*NaHC03*2H20.
(2) Removals shown are assumed for equipment sizing and do not necessarily
represent the potential of the technology.
(3) Removal occurs on the baghouse filter cake due to unreacted CaO carried over
from furnace limestone Injection at Ca/S - 3. When trona 1s being Injected,
combined slipstream SO2 removal by sodium and unreacted calcium 1s assumed to
be 70 percent based on slipstream Inlet SO2.
34-18
-------
TABLE 2
Process Operating Basis and Storage Capacities^1)
Equipment Operating Basis
Front-end loader (raw limestone to bucket
elevator E—101)
Limestone pulverizer (P-101)
Pugram (PH-101)
Solid waste landfill mobile equipment
Davs/Week
1
3
1
1
7
7
7
7
Equipment Storage Caoac1t1es(2?
Raw limestone stockpile
Limestone receiving hopper (H-101)
Pulverizer product hopper (H—102)
Pulverized limestone silo (S-102)
Solid waste storage silo (S-106)
Pulverized trona silo (S—105}
30 days
20 hours
30 minutes
days
days
days
3
2
7
Capacities of Waste Landfill Areas(3)
Non-sod1um waste disposal area
Sodium containing waste disposal area
18 months
6 months
(1) Equipment numbers refer to process flow diagram (Figure 2).
(2) All equipment capacities at the process design point as defined by the
criteria in Table 1.
(3) Landfill capacities are based on 60 percent of the process design point
for a period of 2 years.
34-19
-------
TABLE 3
Identification of Major Equipment Items in OSEC
Process Flow Diagram
Limestone Handling and Pulverization
£-101 8ucket elevator, 30 TPH, 60-ft. height
H—101 Covered raw limestone hopper, ISO-ton capacity, live bin bottom
RL-101A Rotary airlock feeder
P-101 Roller-and-race limestone pulverizer with Internal rotary
classifier, 10 TPH of product 9 90*-325 mesh and 2-percent
moisture, variable speed drive
F-101 Main pulverizer fan
HT-101 011-fired pulverizer heater
C-102 Pulverizer cyclone collector
BF-106 Bag filter for secondary limestone collection
H-102 Pulverized limestone feed hopper, 2.5-ton capacity, with bin
activator
WF-101 Gravimetric welgh-belt feeder, 24-1n. belt
RL-1018 Rotary airlock feeder
9-101 Silo loading blower, centrifugal type, 650 scfm, 6 ps1g
Pulverized Sorbent Storage and Conveying
S-102, BF-101 Pulverized sorbent silo with separation equipment, live bin
bottom, and truck fill line, 500-ton capacity (limestone),
10,500 cu. ft.
3-102 Sorbent conveying and Injection blower, centrifugal type,
2000 scfm, 4 ps1g
WF-103 We1gh-belt feeder, 24-1n. belt
RL-102 Rotary airlock feeder
Trona Handling and Injection
S-105, BF-104 Pulverized trona storage silo with separation equipment, live
bottom, and truck fill line, 85-ton capacity, 6000 cu. ft.
WF-107 We1gh-belt feeder
RL-105 Rotary airlock feeder
8-106 Trona Injection blower, centrifugal type, 115 scfm, 3 ps1g
Solid Waste Handling & Olsoosal
S-106, C-101,
BF-105 Ash storage silo with separation equipment, live bin bottom,
350-ton capacity, 12,000 cu. ft.
VP-101, SL-101 Vacuum pump (1200 acfm 0 16 1n. Hg suction) with silencer
WF-108 We1gh-belt feeder
PH-101, PU-101 Pugmlll (50 TPH) with water supply pump
A8-101 Aeration blower, 250 scfm, 30 ps1g
AO—101 Aeration air dryer, dual tower dessicant type
34-20
-------
TABLE 4
6SCC Prototype Conceptual Design Material Balance
Llaestone and Irona Injection
(All quantities In 103 lb/hr)
Wo
10 11
12.
Ji-
Coal
36.7
-
_
-
—
—
—
_
_
S02
2.56*1* -
-
1.02
0.B4
0.84
0.26
-
0.26
0.08
-
-
-
Air
42B
9.6
-
-
-
-
0.56
-
-
-
-
-
Flue 6as
-
-
520
521
521
130
-
131
131
-
-
-
CaC03
-
12.1
-
-
-
-
-
-
-
-
-
-
CaO
-
-
5.4
4.0
-
1.36
-
1.36
-
4.0
1.34
5.3
CaSO.
121
Na Sesqulcarbonate1 '
— —
3.3
2.5
0.82
0.91
0.82
-
2.5
0.81
3.4
Ma2C03
-
-
-
-
-
-
-
0.64
-
-
0.39
0.4
Na2S04
-
-
-
-
-
-
-
-
-
-
0.34
0.3
Flyash
-
-
3.7
2.8
-
0.94
-
0.94
-
2.8
0.94
3.7
Sorbent Inerts
-
1.3
1.0
0.8
-
0.25
0.10
0.35
-
0.8
0.35
1.2
Total Solids
36.7
13.4
13.4
10.1
(3)
3.37
1.01
4.11
(4)
10.1
4.23
14.3
ll) Uncontrolled SO2 flow rate In furnace based on 100-percent conversion of coal sulfur.
(2) Sodlua sesqulcarbonate (Nagtt^NaHCO?*?^), the najor constituent of trona.
(3) Total particulate flow estliated at 50 lb/hr.
(4) Total particulate flow estimated at 16 lb/hr.
-------
Table 5
Components of Capital Cost
Olrect CostO) A
Indirect' Charges
Temporary Construction^) 8»2XxA
SCS Engineering^) ^
Field Supervision 0»3%xA
SUBTOTAL E
General Overhead F»lXx£
SUBTOTAL S
Interest Ourlng Construction (AFUOC) N/A(*)
SUBTOTAL H
Contingency^5) I«25XxH
GRAND TOTAL, CAPITAL COST J-A+6+C*0+F>l
(1) Total of base costs of labor, material, and equipment Including 3 percent
freight and 4 percent sales tax. Olrect erection or labor costs Include a
contractor overhead and profit of 45 percent.
(2) Project costs not chargeable to a direct account, e.g. construction equipment,
temporary buildings, safety and security, etc.
(3) Based on engineering manhour estimate and an average burdened manhour rate for
SCS. Includes design engineering and project support.
(4) Not applied to this estimate. The research status of this project may dictate
special financing considerations which could not be evaluated within the scope
of this study.
(5) Consists of scope omission and error contingency of IS percent and pricing
contingency of 10 percent. No allowance has been made for unforseen scope
changes.
34-22
-------
Table 6
OSEC Capital Cost Estimate
Prototype Demonstration at Plant Scholz In 1987
Costs 1n 1-1-86 *xl<)3
ITEMIZED- COSTS:
sufrmtyi
Limestone Handling
& Pulverization
Pulverized Sortent
Storage & Conveying
Furnace Sorbent Injection
Trona Handling & Injection
Solid Waste Olsposal
In-Plant Handling
Landfill
Central Instrumentation
& Controls
Miscellaneous and Shared
Facilities
Unit Modifications
Flue Gas Conditioning
Sootblower Modifications
TOTALS
TOTAL COST*.
mfrmi sr^tign
Total
01rect
Subcontract Costs Engineering
741 .4
2S3.1
95.8
670.4
75.8
346.5
265.1
27.9
2476.0
156.4
105.8
40.0
181.7
32.4
298.4
88.8
10.2
913.7
01rect Cost
Engineering
Temporary Construction and Field Supervision
General Overhead
Contingency (25%)
84.4 982.2
— 358.9
109.2 109.2
— 135.8
156.0
0.1
852.1
264.2
171.8 816.7
354.0
246.5 246.5
— 38.1
768.0 4157.7
4157.7
981.0
207.9
53.5
1350.0
149.5
151.8
8.0
21.3
223.0
118.2
130.3
149.3
21.6
8.0
981.0
GRANO TOTAL. CAPITAL COST
6750.1
34-23
-------
Table 7
One-Year O&H Costs for QSEC Prototype Test
(1987 Test Year)
Fixed Q&H Costs
Operating labors'J
Maintenance labor - routine^2)
Maintenance labor - start-up(3)
Maintenance materials(*)
Leased equipment
Flue gas conditioning^)
Mobile equipment^)
Ouantltv
Unit Cost
*
(4-1-841
Total Cost
103$
(7-1-87>
26,880 hr
21.75
706.5
5,760 hr
18.40
128.1
1,280 hr
19.20
29.7
—
—
192.2
143.9
—
TOTAL FIXED O&H 1426.5
Variable Q&H Costs
Sorbents^
Limestone
30,000 ton
22.00
822.3
Hydrated 11me
4,500 ton
70.67
396.2
Trona
750 ton
250.00
225.0
Energy^3)
4.2x10* kWh
Electric power
0.045
224.9
#2 fuel oil
10,000 MBtu
6.35
75.6
Qlesel fuel
24,350 gal
1.10
31.9
Liquid S02^
165 ton
250.00
Si-*
TOTAL VARIABLE Q&H
1827.3
TOTAL Q&H
3253.8
Consists of 8 process operators
(2 operators on shift at all
times), and 6
equipment operators to operate limestone and waste handling equipment (4 per
shift, 7 days per week).
(2) One I&C technician, one mechanical maintenance worker, and one general laborer
on one-shift, 5-day-per-week coverage.
(3) One I&C technician, 2 mechanical maintenance workers, and one general laborer
on day shift during first 8 weeks of the program.
(4) 8ased on maintenance labor/materials cost ratio of 40/60 (routine maintenance
labor as base).
(5) Based on estimated VIO.OOO/month for skid-mounted vaporizer and converter
escalated to 7-1-87.
(6) Consists of one 2-cu.-yd. front-end loader, one bulldozer (equivalent to
Caterpillar 0-3), one tractor and sheep's foot roller, and two 12-cu.-yd. dump
trucks.
(7) Delivered costs to Plant Scholz. Limestone and hydrated Hme costs include
shipment by truck approximately 300 miles. Costs of locally acquired Hmstone
and Hme would be lower. Trona cost is for a prepulverlzed product originating
1n Wyoming and Is speculative at this time.
(3) Consists of electricity for process equipment, fuel oil for limestone drying,
and diesel fuel for limestone and waste handling mobile equipment.
(9) Liquid SO2 1s for flue gas conditioning. Concentration of SO ppm SO3 1s
assumed because conditioning effectiveness with sorbent Injection 1s not
known.
34-24
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EPA's LIMB COST MOOEL: DEVELOPMENT AND
COMPARATIVE CASE STUOIES
David G. Lachapelle, Norman Kaplan,* and Jeff Chappell
U.S. Environmental Protection Agency
Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
ABSTRACT
The LIM8 cost model 1s used to project the capital and annualized costs and
the cost per unit of pollutant controlled for LIMB systems installed on
generic coal-fired utility boilers. The type of sorbent, unit size, unit
life, level of control, and coal sulfur content are among several Items
specified by the user. In addition, flexibility 1n user Input or default
values enables various parametric and sensitivity analyses. Basic economic
premises for the model are taken from the EPRI Technical Assessment Guide
(TAG").
Case studies compare various LIMB process options with each other and with
wet limestone slurry scrubbing, the current standard S0X control technology,
under a variety of conditions. For a new 500 MW unit burning 1.92* S coal
and achieving control to meet NSPS, costs per ton** of sulfur removed are
estimated to be $1377 and S1078 for limestone FGO and LIMB using dolomitlc
hydrate, respectively. At 0.48* S 1n the coal, these costs are estimated
at S3715 and $1366 for limestone FGO and LIMB, respectively. Case studies
involving comparisons between LIMB and FGO are accomplished through the
use of the LIMB cost model and the TVA Shawnee Flue Gas Desulfur1zat1on
Computer Model.
INTRODUCTION
EPA's LIMB cost modeling activities are a response to a need for making rapid
and accurate comparative economic assessments of LIMB technology with other
SO2 control approaches such as flue gas desul furlzat1on (FGD). This work
was initiated 1n May 1984 with the development of the LIMB cost model described
1n this paper. Our ability to conduct comparative economic studies has subse-
quently been augmented by Incorporation of eost models for FGD and Integrated air
pollution control systems that were developed under earlier EPA contracts. A
broad base of cost data for NOx» S0X> and particulates resides within EPA's
* Presenter
** For those more familiar with metric units, see conversions at the end of paper.
35-1
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Industrial Environmental Research Laboratory at Research Triangle Park. However,
the coordination and synthesis of this data base relative to comparative economic
assessments are assigned to the LIMB Applications Branch of the Engineering
Applications 01 vision of IERL-RTP.
To date', many benefits have derived from EPA's cost modeling work. Among these
are:
1. Responsive capability to perform parametric cost sensitivity
studies for a broad range of process variables.
2. An ability to make direct comparison, under equivalent premises,
of LIMB to other SO2 control options, particularly FGO.
3. An ability to economically optimize choice of sorbents, calcium-to-
sulfur ratios, and SO2 control levels.
4. Quick response to industrial Inquiries where s1te-spec1f1c
requirements can be defined.
5. Evaluation and/or reconciliation of cost estimates prepared
by other agencies themselves or through Agency-sponsored
contracts.
6. Program guidance relative to the focus of research and
development efforts as LIMB technology matures.
This paper presents some of the background and illustrative examples resulting
from our cost modeling activities.
COMPARISON OF LIMB AND FGO COST ESTIMATING METHOOOLOGIES
Process economics like most other quantifiable items Is relative; the numbers
mean very little in an absolute sense but are very meaningful when they are
used to compare two or more processes with each other. Since wet FGO processes
are currently the predominant SO2 controls used for fossil-fueled utility boilers,
comparisons between projected LIMB costs and FGO costs were deemed appropriate
to investigate the potential economic viability of LIMB. Comparison of LIMB
and FGO costs should be done with proper perspective. Since FGO is a relatively
mature technology, the projected costs are backed by actual full scale applica-
tions experience, whereas LIMB 1s a relatively new technology and its projected
costs are based on pilot data. The accuracy of the FGO costs Is expected to
be in the range -15%, >30%; accuracy of the LIMB costs is expected to be
somewhat less.
The EPA LIMB cost model was developed 1n-house at the Industrial Env1ronmental
Research Laboratory at Research Triangle Park, N.C. (IERL-RTP). The computer
program was developed using BASIC language on a Zenith 100 microcomputer. The
program and imbedded coiments contain approximately 1000 lines of code and, when
the optional printed reports are produced, a typical session and associated
case study takes less than 3 minutes to complete.
35-2
-------
The program 1s designed for minimum user Input of LIMB system operating and
performance data and generates corresponding material balances, sol Ids distri-
bution, emissions summary, tons/year SO2 removed at given capacity factor,
detailed capital requl rement, operating and maintenance costs, first year costs,
level 1zed costs, and cost per ton SO2 removed.
The cost model was designed to optimize speed and ease of use by containing
"default" economic assumptions and values. These economic values are presented
to the user during the session for acceptance as presented, or the user has
the flexibility at any time to override the default value and enter his own
values.
The cost model was developed as an analytical tool to support parametric sensi-
tivity studies and comparative technology cost studies. The model accepts
LIMB performance data and generates associated costs.
Since EPA's LIMB cost model was developed with a high degree of flexibility, an
FGD model with a similar degree of flexibility was sought for comparative studies.
Fortunately, TYA developed just such a model called the Computerized Shawnee
L1me/L1mestone (L/LS) Scrubbing Model under an Interagency agreement with EPA.
This model accepts about 150 user Input variables and about 20 print control
variables and 1s considered a preliminary design and cost model for wet lime
and limestone FGD processes.
Some of the more Important numerical values supplied by the user are given In
Table 1.
Some of the Important options available to the user of the TVA Shawnee L/LS
model are shown 1n Table 2.
The TYA program 1s a design and cost model for new FGD control systems. To
project costs of retrofit systems, a program was written for a TI-59 hand-held
calculator to use the results of the TVA program to project the cost of retrofit
systems. The basic assumption used was that the total capital Investment would
Increase by 30 percent over that for a new system. The program calculates
revised annualized costs by Increasing total capital Investment and those Items
that are estimated as a function of capital, but keeps constant Items such as
labor and unit costs which are not dependent on total capital Investment. The
FGD retrofit results are based on this program.
COMPARATIVE COSTS OF SO2 CONTROL TECHNOLOGIES
LIMB technology offers economic advantages over conventional wet FGD methods when
moderate SO2 control levels (45 to 65S) are required. The costs of these SO?
control technologies have recently been evaluated In considerable detail by EPA
based on wort conducted by TVA (1); Combustion Engineering, Inc. (2); PEDCo
Environmental, Inc. (3), and In-house cost analysis work performed by IERL-RTP.
35-3
-------
Since the SO2 removal efficiencies are different for LIMB and FGO, cost compari-
sons are presented on a normalized basis; I.e., cost per ton of SOg removal.
The cost analysis procedures are based to the maximum extent possible on guide-
lines suggested by the Electric Power Research Institute (4). The current dollar
analysis method 1s used with costs expressed in 1985 dollars. For retrofit units,
15-year levelized costs are used; whereas, 30-year levellzed costs are used for
new untts. Internally consistent costs and/or factors for such Items as operating
and maintenance labor, maintenance material, administrative and support labor,
consumables, and levelizatlon factors have been employed to ensure that the LIMB
and FGO costs are on an equivalent basis. Tables 3 and 4 present summaries of
the major premises used in the economic analysis. In addition to those shown,
there are other indirect charges and assumptions that enter Into this rather
complex analysis. These include items such as: engineering and home office
overhead including fee; project and process contingencies; cost of general
facilities; preproduction costs; Inventory capital; and land. Some of these
charges are based on a percentage of process capital cost, while others are
computed based on specific site requirements, cost and quantities of consumables,
allowance for funds during construction, etc. It is beyond the scope of this
paper to discuss these in any depth, but we have ensured that most charges and
assumptions are consistent within and between LIMB and FGO.
Some of the technology-related assumptions used 1n developing the costs for LIMB
are given below:
a. New units are assumed to be already equipped with burners capable
of meeting the current NQo standard of 0.6 lb/10® Btu for
bituminous coal and 0.5 lb/106 Btu for subbitumlnous coal.
b. Retrofit units are assumed to be installed with with improved
burners capable of meeting N02 emissions of 0.7 lb/10® Btu.
c. New units are assumed to be already equipped with a bare-tube
economlzer.
d. Retrofit units are assumed to have an existing finned-tube
economizer which is replaced with a bare-tube economizer.
e. Retrofit units have upgraded ESPs to handle the additional
solids loading plus SO3 conditioning to improve resistivity.
f. Mew units have baghouses which are not charged off as a
LIMB-related cost.
g. Both new and retrofit units have sootblower upgrades, a
sorbent Injection system, and dry waste disposal.
Some of the technology-related assumptions used 1n developing FGO costs are
given below:
a. Spray tower absorbers using limestone slurry and forced
oxidation were specified.
b. Waste disposal is by landfill.
35-4
-------
c. One spare absorber was specified for new units, and no
spares for retrofit cases.
d. Emergency bypass of 50% of the flue gas normally scrubbed
1s provided.
e. Reheat Is by 1n-l1ne steam tube reheater to 79.4*C (175*F).
For FGD systems, the stoichiometric ratio 1s defined as the moles of calcium
per mole of SO2 absorbed. For LIMB, the stoichiometric ratio Is defined as
moles of calcium per mole of sulfur 1n the fuel. Typically, a stoichiometric
ratio of 1.4 1s used with FGD for 90S SO2 control; whereas for LIMB, stoichi-
ometric ratios of 1.4 to 2.5 might be employed depending on the sorbent and
required control level. A LIMB system using a Ca/S ratio of 2 and achieving
50 I SO2 control would be equivalent to a stoichiometric ratio of about 4
using^GD's nomenclature for stoichiometric ratio. The figures In this paper
that Illustrate the comparative costs of LIM8 and FGO use the stoichiometric
ratio nomenclature associated with the respective technology. For LIMB, It Is
shown as Ca/S; for FGD, 1t 1s shown as Ca/S02-
Table 5 gives the boiler and coal characteristics used for the LIMB and FGO
economic analysis. The unit sizes selected represent those typical of retrofit
and new applications. Wall-fired designs were used in all cases. The coals
encompass the sulfur content range targeted for application of these SO2 control
technologies. The net plant heat rate 1s used 1n the analysis to determine the
required coal flow and corresponding sulfur and SO2 mass flow rates.
Table 6 gives the sorbents, Ca/S ratios, and SO9 control levels used 1n the LIMB
economic analysis. The performance data 1s derived from pilot scale tests shown
in Figure 1 and from In-house testing of sorbents with promoters. Promoted
sorbents contain relatively small amounts of mineral substances that are added to
enhance the sulfur capture potential of the sorbent. Some very preliminary work
conducted to date Indicates that the use of a promoter such as sodium carbonate
can increase CaC03 and Ca(0H)2 performance by about 1.4 times that typical of the
unpromoted sorbent. The sorbent costs represent delivered costs to the power
plant based on current estimates from sorbent suppliers. The selection of these
specific Ca/S ratios and corresponding SO2 control levels resulted from an Initial
sensitivity and optimization study 1n which a range of Ca/S ratios and SO2 control
levels were evaluated. The values selected represent the optimum economic levels
for these sorbents.
For retrofit units, the Ca/S ratio sets the SO2 control level. For new units,
required SO? control levels to meet New Source Performance Standards were
determined for the coals being used, which 1n turn set the Ca/S ratios.
Figure 2 and Table 7 present the results of the economic analysis of LIMB and
FGD for retrofits. Mote that for Intermediate sulfur levels (e.g., 1.92%), LIMB
Is consistently more cost effective than FGD 1n the categories of cost per ton of
SO2 removed, total capital requirements, and levellzed revenue requlrements. For
higher sulfur levels (e.g., 3.365), FGD has a slight edge In terms of cost per ton
of SO2 removed over LIMB when limestone and/or pressure-hydrated dolomltlc Hme
is used as the LIMB sorbent. This 1s due 1n part to the scenario chosen for FGD
in that FGD would be retrofit to meet USPS requirements. For FGD, the differen-
tial cost 1n capital requirement and levellzed revenue requirement that occurs
35-5
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in going from 1.92 to 3.36% sulfur fs offset to an extent by the increased
SO2 control. For LIMB cases, a constant percentage control is assumed for these
coals; consequently, on a cost per ton of SO2 removed basis, LIMB's cost advantage
relative to FGO diminishes for limestone or pressure-hydrated dolomltlc lime.
However, LIMB continues to exhibit an economic advantage when Ca(0H)2 or promoted
Ca(0H)2 or promoted CaC03 1s used as the sorbent. Note also, that LIMB consis-
tently showns an advantage over FGD In terms of total capital requirement and is
always more than SlQO/kW cheaper.
Figure 3 and Table 8 present the results of the economic analysis of LIMB and FGD
for new units meeting NSPS. Here, LIMB exhibits a significant economic advantage
over FGO with the low sulfur coal. With intermediate sulfur levels, LIMB contin-
ues to be about 1/3 to nearly 1/2 the cost per ton of SO2 removed that FGO
displays. Table 3 illustrates that for LIMB, the total capital requirement is
consistently at least SlQO/kW less than FGO. For LIMB, the cost per ton of SO?
removed is affected significantly by sorbent cost as reflected in the line repre-
senting the pressure hydrated dolomltlc Hme. CatOH)?, both umpromoted and
promoted, appears to be the sorbent of choice for NSPS applications.
An examination of Tables 7 and 8 shows that both processes are 0AM intensive, but
as a percentage of the total levellzed revenue requlrements, FGO Is slightly less
04M intensive. This results because of F<3D's lower sorbent cost and somewhat
more favorable sorbent utilization. Oespite this, LIMB has overall cost advan-
tages that for many applications appear favorable.
CONTINUING WORK
Comparative Economics
In order to continue economic evaluations of LIM8 processes and to evaluate them
relative to other competing technologies, plans are underway to modify and update
another existing cost and performance model called the Integrated Air Pollution
Control System (IAPCS) which was developed by PEOCo Environmental, Inc., under
contract with EPA 1n 1983. The IAPCS was designed to compare the cost and
performance of several control technologies used with fossil fueled power
plants. Within certain stated limitations, the IAPCS projects the cost and
performance of systems consisting of various configurations or combinations
of nine control technologies:
• Overflre air/low N0X burners (OFA/LNB)
• Limestone Injection In multistage burners (LIMB)
• Physical coal cleaning (PCC)
• Spray humldlflcation (SH)
• Electrostatic precipitator (ESP)
Fabric filter (FF)
• Lime spray drying (LSD)
35-6
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" Flue gas desulfurization {FGD)
# Dry sorbent injection (DSI)
The IAPCS model Is currently operational on the IBM mainframe system at the
National Computer Center at Research Triangle Park, N.C. The model is
interactive—it prompts the user to supply the required input data and to
accept or change most of the current numerical parameters.
Currently, 1t 1s planned to replace the IIM3, FGD, ESP, and FF modules 1n the
IAPCS with updated versions. The EPA LIMB cost model will be made a part of
the IAPCS, replacing the current (I.e., PEDCo) LIMB cost module of the model.
The ESP and FF modules will be replaced by programs developed by V1ner and
Ensor (5) of Research Triangle Institute under contract with EPA in 1982-1983.
We expect to develop an algorithm for predicting flyash resistivity as a function
of ash characteristics and LIMB product solids. This will be used to calculate
specific collection area and, thus, project more accurate ESP costs.
The current FGO module in the IAPCS model deals only with wet limestone FGD
using a spray tower and forced oxidation. We intend to replace this module
with an updated version of the TYA Computerized Shawnee Lime/Limestone
Scrubbing Model. This will add a lot of flexibility to consider, for example,
lime or limestone, forced or natural oxidation, different waste disposal
options, and different scrubber types.
In addition to updating and expanding some of the Individual IAPCS modules,
general improvements are also planned and listed here:
# Inclusion of EPRI guidelines (TAG") and cost reporting
format to allow the user to specify EPRI or TVA cost
and reporting format.
# Inclusion of Marshall and Swift cost indices to allow
the capability to produce cost estimates for any
time frame.
Expression of results 1n cost per unit ($/ton) of
pollutant removed.
Recycle of Spent Sorbent
Since LIMB annualized costs and cost per unit pollutant removed are 04M
intensive and much of the sorbent remains unused, the potential exists to
reduce costs by recycling some of the unused sorbent In the waste. To
do this, a process would have to b« designed and Installed to enrich the
spent sorbent in unused reactant and simultaneously produce a waste product
poorer in unused reactant. Such a process would require additional capital
investment and operating revenue but would balance this cost with a savings
in sorbent cost for the overall LIMB process.
35-7
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Although the LIMB cost model cannot be used to conceive and design such a
process, it can be used to determine break-even costs for the Installation
and operation of the potential process. The LIMB cost model has been modified
to consider recovery and recycle. The user must supply Inputs concerning the
enrichment of the waste and the percent recycle. The cost model will then be
used to.help guide a preliminary engineering study of potential recycle schemes,
rejecting from further study those not economically viable.
Sensitivity Analysis and By-Product Credit
The model is expected to be used extensively in studying many economic aspects of
LIMB processes to help guide the expenditure of resources 1n basic research and
engineering studies so that these resources will be spent where there is the
most potential for practical application.
Sensitivity analyses based on the model may be used to examine the effects of
such items as by-product credit, sorbent cost, capacity factor, and stolchlometry
on the process economics for a range of applications. 8y-product credit 1s of
particular interest because the LIMB processes will produce greater quantities
of waste (dry basis) than the currently used SO2 control technologies. As more
1s learned about the LIMB process and Its wastes, beneficial utilization tech-
niques will be sought and further developed if economically viable. The LIMB
cost model or an upgraded version will be used to focus on the techniques with
most economic potential. Sensitivity of the LIMB process with respect to sorbent
cost and stolchlometry 1s an Important consideration for reducing operating costs
and further improving LIMB's projected cost advantage.
CONVERSION UNITS
To convert from to Multiply by
lb/106 Btu ng/J 433
tons metric tonnes 0.907
Btu J IQS5
lb 1(9 0.454
gal. liters 3.78
35-8
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REFERENCES
1. Anders, W. I., and Torstrfck, R. I., "Computerized Shawnee l1me/L1mestone
Scrubbing Model Users Manual," EPA-600/8-81-008 (NTIS No. PB 82-178963),
March 1981.
2. Plumley, A. I., et al., "Feasibility of Furnace Limestone Injection for
SOg Control." Draft Final Report for EPRI Research Project 1836-3,
September 1983.
3. Baker, G., et al., "User's Manual for the Integrated A1r Pollution Control
System Cost and Performance Program." Draft Final Report for EPA Contract
No. 68-02-3693 (3,6), October 1984.
4. Electric Power Research Institute, "Technical Assessment Guide,"
EPRI P-241Q-SR, May 1982.
5. V1ner, A. S. and Ensor, D. S., "Computer Programs for Estimating the Cost
of Particulate Control Equipment," EPA-600/7-84-054 (NTIS No. PB 84-183573),
April 1984.
35-9
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OC«
-------
15-YR LEVELIZED $/TON
S02 REMOVED
BASIS t C2.8X CAPACITY FACTOR
1400
1300
1200
1100
1000
900
800
700
600
500
1.0
G1CO3 $ •18/T
C«/S = 26 .
46% CONTROL \!
Ca(OH) 2 Mg|OH)2
•60/T. Ca/S = 1.4
62% CONTROL —
PROMOTED CaCOj
•26/T. Ca/S - 2.0
66% CONTROL
CafOHfe 9 M6/T
Ca/S = 2.0 V"
62% CONTROL *\
PROMOTED Ca|OHb
•60/T. Ca/S = 1.6
66% CONTROL
I 1 I I I 1 I
1.5 1*®* 2.0 2.5 3.0 3.5
COAL SULFUR, PERCENT
4.0
Figure 2. Comparison of SO2 control technology cost; 300 HUe retrofit.
-------
30-YR LEV ELI 2 ED $/TON BASIS i 62.6V CAPACITY FACTOR
SO,REMOVED
4000
LIMESTONE FGD
3500
3000
•2« CO 4TROL
TO* CO ITROL
2500
2000
CstOHl2 MtfOH|2
@I60/T
1500
1000
PROMOTED Ca(OH|2
@*60/T
600
2.5
1.6
1.0
COAL SULFUR, PERCENT
0.5
Figure 3. Coapart&on of SOj control technology cost; 500 MUe USPS.
-------
Table 1
SOME NUMERICAL VARIABLES FOR THE
TVA SHAWNEE LIME/LIMESTONE SCRUBBING MODEL
Boiler
Electric power output
Boiler heat rate
Heating value of coal
Excess air, %
Temperature of hot gas to scrubber
Coal Composition, wt %, C, H, 0, N, S, CI, Ash, HjO
Scrubber
SO2 removal, I
Temperature of stack gas
L/G ratio
Hold tank residence times
Superficial gas velocity
Sorbent stoichiometry
Oxidation rate
Air stoichiometry (for forced oxidation)
Solids in filter cake, %
Waste Disposal
Sludge disposal fee, S/ton dry sludge
Land area for pond, acres
Land cost, $/acre
Distance from scrubber area to disposal site
Pond Uner cost, S/yd2
Indirect Costs as percentage of direct construction expense
Economics
Levelizlng factor for 04M
Level1z1ng factor for capital charge
Sales tax
Freight rate
Royalties
Chemical engineering material cost Index
Chemical engineering labor cost Index
Unit Costs for limestone, Hmt, additives (if applicable), labor, utilities
Operating Profile
Number of years of operation
Operating hours per year
(capacity factor * operating hours per year * 8760)
35-13
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Table 2
SOME IMPORTANT OPTIONS FOR
TYA SHAWNEE LIME/LIMESTONE SCRUBBING MODEL
Emergency bypass
Partial scrubbing/bypass
Coal cleaning
Pollutant Removal - % removal, MSPS, lb/10® 8tu
Sto1ch1ometry, L/G, SO2 removal
(scrubber design based on any two of these three)
Sorbent - lime or limestone
Add1t1ves - MgO or adlplc acid
Forced Oxidation
Scrubber Type - spray tower, venturl, TCA, and
combinations of these
Sludge Disposal - thickener, filter, ponding, lining, fixation,
landfill, and combinations of these
Economic Premises
35-14
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Table 3
MAJOR ECONOMIC PREMISES FOR COST OF CAPITAL
New Retrofit
Units Unit
Base year for cost conparlson 1985 1985
Book life, years 30 15
Tax life, years 15 5
Inflation rate, Vyr 8.5 8.5
Debt/equity ratio 50/50 50/50
Debt cost, 1/yr 11.0 11.0
Preferred stock ratio, 1 15 15
Preferred stock cost, 1/yr 11.5 11.5
Cmmon stock ratio, t 35 35
Conaon stock cost, 1/yr 15.3 15.3
Weighted cost of capital, 1/yr 12.5 12.5
Federal plus state Incoae tax rate, 1 50 50
Property taxes and Insurance, 1/yr 2 2
Investoent tax credit, 1 10 10
Level1 zed carrying charge rate, 1 15.3 16.01
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Table 4
MAJOR ECONOMIC PREMISES FOR OPERATING AND MAINTENANCE COSTS
New Retrofit
Units Units
Base year for cost comparison 1985 1905
Unit capacity factor, X 62.8 62.8
Book life, years 30 15
Tax life, years IS 5
Levelizing factor 2.314 1.714
Uaste disposal cost, S/ton 7.66 7.66
Operating aanhours/year
LIMB 43,800 43.800
FGO 55,460 55.460
Average labor rate, $/hr 23.37 23.37
Limestone cost, $/ton* 17.88 17.88
Uater, 9/1000 gal. 0.77 0.77
Process steam, 1/1000 lb 4.84 4.84
In-plant power, mills/kUlt 58 58
Coal cost, f/106 Btu 2.61 2.61
a A variety of sorbents can be used with LIMB.
Costs for alternate sorbents are indicated on Figures 2 and 3 and in Table 6.
-------
Table S
BOILER AND COAL CHARACTERISTICS SELECTED FOR LIMB AND FGD ECONOMIC ANALYSIS
Coal Characteristics
Net Plant lleat High Heating Value
Unit Size, MUe
Status
Rate. Btu/kU«h
Btu/lb
% S
1 Ash
300
Retrofit
9,500
11,700
3.36
15.14
300
Retrofit
9,500
11,700
1.92
15.08
500
New
9,500
11,700
1.92
15.08
500
Mam
new
10,500
8,200
0.48
6.3
NOTE: Wall-fired boilers are used 1n these case studies.
-------
Table 6
SORUENTS AMD PERFORMANCE DATA USED FOR LIMB ECONOMIC ANALYSIS
Retrof1t
New
in
i
CO
Sorbent
Vlcron CaCOo
Longview Ca|0H)2
Longview Ca(0H)2
Corson CafOHlo^HgfOHto
Corson CajOH^'HgiOH^
Prowoted CaC03
Promoted Ca(0H)2
ProMOted Ca(0ti)2
Sorbent Cost,
S/ton Ca/S
SO2 Control,
I Ca/S
IB a
2.5
45
45
2.0
62
2.7
70
45
-
-
4.0
82
60
1.4
62
1.63
70
60
-
-
2.1
82
25
2.0
56
-
-
50
1.5
65
1.8
70
50
-
-
2.8
82
SO2 Control,
t
a Actual cost used was $17.88/ton.
b Miniww percent control required by NSPS for the 0.481 S coal.
c Miniww percent control required by NSPS for the 1.921 S coal
to be at or below 260 ng/J (0.6 lb/lCP Btu).
-------
Ilkll 7
COMPARISON OF COSI COMPONENTS FOR MTROFIT LIMB AND FGO
•tils: 300 Ml* Wa11-flre4 Italtt at 62.9* Capacity Factor; 199S Doll art
ItCkMlttD
Sulfur,
ft
IwkMl
S02
IhohI ,
l/ton
lot*! Ci^ltil
f/hU
IS-Year
iMtllnd Revenue
Requirement.
¦IHi/kM.h1
IS-Year
Level lie4 Caplul,
¦Ills/kVh
IS-Vear
levellied Operating
and Maintenance,
¦lllt/kU*h
FCO
1.92
CaCOj
1351
210
17.30
6.10
11.20
IIM
1.92
CaCOj
113$
M
7.99
2.S7
S.42
LIN
l.«
UlflNlz
•44
If
9.14
2.30
S.94
IIW
I.M
Ca|0N|j»Mf|0M|j
HOI
M
10.(1
2.69
9.02
UN
1.92
CaC0,fc
•SS
74
7.47
2.16
S.3I
IM
1.92
CalOM);'
666
64
6.94
1.97
S.07
FCS
l.M
CaCO)
121
239
20.22
6.97
1J.2S
IIM
3.X
CaCOj
•14
10?
10.91
3.11
7.70
LM
3.31
CelOH)*
6*1
107
11.64
3.11
9.S3
LIM
3.36
Ca|OM)2*N«40N|2
942
122
IS.97
3.65
12.32
IIM
3.31
CaCOj*
695
102
10.63
2.97
7.66
LIM
3.36
Ca(0N)2*
556
17
9.79
2.S4
7.24
• IkIiAi Imlliil ciftul ni levellie* eperatlni hIMmmci cMrfit.
I frmul MrtMt.
-------
Table a
COMPARISON OF COST COMPONENTS FOB NEW LINO ANO FGO
Basis: 500 HUe Uall-flre4 Units at 62.81 Capacity Factor; 1985 Dollars
30-Vear 30-Vcar
Technology
Sulfur
X
Sortoent
S02
fleaoval.
1/too
Total Capital
Requlreaent,
t/kU
Level lied Revenue
Requirement,
aills/kU.h*
30-Vear
LevelIie4 Capital,
¦tllsAU*li
Levellied Operating
and Maintenance.
¦llls/kU*h
FCO
0.4ft
CaCOj
3115
158
15.97
4.39
11.58
LIMB
0.4ft
CalOHfe
1134
19
4.87
0.54
4.33
LIHB
0.4ft
Ca<0N|2«Ng<0M)2
1366
21
5.87
0.58
5.29
LIMB
0.40
Ca|0N)2*
961
18
4.13
0.49
3.64
FGO
1.92
CaCO)
1377
170
17.53
4.73
12.80
LIMB
1.92
Ca|0N)2
921
27
11.77
0.74
11.03
LIMB
1.92
Ca(0M)2*Mg(0M|2
1070
28
13.74
0.79
12.95
LIHB
1.92
Ca(0M)2k
761
30
9.69
0.B2
8.87
a Includes leveltie4 capital plus levelIie4 operating nalntenance charges,
k froaotee sorfeent.
-------
SESSION VII: S0R8ENT AVAILABILITY AND COSTS
Chairman, Richard Hooper, EPRI
36-i
-------
AN UPDATE ON THE APPLICATION OF LIME PRODUCTS FOR SOg REMOVAL
David C. Hoffman
Chemical Lime, Inc.
and
Oonald H. Stowe, Jr.
Dravo Lime Company
In conjunction with the
National Lime Association
Arlington, Virginia
ABSTRACT
In the early years of utility SO- removal 1n the United States, scrubbing equipment
manufacturers offered several "Wet" processes utilizing different reagents. The
most popular processes employed high calcium lime; magnesium modified Time; high
calcium limestone; and sodium based alkalies as their scrubbing reagents. As in
most industries where technology is continuously evolving, these processes have
become more and more efficient, along with the coimercialization of a major new
process — dry scrubbing. Because of the need for further SO- reductions from
existing sources, new technologies are starting to be visualized ^nd are receiving
mere laboratory and developmental attention. One of the more promising
technologies involves the direct Injection of lime-based absorbents into the hot
flue gas stream.
The major objective of this discussion is to highlight current economics on today's
most popular wet scrubbing systems with major emphasis on reagent aspects.
Additionally, state-of-the-art technical and economic considerations on direct lime
injection will be reviewed, with the commercial reagent emphasis centering on
today's existing lime industry (location, tonnages, manufacturing processes, etc.).
The question of Hme manufacturing flexibility to meet current and projected Hme
demand will be discussed with respect to assumed commercialization of direct 1ime
injection technology.
With these variables in better perspective, 1t can be seen that today's Hme
industry is attuned to SO- removal reagent needs, and will readily respond to the
anticipated needs for UnwF-based alternative absorbents.
INTRODUCTION
In the early years of electric utility-based SO- removal 1n the United States,
scrubbing equipment manufacturers offered several "wet" processes utilizing
different reagents. The most popular processes employed high calcium lime;
magnesium modified lime; high calcium limestone; and sodium based alkalies as their
scrubbing reagents. As 1n most industries where technologies are continually
evolving, these processes have become more and more efficient; along with the
commercialization of a major new process — spray drier scrubbing, I.e., dry
scrubbing. Because of the need for further SOg reductions from existing sources
36-1
-------
and their unique retrofit requirements, new technologies are starting to be
visualized and are receiving tremendous laboratory and developmental attention.
One of the more promising technologies involves the direct injection of lime based
absorbents into the hot flue gas stream, i.e., dry injection.
The major objective of this discussion is to highlight current state-of-the-art
technical- and economic considerations of dry lime injection with respect to the
commercial lime industry. In. order to understand the lime industry, a brief
overview of the industry will be undertaken discussing the major manufacturing
processes, locations, markets, new technology, etc. Additionally, projected demand
for lime products with respect to various acid rain demand scenarios will be
presented.
The assumption throughout this discussion is that, if one were to go commercial
with dry lime injection technology today, lime-based products, calcium hydrate and
dolomitic hydrate, are the only reagents that can meet the general process goals of
60 to 70 percent SO- removal at a 2 to I calcium to sulphur mole ratio based on
inlet SOj concentrations.
IDENTITY OF THE LIME IN0UST3Y
As is quite typical of many industries, what they do and what they manufacture may
be confused with other industries. To help clarify the lime industry, lime
manufacturing typically involves three major operations:
CI) Quarrying or mining the starting natural resource — limestone.
(2) Manufacturing the limestone into a finished product — quicklime.
(3) Remanufacturing of the quicklime into lime based products — hydrates.
Two words have been mentioned that are often confused with one another — limestone
and quicklime. Limestone is the natural resource that 1s found in the earth. It 1s
a carbonaceous rock of varying calcium carbonate content; typically greater than
90" calcium carbonate (CaCO,). A common species intergrained with many limestones
is magnesium carbonate (MgC03). Depending upon the magnesium carbonate concen-
tration (usually greater thin 40%), the limestone may be called "dolomitic
limestone." Dolomitic and calcium limestones are mined, processed, and handled 1n
similar ways. However, the calcining conditions vary, depending upon the desired
product. For purposes of this discussion, emphasis will be placed on high calcium
quicklime or Hme products that usually contain less than 2.5S by weight magnesium
oxide. However, current experimental data on dry injection indicates that
dolomitic products are applicable. Process economics, based on delivered prices of
each, may greatly influence the choice of reagent, high calcium or dolomitic lime
products. The delivered price will be Influenced by the transportation cost from
the closest lime producer, dolomitic or high calcium.
The initial lime manufactured product, quicklime, calcium oxide (CaO), Is not
found in nature. The chemical conversion process from limestone to lime involves
the heating of limestone to a minimum of 1,652°F (900"C) to liberate the carbon
dioxide and to produce the highly active quicklime. Quicklime readily reacts with
water or water vapor to form the lime product, calcium hydroxide CCa(0H)^3•
In 1983, lime 1n its oxide or hydrate form was the number three (3) ranked
industrial chemical. Table 1, Leading Lime Uses In 1983. (attached) tabulates the
latest statistics on the uses of lime. The environmental uses of lime; sulphur
removal, sewage treatment, water purification, and acid water treatment, amount to
22.55 of the total market, or 3,353,000 tons of lime. Of this 22.5%, approxi-
mately 30S, is devoted to SO- removal — 1,019,000 tons. This is illustrated in
Figure 1, U.S. Environmental Pses Of Lime, (attached).
36-2
-------
Lime for SO- removal is already a significant part of the lime industry and
emphasizes the lime industry's commitment to the FGO industry. Figure 2,
Commercial Lime Plants In The U.S. & Canada, (attached) depicts the location of the
commercial lime industry. These plants are quite widespread and FGO lime needs can
be met from existing capacity. Currently, it is estimated that the commercial lime
industry in the Continental United States can supply an additional five million
tons per year of quicklime from their existing capacity. It is envisioned that
additional dry lime injection needs will be met from capacity expansions at
presently existing lime production facilities.
LIME PRODUCTION
As in any supplier-user situation, and more so in the case of long-term FGD
contracts, it is important to understand each others production modes. Figure 3,
Lime Manufacture Flow Sheet, (attached) outlines the various steps that are needed
to manufacture high quality quicklime and lime products. This operation is not
quite as simple as digging up limestone, heating it, and delivering the product to
the customer. Although not emphasized on this flow sheet, there are numerous
quality control check points, such as stone sizing, quicklime testing to meet
production guidelines, and delivery testing to assure the product meets the
customer specifications according to ASTM, AWWA, TAPPI, etc., procedures.
This flow sheet can also be classified into four major areas:
1. Precalcination limestone preparation
2. Calcination of the limestone
3. Product classification
4. Hydrate production
Precalcination limestone preparation can generally be termed quarrying or mining of
the raw stone, plus stone sizing for the particular type of calcining device
(kiln). Oependlng upon the limestone depth below the earth's surface, the lime
producer will use quarrying or underground mining methods to extract limestone from
its natural bed. Figures 4-7 (attached) depict various practices in producing the
right quality of stone prior to calcination. The overall intent of this phase of
lime production is to produce the right size of stone that can most efficiently be
calcined into lime 1n a particular type of kiln while minimizing the waste
limestone (fines).
At this point, the limestone has been prepared for calcination, or conversion, into
quicklime. Briefly, calcination 1s the controlled liberation of carbon dioxide
from the calcium carbonate portion of the limestone rock. Theoretically, this is
accomplished by heating the stone to the dissociation temperature of approximately
1,652'F (900°C). There are several factors that affect this chemical conversion
and dissociation temperature, but the rapid and continuous eyolutlon of CO. gas is
a major objective.
Based on the most recent survey of the National Lime Association, approximately 383
of the commercial producers use a calcining device called a rotary kiln to
manufacture quicklime. This same poll indicated that the following types of fuels
are used in lime calcination:
36-3
-------
Table 2
Fuels Used for <11n Firing
77.6% — Coal
15.25 — Natural Gas
5.6% — Bituminous or Petroleum Coke
1.5S - Oil
In conclusion, today the most prevalent type of calcining device in the United
States and Canada is the rotary, coal-fired kiln.
Figure 8, Coal-Fired Rotary Preheater Kiln, (attached) is a cross section of a
modern, preheater, rotary kiln. Sized limestone enters the preheater section above
the feed end of the kiln. Hot kiln exhaust gases at 1,000-1,300°F preheat the stone
before it enters the kiln and are reduced in temperature to approximately 350°F or
less as they exit the preheater. It has been reported that as much as 20 to 50S of
the calcining takes place in these preheater sections. As the stone rotates down
the kiln, it may pass over a trefoil, dams, and/or lifters that have been designed
into the internal refractory shell of the kiln to effect more transfer of the heat
into the lime bed. As the calcined lime exits the kiln, it drops into a contact
cooler where ambient air 1s forced, counter-currently, up through the hot lime bed.
This cools the Hme and the warm air is used for combustion air and coal drying.
It is common for a properly designed and operated coal-fired, preheater kiln to
consume about 4.5 to 5.5 million BTU/ton of lime.
SIZING, STORAGE, AND DELIVERY
At this point in the manufacturing process, the quicklime has been made and 1s
cool; is now ready to be sized, portions converted to hydrate, stored, and
delivered to customers. The choice of processing equipment and product sizes 1s
usually dictated by the market and primary mode of delivery. Typical delivery
modes are by covered hopper rail car, covered dump trucks, pneumatic trailer
trucks, and to some extent, covered barges. Typical physical sizes available
include 1 3/4" x 0, 3/4" x 0, 3/4" x 1/8" and 1/8" x 0. Screened quicklime
products are also made Into hydrated lime by adding a controlled amount of water.
Both quicklime and hydrate are stored 1n large metal or concrete silos that are
watertight and delivered in watertight equipment.
Transportation Is always a consideration in bulk lime deliveries due to cost and
the type of equipment utilized. Table 3, Typical Transportation Modes, lists the
three major delivery modes, unit tonnages, delivery radius, and associated costs
that are seen today by the lime industry.
Table 3
TYPICAL TRANSPORTATION MOOES
Tons/Shipment
Competitive
Range
(Miles)
Typical
Costs
(S/Ton Mile)
Truck
20- 25
90- 100
1,000-1,500
0- 300
.06-.12
Rail
100- 500
.04-.08
Barge
100-1,000
01-.04
36-4
-------
HYDRATE PRODUCTION
As hydrated quicklime is the final reagent material that Is envisioned for dry
injection, it is appropriate to look at today's commercial equipment used to make
hydrate. Figure 9, Typical Flow Sheet Of A Lime Hydratinq Plant, (attached),
illustrates the flow and general equipment needed to produce normal calcium hydrate
and normal dolonritlc hydrate. flriefly, the starting quicklime product Is
gravlmetrically metered into a premlx chamber where the Hme is rapidly mixed with
an amount of water slightly in excess of the stoichioraetrfcally required amount of
water in order to complete the hydration process with little (less than 3 to 45)
moisture remaining In the product. As quicklime hydration Is-a violent, exothermic
reaction, the premixed sol Ids slurry proceeds into the seasoning chamber to
complete the reaction and to fully utilize the reaction's exothermic heat to
produce a dry, fluffy hydrate. At this point, the product can be stored and sold
2S is, or further processed, as shown, for controlled particle size distribution.
Figure 10, Typical Equipment Arrangement of a L1me Hydratlnq Plant, (attached)
depfcts a compact layout for a hydration plant.
Dolomitic quicklime, CaO-KgO, Is a different compound and has different chemical
properties. In particular, the heat of hydration is lower and atmospheric
hydration equipment depicted above for high calcium quicklime is only sufficient
to hydrate the calcium portion of the dolomitic molecule. This 1s commonly
referred to as normally hydrated dolomitic Hme. For complete hydration of both
calcium and magnesium, steam pressures up to 100 PSI are typically used.
Figure 11, Flow Diagram of Pressure Hydration Process, illustrates a typical
process. The major differences are the containment of tEe water/quicklime slurry,
under pressure, and the release of the same for flash drying and particle size
reduction. Referring to the flow sheet, dolomitic quick!fine, usually of a finer
size than used in normally hydrated products, 1s gravlmetrlcally fed into a mixer
for combination with water to form a thick paste. The paste 1s fed to a specially
designed pump and pumped, under pressure, into the hydrating vessel. Unlike normal
hydration, the mixture is retained in the hydrator for up to 30 minutes, as steam
pressure builds and the hydration process continues. The hydrate is released into
a coHector/separator where the fine hydrate particles are separated from the steam
and collected. Oependlng upon the use of the product, the hydrate may be sized and
stored as is. or further reduced in size, classified, and stored for sale.
Attached Tables 4 and 5 contain useful data on the properties of quicklimes and
their resultant hydrates.
A recent survey by the National lime Association of selected member companies
indicated that pressure hydrated dolomitic products have surface areas ranging from
20 to 30 square meters per gram of product. The higher areas may be attributed to
soft-burned, more reactive limes. Normal hydrated materials, high calcium and
dolomitic, were found to possess slightly lower surface areas ranging from 15 to 20
square meters per gram. With respect to dry lime injection for SO- removal,
indications are that particle surface area Is an Important process parameter but to
what degree Is yet to be determined. From a Hme operators standpoint, normally
hydrated materials are easier to manufacture.
Because of the varying bulk densities, flow properties, and tonnages involved 1n
the lime Industry's products, material handling is an Important part of any system
design. Each product — stone, quicklime, and hydrate — has Its own distinct
handling properties and each has to be considered separately in designing material
handling systems. Extra consideration 1n designing a system will greatly reduce
problems when the system starts into operation.
36-5
-------
COMMERCIAL IMPLICATIONS OF DRY LIME INJECTION
in order to address the lime industry's ability to respond to dry lime injection's
reagent demand, one must venture into unclear areas and make some decisions and/or
assumptions about the potential impact of the acid rain issue on the lime industry.
First, let us assume that an eight million ton per year reduction in 1980 emission
levels will occur as outlined in Senate Sill 768 and will occur in the thirty-one
state Acid Deposition Impact Region of the Eastern United States. Table 6,
Example of SO- Reductions Resulting from Acid Rain Legislation, (attached) lists
the expected tonnage impact of such legislation. The total SO- reduction amounts
to roughly 10.2 mil lion .tons. Assuming that this total amount Will be removed with
dry lime injection, based ort a calcium to sulphur stoichiometry of 2 for 601! SO-
removal, the lime reagent tonnage is estimated at approximately 31.4 million tons
of quicklime (based on 95* calcium oxide quicklime).
A mare realistic scenario is probably closer to the one proposed by the Environ-
mental Protection Agency assigning the SO- reductions to five various control
technologies: c
(1) LIMB
(2) Low NO Burners
[3} Physical Coal Cleaning
(4) Lime Spray Drying
(5) Wet Lime/Limestone FSO
Combining the eight million ton reduction requirement with the EPA's various
technologies, Table VII assigns the removal requirements by control process.
Table 7
EPfl Assumed Reductions By Control Process
Control Process Reduction (MP Tons)
LIMB 3.0
Low NO Burners 0.5
Physicll Coal Cleaning l.Q
Lime Spray Drying 3.0
Met Lime/Limestone FGO 0.5
Total SOg Reductions/Year 8.0
The assignment of these amounts 1s based on using the least costly (assumed to be
LIMB) to the most expensive (wet FGO J to a limit of about 5CS of the estimated
maximum capability as estimated by the EPA. If additional removals beyond this
eight million tons are required, these will be assigned to wet lime/limestone FGO.
For purposes of this discussion, we can then combine the Senate Bill 768 tonnages
with the EPA's estimates as listed in Table 8.
36-6
-------
Table 8
Estimated Overall Reductions 3y Control Process
Control Process Reduction (MM Tons)
LIMB 3.0
Low NO Burners 0.5
Physical Coal Cleaning 1.0
Lime Spray Orying 3.0
Wet Lime/Limestone F50 2.7
Total SOj Reductions/Year 10.2
Analyzing the Bureau of Mines Minerals Yearbook section on lime for the past
several years, and discussions with The National L1me Association, it is estimated
that the cornnercial lime industry currently has approximately five million tons per
year excess capacity. Further, breaking this excess capacity down into regions
closely matching those areas in the Acid Deposition Impact Region, it is estimated
that four million tons of excess capacity exist in the region east of the Missis-
sippi. Figure 12, 1984 Uncommrtted Lime Capacity, illustrates this geographic
distribution.
Based on this estimate, the lime Industry has inrnediate capacity to handle the
initial phases of SO- reduction due to this assumed acid rain legislation. As lime
spray drying technology 1s commercially accepted now, this lime capacity could now
meet 74% of Table VIII's projected spray drying demand without adding additional
capacity.
Since there are numerous lime plants 1n the eastern half of The United States,
especially in the Midwest and Mid-Atlantic states, it is felt that additional lime
needs will be filled by expanding calcining and/or hydrating capacity at existing
production facilities as they now exist. This will minimize capital cost and
result in lower lime reagent costs for SO- removal. These costs can be further
minimized if these new kilns can be completely dedicated to a particular user or a
consortium of users within a particular geographic area.
Based on the assumptions presented 1n this discussion for dry lime injection and
lime spray drying (Table B) with 1005 acceptance of these technologies as known
today, 1995 lime demand 1s estimated at 14.6 million tons per year. Utilizing
today's estimated excess capacity and continuing to meet other markets, this
represents a lime short fall of approximately 10.6 million tons per year in 1995.
The cost of such an expansion is difficult to estimate due to the size of a kiln
needed at a particular location to meet demands within a specific geographic area.
For example, a 500 megawatt station required to obtain 60* removal of Inlet SO.
burning 2.55 sulphur coal and employing dry Hme Injection technology with a two to
one stoichiometry may consume 109,000 tons/year of lime(CaO) on a 955 calcium
oxide basis. This would represent a 330 ton per day kiln demand. A single kiln of
this size could easily be constructed, but It may be more economical to construct a
larger kiln in the range of 600 to 1,000 tons per day capacity. Thus, the
estimated 1995 demand for 10.6 million tons of lime might be met by installing 50
to 60 additional kilns of the 600 ton/day capacity type. This represents a 20 to
255 increase 1n the number of-kilns in the United States and can be easily handled
by today's lime industry over the next ten years.
36-7
-------
CONCLUSION
In this brief discussion, an effort has been made to reaffirm that the lime
industry has been involved with the utility industry for many years, by supplying
high quality lime products for SO- removal with conventional wet lime scrubbers and
the newer spray dryers. From the description of the lime manufacturing process, it
is evident that today's lime industry is attuned to the ever present need for
efficient manufacturing processes and employs some of the most modem and efficient
systems in the world.
To meet the impending needs for additional lime requirements, the lime industry is
well positioned in the eastern half of the United States with immediate production
capacity to handle new dry lime injection or spray drier applications. For the
more distant applications in the 1990's, the most economical approach to lime
supply is to expand at the present quarrying and production facilities by adding
kiln capacity. Based on the projections just discussed, this 20 to 255 expansion
can be quite manageable with prudent planning.
In conclusion, the lime industry is a dynamic industry that has conquered the
energy crisis of the '70*s. It has the awareness and existing production capacity
to meet the immediate needs of this new dry lime injection process. And most
importantly, 1t 1s willing to commit its resources to assure industry that lime
will be available when it is needed at competitive prices to meet the future
requirements.
36-8
-------
Farber, Paul S., "Start-Up and Performance of a High Sulfur Dry Scrubber
System75th Annual APCA Meeting, June 20-25, 1982, New Orleans,
Louisiana.
Minerals Yearbook, Lime Section, United States Department of the Interior,
Bureau of Mines, 1983.
Parker, Larry B., "Distributing Acid Rain Mitigation Costs: Analyses of a
One-Mill User Fee on Electricity Generation in the Contiguous 48 States,"
The Library of Coraress, Environment and Natural Resources Policy
Division, April 22, 1983.
Parker, Larry B., "Summary and Analysis of Technical Hearings on Costs of
Acid Rain 8111s," The Library of Congress, Environment and Natural
Resources Policy Division, July 26, 1982.
Peabody Holding Company, Inc., "Economic Impacts of Senate Environment and
Public Works Committee and Acid Rain Legislation-1983, Briefing on Acid
Rain Legislation, Arlington, Virginia, June, 1983.
Internal Communications, National Lime Association, Arlington, Virginia.
Internal Communications, Southern Research Institute, Birmingham, Alabama.
Internal Communications, Kennedy '/an Saun Corporation, Danville,
Pennsylvania.
36-9
-------
s
Sewtflt *
NhivmI jfattti
1
to
fta
Ffgur* 1. U.S. Environmental Uses of Lime
G <*'
Figure 2. Conrnercia? Lime Ptants in U.S. and Canada
36-10
-------
I -.CMW.iiaaffCLxrw
jsSSeaSC
H
I T 1 imTCM.
m. I "
i r^-swr^rmt"*1^^
tausas
r*}
Figure 3. L1me Manufacture Flow Sheet
Figure 4. Quarry Mining
36-11
-------
Figure 5. Underground Mining
Figure 6. Primary Roll Crusher
36-12
-------
Figure 7. Kiln Feed Preparation
Figure 8. Coal-fired Rotary Preheater Kiln
36-13
-------
•T
Typical Plawshaat of a
lima Hydra ting Plant
Figure 9. Typical Flowsheet of a Lime Hydrating Plant
I
! !
Typical Equipment Arrangamant
of a Lima Hydrating Plant
£
I
•»
t
JL *
'U-..
¦_ .~jE
k- ,:
2u
i i
Figure 10. Typical Equipment Arrangement of a Lime Hydrating Plant
36-14
-------
FLOW DIAGRAM
OF
PRESSURE HYDRATION PROCESS
Figure 11. Flow Diagram of Pressure Hydration Process
"V"
Ff-
Butcm Section
t.annnno nmly**
¦nr»t? iim
•»«*
• MfSI
nc nnwa «« « «<
MNirM itNf HfMNI
r»«5l <* i aw
WWUT M«4
Figure 12. Uncommitted Lime Capacity
36-15
-------
Table 1
LEADING LIME USES IN 1983*
Use
i. Steel
a. Vint Purification *•
j. Sulfur Removal *•
4. Pulp uid Piper
5. Soil Stabilization
4. Sewaft Treatment**
7. Sugar Refining
5. Alkalies
9. Magnesium from Sw"«w
to. Retraetory Dolomite
it. Capper Ore Concentration
12. Building Ume
[]. Acid water Treatment**
(4. Calcium Carbide
15. Aluminum and Bauxite
14. Magnesium Metal
17. Glass
11. Precipitated Calcium Carbonate
19. Ore Concentration
aa. Oil and Crease
21. AH Other L'les ^
Tana (iooo's)
"4 of Total
2.193
]«•¦»
[0.0
(^19
4.1
)ii
4.1
J07
1-4
57«
3-9
i66
1.1
}te
J.»
Si7
J-7
*ii
J
190
17*
J-}
ad1
t.l
209
1-4
»3
t-4
I7t
t.l
t.O
til
0.9
to
0.}
5*
0-3
!d<
_±£_
(4.902
IOOU3
* Source • tg a.}4* of Total
Table 4
PROPERTIES OF THEORETICALLY PURE LIME COMPONENTS
PUflCUMC
wopcrnn
quicxum« cpM»omNTa
HVQHATCO UMICOM0QNCNT3
ChemwsiNeme
Cnamtea Ponnula
Molecular w»gm
Melting taint
Decomposition Pouu
Soiling (*omm
Retractive inoee
M«ai 01 Solution at ia*C
Crystalline Form
3 amity
CatewmOnee
CaO
m.»
297Q*C|4«»,F>
2SM*Ci9i«a*F)
taaa
• <133 *g. cat.
CUDM
140
Magnesium Oikm
MflO
40 a
2800'C ;i072"*l
3800'C iSSIJ'H
173«
euOic
3.63
Catcwm Hyerouoe
CatOWj
uow
sap-ciiort'F)
1174 and t S49
• 2.79 kg. cat.
neiagonal
2.343
Magnesium Hyetoiide
JIJM
3*S*CitS3*»>*
1 SHane 1 HO
O.Ong. eai.
neiagonal
2.*
•THere 11 not comoiaia4gr»ement on me nasi aacomoounsngomt of MgtflHi]. nowever m« .«tu*givan
reoreeems me omi oata avaiiaoie.
36-16
-------
Table 5
PROPERTIES OF TYPICAL COMMERCIAL LIME PRODUCTS
QWCKUMCS
mgnCJKiMffi Baiami*
MinCmwuaMi CaO *¦••••(
JWHHOlMT W'3» IJ 1*
-- —
»ma Oiwim'mii w«« '»•<«««• "¦
a«iOO>* «w«. 3 ,1
h»
n*OMTlS
NwCawMm C«OM! CaOMf. M«0
l'u 1441
»*" »»"
jaatK*«aa^'CO*»«n»». «» 3a al*
"" ""
•Tte mm «t f«MM ^ •••" «*••• •• *•*»• '* Mffittam *wiee lihhui«»«
memwmviwii Mfmihumk **n»»wmci»«—«~*«•»»«
. ?*• MR <• uMt m MM***—9 *
Table 6
EXAMPLE
OF S02 REDUCTIONS RESULTING FROM ACID RAIN LEGISLATION
Mmmm
DiMMt «i
itlfe
HIM
Marvin
Uuac
MiehtaMi
Nca Ysrt
North Cantata
Ohm
Smr Cwoiipa'
w«t vti
Olnin
Taut
EiimnaM GnMk Tout Ra*ctai P«
utO'M Raouwarf t«ts
I MM ia* . _r_ ^ ^
so. gL— iff? soffit "«f ' ml "Wfrt
tjM
Tl.»
>**¦>
•JJ-7
•J7-7
*•?»»
MfcJ
JJ»4
*77.7
911.7
I ST**
All.)
JeU
m*«4
)«.«
)i)4
iQtt.a
H4
M«.T
>iU
U.tOO.7
JIO.J
414
>x.l
u
•T.J
»l
u
<»7
M
ll.»
•J.I
>74
OA
M
«•
*74
J71.7
!»'
JJO.I
l»M
50*1
Uli
-174
37*4
I.14M
•IT.J
1. |U
>!<.)
1.4
7U
•Hi
¦>*¦1
Ma
>414
«|4
7«-«
< I4-J
iom
!.)•*«
W4
t.771.*
tll.J
• W74
I'M
M
1-7
0J>
•M
m.l
5U>I
«4
»<>J
M
9-5
a*
».}
iaa.t
1074
«1U
A.i
«•>!
_jLhl
9514
7.***4
l.H»«
¦O.I9M
17
lit
0
J«
•
>•
»
rr
u
»
it
•
41
It
I*
I*
l»T
M
IS
J«
il
17
«!
u
a
»
si
)l
il
4('
36-17
-------
DRY INJECTION FGO SOOIUM-BASED SORBENTS:
AVAILABILITY ANO ECONOMIC EVALUATION
R.M. Wright
FMC Corporation
Alkali Chemicals Oivision
Philadelphia, Pennsylvania
INTRODUCTION
Injection of a dry pulverized sodium sorbent into the flue gas ahead of a fabric
filter to collect SO- in conjunction with the fly ash is receiving more and more
attention from both the utility industry and potential suppliers of systems and
sorbents. As evidence of both the commercial viability and the substantial cost
savings mounts, it naturally heightens the interest in all involved.
Ory injection SO- scrubbing, as it is now known, is not especially new in concept.
The idea of using a dry sorbent to remove the S02 goes bade many years.
When fabric filters grew in interest, attention turned from fluid bed and regen-
erable fixed bed reactors to direct injection of the dry sorbent into the gas
stream with subsequent collection along with the fly ash. A number of lab and
pilot studies were conducted to prove out the basic concept. The work culminated
in a 22 MW demonstration at the Cameo Unit 1 of Public Service of Colorado. This
test program, under the sponsorship of EPRI showed that dry injection is techni-
cally practical. A subsequent economic study by Stearns-Roger added the icing.
Not only is it workable, dry injection 1s less costly by 20% over 1 in>« spray
dryer scrubbing.
The only problem was that at the time the Cameo work was done there was no one
offering a sorbent that was available. That was three years ago and a tot has
changed. Today there are several suppliers offering commercial quantities of
products to use as dry Injection sorbents and I believe we have only touched the
surface.
This paper will describe the potential sorbents, their sources and availability,
and finally the factors that go into evaluating the sorbent cost to the utility
or other user.
SORBENTS
The heart of dry injection is the sorbent. Chemically the molecule that is remov-
ing the SOg 1s sodium carbonate. The reaction that takes place is:
Na2C03 ~ S02 —> Na2S03 + C02
37-1
-------
3ut the Cameo tests showed very little reaction between commercially available
sodium carbonate (soda ash) and
Fortunately there are a number of other sodium chemicals that will convert to
sodium carbonate under relatively mild heating conditions such as found in the
hot flue gas. These chemicals are any combination of sodium carbonate and sodium
bicarbonate (NaHCO,). And indeed there may be ways found to make soda ash itself
work.
The sorbent choices are numerous. Table I lists the known chemical combination
of sodium carbonate and sodium bicarbonate that are relatively stable. All will
decompose with heat to form sodium carbonate. The time and temperature needed to
achieve the full calcination varies with compound but all can be fully converted
with the residence time and temperature in a typical baghouse.
In addition to these pure chemical compounds several of these occur naturally as
ores. Just to confuse things the ores have different names. Table II lists
these. To describe the source and availability of the various sorbents we will
begin with the ore from which the sorbents originate.
Trona - Wyoming
Trona is the only ore that is being commercially mined today. Commercial deposits
have been located in south western Wyoming and in Southern California. The Wyom-
ing deposit is the remains of a huge ancient lake. The deposit was discovered in
the late 30's and the first commercial plant was completed in 1953 by FMC. Today
five companies mine greater than 12 million tons of trona per year.
The trona is deposited in numerous relatively thick flat beds. The commercially
mined beds are located 800-1500 ft. below ground and are dry mined using many
techniques. This vast reserve contains an estimated 52 billion tons of trona.
The trona ore as mined is relatively pure containing roughly 85 percent sodium
sesquicarbonate. There are a few tenths percent of soluble salts, primarily
sodium sulfate and sodium chloride. The majority of the impurities are insoluble
with dolomite and calcite making up 85 percent of the insolubles.
The impurities have some important effects that need to be considered. The costs
of transportation and waste disposal are greater because of the extra volume of
material. Also the impurities are not as easily pulverized as the crystalline
sodium salt. This may require sizing with a larger grinder and higher power con-
sumption. The extra grain loading on the fabric filter was shown at Cameo to not
requira 4 larger baghouse for satisfactory performance.
Several techniques are available to beneficiate trona to a higher purity. None
are practiced today but could be used if the improvement in value (lower transpor-
tation, disposal and power costs) warrants.
37-2
-------
None of th1s trona is shipped presently. Rather It all goes into making soda ash
or sodium sesquiearbonate. Companies would need to add handling and loading
equipment to make it available for large scale rail shipment to a utility. It
might also be appropriate to do some size reduction at the mine site. Complete
pulverization is not expected to be suitable because of the handling problem. In
addition, if the bulk density gets too low the transportation cost rises.
The surface processes to convert trona into products are important to review.
There are two basic processes that are used by the five producers. They are
termed the monohydrate process and the sesqui process. The monohydrate process
is employed by all producers whereas only FMC uses the sesqui process in addition
to the monohydrate process.
The monohydrate process (Figure I) calcines the trona to crude soda ash before
dissolving and removing the insoluble impurities. The sodium is recovered by
crystallization of sodium carbonate monohydrate (hence the process name). Finally
the monohydrate is heated to remove the water and yield soda ash.
Two solid intermediates are prepared in the course of this process: crude soda ash
and sodium carbonate monohydrate. If either were suitable sorbents they could be
made available relatively easily and in large volumes.
The sesqui process (Figure II) differs in that no chemical change (calcination)
occurs until after the impurities and the recrystallization takes place. The pure
sodium sesquiearbonate crystals are then heated to convert them to soda ash. Only
one solid intermediate is produced in this process: sodium sesquiearbonate. This
intermediate is identical to trona except that the impurities have been removed.
It was successfully tested at Cameo and is available in very large quantities as
with other soda ash intermediates.
An additional sodium chemical is produced by two Wyoming producers. It is sodium
carbonate decahydrate. FMC dredges about 500 M tons per year off the floor of
their evaporation lake. Allied crystallizes deca from their purge stream. Pre-
sently both return the deca to their process to Improve efficiency but the deca
could also be supplied if found suitable as a dry injection sorbent.
Trona - Southern California: Owens Lake
Two dry lake beds in Southern California contain large deposits of trona that
are commercially recoverable. Owens Lake is presently being mined by Cominco
American. The deposit is on the surface of the lake and contains reserves of
50-60 million tons. A section is allowed to drain to remove entrained brines,
me trona is removed and air dried to make it handleable.
The composition of the trona 1s different than that in Wyoming. Purity is 50-70
weight percent sodium sesquiearbonate. Impurities consist of Na-SO*. 5-7%; NaCl,
4-6*; free water,2-10%; and insolubles, 6-10X. The trona is shipped to customers
without further processing.
37-3
-------
Cominco lias stated they could add additional drying and beneficiating (up to about
3531 purity) if needed. To provide different products from this plant would re-
quire a major capital investment to build the necessary processing plant.
Trona - So. Calif. - Searles Lake
Searles Lake is another dry alkaline lake bed that was formed at the same time as
Owens Lake. The existing operation at Searles Lake is quite different from
Cominco's. Kerr-McGee has two plants, Argus and West End, that are recovering
sodium carbonate values from the lake.
Argus is solution mining a trona bed about 350 feet below the lake surface. West
End is mining at shallower depths In a mixed salt layer. 3oth brines are carbon-
ated to crystallize out the sodium carbonate values as sodium bicarbonate. The
primary differences in the bicarb from the two plants is in the level of Impur-
ities in the crystals, West End being higher.
The bicarb at Argus is presently only used as an intermediate in the production of
soda ash. The bicarb is converted to light soda ash followed by sodium carbonate
nonohydrate and then, as with Wyoming producers, calcined to soda ash. West End
does not go through the monohydrate step.
Any of these intermediates, bicarb, light soda ash, or monohydrate could be rela-
tively easily prepared for use as a sorbent in dry injection scrubbing. Bicarb,
of course, was successfully tested at Cameo (as nahcolite).
The two Kerr McGee plants have a combined capacity for soda ash of 1,4 million
tons backed by an estimated reserve at Searles Lake of 900 million tons.
Nahcolite
In the northwestern part of Colorado is located an area containing a very large
deposit of bedded and dispersed nahcolite. This area has been of commercial
interest for many decades both for the nahcolite and more importantly for the
rich oil shales present.
Despite this long interest, no commercial mining has yet taken place. This is
mostly due to the costs of dry mining nahcolite at Its greater depths and lower
assay and converting it into soda ash compared to Wyoming trona.
Industrial Resources, Inc. Is developing a solution mining process that may im-
prove the economics if technically successful. They report the successful com-
pletion of the first phase pilot and are going to begin the second phase soon.
Whereas the dry mined nahcolite was of an assay of about 70X. A product from
IRI's solution mining project would more appropriately be termed sodium bicarbon-
ate because the purity would be expected to be quite high.
37-4
-------
Natrona, Inc. is also Interested 1n solution mining of their nahcolite lease.
They have not yet begun field testing of the process they plan to use. They have
licensed the Shell mining technology that mas worked on several years ago in con-
junction with an oil shale project.
Of more potential impact on costs than solution mining would be a major shale oil
project in the nahcolite zone. Such a project might yield nahcolite bearing ores
on the suface at zero (or low) assigned cost. The low price for crude, the im-
mense capital for such projects and the Federal ownership of essentially all the
nahcolite zone make & venture improbable in the next ten years.
Despite the great potential of nahcolite, until further evaluation shows its eco-
nomic viability, it cannot be counted on to be available as a sorbent.
Other Ores
Wegscheiderite, natrol and thermonatrite are all minerals that have been found in
nature. None have been found in sufficient concentrations or large enough depos-
its to be economically recoverable.
Chemicals
Soda Ash Ue described the sources of soda ash in our discussion of trona with
the exception of a plant at Syracuse, NY owned by Allied Corp. This plant is tie
single remaining Solvay process soda ash plant in the U.S. It uses salt, ammonia
and calcium carbonate as the feed materials. The first stage makes sodium bicar-
bonate. From there on it follows the same sequence as described for Kerr-McGee;
light soda ash, sodium carbonate monohydrate and finally dense soda ash.
This plant is rated at 700 thousand tons per year of soda ash and so has the
necessary capacity to be a supplier of bicarb, light soda ash, monohydrate or
dense soda ash to the dry injection market. Allied also makes sodium sesqulcar-
bonate but 1t is made in a separate plant with a relatively small capacity and
so would probably not be considered a source for sorbent.
Sodium Bicarbonate We have mentioned that large volumes of sodium bicarbonate are
produced by Kerr-Mcfiee and Allied Syracuse as intermediates in soda ash produc-
tion. There is an additional quantity of bicarbonate that is produced for sale.
Four producers operate a total of five plants with a combined capacity of *70
thousand tons per year. All plants begin with soda ash as the starting material
and react it with carbon dioxide to form bicarb in a highly pure form. The dried
and sized products are used in a variety of food, drug and feed markets.
37-5
-------
Church'and Qwight, the largest of the merchant producers of bicarb, is proposing
ta build bicarb plants at the utility site using CO, from the flue gas to do the
carbonation. The economics of such a process depend heavily on the cost of start-
ing material {soda ash) and whether an organic extraction process is required to
attain suitable CQ^ gas.
This is an intriguing concept to take advantage of the lowest transportation cost
and the hignest demonstrated SO- reactivity. However, one real drawback exists
even if the economics are viable. There is the perception even if the utility
does not own or operate the bicarb plant that the process is no longer simple and
"non-chenical".
Sodium Sesquicarbonate This chemical sorbent was discussed in the Wyoming trona
section, it is simply the refined form of trona. FMC's process to make soda ash
via the sesqui process has this purified trona as an intermediate. The process
is rated at 1.8 million tons per year as sesqui.
Currently, some of the sesqui is further purified to remove a trace color impur-
ity before sale to the merchant market. As the slight color has no detrimental
affect on FGO the bulk of the sesqui is available to dry and ship "as is" for dry
injection scrubbing.
Other Chemicals Both monohydrate and decahydrate are made by several producers as
intermediates for further processing to sada ash. Tribi is not produced in any-
t.iing but research quantities. None of these have been demonstrated to be effec-
tive sorbents but were added for completeness.
Table III summarizes the materials that are produced and the capacities that exist
today.
It should be apparent from the foregoing discussion that as compared to as few as
three years ago, the question of whether any sorbent ts available for dry Injec-
tion should be put to rest. The question is now not, "What sorbent is available?"
but "Which should I choose?"
DRY INJECTION COST EVALUATION
It would be appropriate to move into a discussion of sorbent characteristies and
properties. However, that is important enough to be the subject of a separate
paper. Instead I would like to discuss evaluation of costs and how to combine
them into a comprehensive assessment of dry injection costs.
With so many possible sorbents with different properties and shipped from differ-
ent locations the evaluation appears complex. Additional complications enter when
trying to compare all the parts supplied individually or together as a package.
If we have a mechanism to draw all the pieces into one final cast to the utility,
the job is simplified. Hie goal is then to develop a route to a common form of
total cost; levelized cost.
37-5
-------
LEVELIZEO OPERATING COST
Levelizing the cost starts with the total first year operating costs. They are
escalated at the inflation rate for the life of the plant and then discounted to
a present value. This total present value of all future operating costs is then
spread evenly over the project life. The latter is done with the capital recovery
factor.
The sorbent affects the operating costs in a number of ways. Certainly there is
the F.O.B. origin price and the transportation cost plus the scrubbing efficiency
which defines the volume of sorbent needed. Volume of sorbent also impacts the
grinding cost and waste disposal cost.
First the pounds of inlet SO- generated is determined using design information on
the plant size, heating rate, load factor and coal analysis.
We can now calculate the quantity of any sorbent that will be required.
lbs sorbent
- (NSR)I 1.65 ^ I I \
hr [lb Styhr) (^RT-J
where: NSR ¦ normalized stoichiometric ratio for
the sorbent at the required SO^ removal
TA « total alkalinity of sorbent (as S Na^CO^/lOO)
Because the sorbent cost is such a large percentage of the total cost of dry in-
jection, the NSR used in the calculation is of key importance. It is appropriate
to add a contingency in recognition of the risk involved. The size of this con-
tingency for sorbent performance could vary from zero to probably 20* depending
on the degree of confidence in the value for each sorbent and on the level of risk
that the supplier will absorb.
Traditionally a chemical only supplier will guarantee to meet a set of physical
and chemical specifications but not guarantee performance (SO- pick up in this
case). This would place the burden of risk fully on the utility and constitute
the maximum contingency case. The opposite case 1s a supplier that offers full
performance guarantees. In such case no contingency is necessary on the utility's
part.
With the volume Just determined, we can arrive at the total sorbent Dependent op-
erating costs.
37-7
-------
Annual Sorbent * (8760 hr) |ton sorbentj |P + T + G + Wj
operating costs
where: P * Price /ton of sorbent FOB origin
T » Transportation cost/ton
G ¦ Grinding cost/ton '
W ¦ Waste disposal cost/ton
The grinding cost may not be fixed for all sorbents. Some sorbents may require
higher horsepower per ton than others. As no universal index of grindability is
available, relative testing must be done to quantify the differences.
ATI other operating costs can now be added to the sorbent costs to arrive at the
total operating cost to be levelized.
The additional general costs to be added are:
• Operating labor
• Maintenance - labor and materials
• Utilities - This is primarily power with dry injection. If grind-
ing costs have been accounted for in the sorbent cost
the power should not be included again 1n this category.
• Waste disposal - Fly ash only since the waste sorbent has already
been counted.
• Overhead
Levelized Capital Cost
All the typical costs are incorporated into the total capital cost. They include:
• Turnkey system
• General facilities
• Engineering and overhead
• Contingency
• Escalation of capital
• Interest during construction
• Startup
• Land
• Working capital
The total capital cost is levelized by multiplying by the fixed charge rate.
37-8
-------
As with the discussion on contingency for sorbents, if any of these costs are
covered in the suppliers offering, then they should not be counted again. If the
supplier has guaranteed the system performance on SO- removal and availability,
then the added contingency should cover only the general facilities.
Conclusions
The existing capacities to produce proven dry injection sorbents and supplier
willingness to participate in this exciting new technology is more than sufficient
to allow a utility to concentrate their attention on deciding which PGD system
fits best, and assuming dry injection is the choice, which sorbent or which sup-
plier has the best package.
In evaluating the suppliers' offers, the best way to assure that everything is
evaluated on an equal basis and one appropriate to the utilities' need is to
determine the levelized cost. All effects of various sorbents, origins, guaran-
tees, etc will be rolled into one cost that reflects the utilities' cost for
performance.
37-9
-------
FiGUKB I
BUll
-------
FIGURE
II
i
Ml#
Jnnwmm 1—1
—-PrrH
1 ^ (
-------
Table I
Sodium Carbonate Chemicals
Common
Chemical Name Name
Sodium Carbonate Soda Ash
Sodium Sesquicarbonate Sesqui
Sodium 3icarbonate Bicarb
Sodium Carbonate Crystal
Monohydrate Carbonate
Sodium Carbonate Mashing
Oecahydrate Soda
Sodium Carbonate
Trihydrogen Carbonate Tribi
Formula % Na^CO^
Na2C03 100
Na2C03+NaHC03+2H20 70
NaHC03 63
Na2C03+H20 35
Na2C03+10H20 37
Na2C03+3NaHC03 74
37-12
-------
Table II
Sodium Carbonate Minerals
Ore
Chemical Constituent
Trona
1
1
Nahcolite
Wegscheiderite*
Natrol1
Thermonatrite^
Sodium sesquicarbonate
Sodium bicarbonate
NagCO^NaHCO^
Sodium carbonate decahydrate
Sodium carbonate monohydrate
1 Industrial Minerals and Rocks, 4th Ed.; lefond, S.J., Ed.;
Am. Inst. Mining, Met. 4 Pet. Eng. p 1063 (1975)
2 Fahey, J.J. et. al.; Geol. Soc. Am. Abstracts 1961 Ann.
Meetings, p 48A-49A (1961)
37-13
-------
Table III
Plant Products and Capacities*1 (MM Tons)
Calcined Mono- Soda Oeca-
Trona Trona hydrate Ash Sesqui hydrate
3icarb
FMC, WY 5.1 1.8
AIHed, WY 4.0 2.6
NY -
Stauffer, WY 3.3 2.1
IL -
Texas Gulf, WY 1.8 1.2
Tenneco, WY 1.8 1.2
Karr-McGee, CA NA
Cominco, CA 0.1
Church & Owight, WY
OH
Riverside Prod. GA
1.8
2.6
0.8
2.1
1.2
1.2
1.3
2.8
2.2
0.7
1.8
1.0
1.0
1.4
1.8
0.5
NA2
1.1
0.070
2.2
0.190
0.090
0.020
1 Manufacturers and industry sources, capacities are the maximum
for each material but cannot all be produced at one time
2 NA » information not available
37-14
-------
SODIUM BICARBONATE FOR SULFUR DIOXIDE
EMISSION CONTROL
Ray Shaffery
Church & Owight Co., Inc.
20 Kingsbridge Road
Piscataway, New Jersey 08854
ABSTRACT
It is anticipated that more and more stringent controls.on SO2 emissions from
public utility and industrial coal fired boilers will be imposed. It is further
recognized that wet scrubbers, spray dryers and variant systems require heavy
capital investment and are troublesome to operate. The dry sodium based sorbent
injection technique using a bag house for collection of fly ash and reactants
is attractively simple in operation and effective. Important considerations
in the selection of this technique over alternative systems are the reliable
availability of sorbents and the impact of freight to allow dry injection to
be competitive with alternative systems.
The focus of the paper will be on a concept to economically provide sodium bicarbon-
ate as a sorbent to control sulfur dioxide emissions using the dry injection
technique.
GENERAL COMMENTS
It is anticipated that more and more stringent controls on sulfur dioxide emissions
from public utility and industrial coal fired boilers will be imposed. The nature
of the legislation remains to be defined but there is little doubt that substantial
reductions in emissions will be required.
Many collection systems have been tested and some Implemented on major facilities.
Systems which use wet lime or limestone as the scrubbing medium have generally
been effective in meeting emission reductions but also have been recognized to
require a heavy initial capital investment. Further, these units need significant
operating and maintenance attention to assure their performance.
The developing alternative of the dry Injection technique using a sodium based
sorbent offers two major advantages over these wet collection systems.
1. Capital investment is a fraction of that for a wet system; about
15-201.
2. Operation is attractively simple.
38-1
-------
PREFERRED SORBENT
There has been an on-going evaluation of a variety of sodium based compounds for
use as sorbents. Among these have been:
Commercial sodium bicarbonate
Solution mined nahcolite (982 bicarb)
Conventionally mined nahcolite (70S bicarb)
Trona from Wyoming
Trona from California
Sodium sesquicarbonate
Soda ash
In each comparative test, it has been recognized that the manufactured or mineral
form of sodium bicarbonate is the most effective sorbent of the group. Recent
work has indicated that the effectiveness of the sorbent can be further enhanced
by reducing the particle size of the injected compound.
One of the most convincing demonstrations of effectiveness has been the work
performed at the Cameo station by EPRI and reported in the spring of 1983. The
following graphically presents this evaluation. These figures are used for
calculations of relative quantities of each sorbent in this paper. It is recogniz-
ed that the nahcolite used was conventionally mined material with about 3Q3T inert
materials and the remainder sodium bicarbonate. The identification of sodium
bicarbonate as the effective sorbent is clear.
Figure 1. S02 Removal at Steady State as a Function of Normalized
Stoichiometric Ratio
TRONA
SCO A ASH
0 O.S 1.0 l.S 2.0
N5R (Normalized Slaichiomctrte Ratio)
38-2
-------
AVAILABILITY AND PRICE
Even though sodium bicarbonate has consistently demonstrated effectiveness, the
price of commercially available, high quality (U.S.P.) material was prohibitively
high for consideration as a sorbent; about S300/ton plus freight from established
producing locations.
NOTE: U.S.P. refers to the quality specified by the U.S. Pharmacopeia
which defines assay, trace chemicals and other qualities to permit
its use in foods, antacids and other products which are internally
consumed.
Also, nahcolite, the mineral form of sodium bicarbonate, was not commercially
available and required significant elapsed time to demonstrate its consistent
availability and eventual price.
In short, a reliable source of non U.S.P. sodium bicarbonate suitable for use
as a sorbent was required. And, preferably, it was to be based upon raw materials
or minerals which were commercially and readily available.
Against this background, a technique was conceived and technology developed to
produce sodium bicarbonate at the site of a power facility. This process will use
sodium carbonate, wnich is commercially available in large quantities, and carbon
dioxide from stack gases at the power facility itself.
SOME FUNDAMENTALS
To demonstrate the attractiveness of the concept it is necessary to recognize
some fundamental information. And, to do this, the standard Kenosha, Wisconsin
plant with two 500 MW units burning coal with a Q.48S sulfur content has been
selected for illustration.
The required removal level as dictated by the New Source Performance Standard
is 70S of the sulfur dioxide in the combustion products.
Using these criteria and the Cameo data as a basis, the estimated quantities
required of each of the major sorbent options then 1s as follows:
However, if soda ash, the most concentrated practical form of sodium values which
is commercially available, 1s shipped to the Wisconsin location for subsequent
conversion to sodium bicarbonate on site, the quantity is reduced to:
CONCEPT
Tons/Year
Trona
Sodium Sesquicarbonate
Conventionally Mined Nahcolite
Sodium 8icarbonate
solution Mined Nahcolite
136,000
117,000
112,000
79,000
79,000
Soda Ash for on site conversion 53,000 tons
38-3
-------
NQTE:One ton of soda ash will be converted to approximately ore and a
half tons of sodium bicarbonate in the carbonation si.ep on site using
carbon dioxide from the stack gases.
FREIGHT IMPLICATIONS
Freight is a non productive cost. It is also an on-going and usually escalating
cast. It is of fundamental Interest to minimize freight on all materials.
Freight comparisons on the alternative sodium based sorbents can be estimated. A
freight rate of S5Q/ton for all materials shipped from Green River, Wyoming has
been assumed for this illustration and clarity. It should be recognized that
the freight rate actually applied will be a result of negotiations with the rail-
roads involved and individual rates could vary this figure by plus or minus a
few dollars. Further, for nahcolite, which is in a comparatively remote location,
the S50/ton rate may be lower than actual costs to load trucks, transload to
hopper cars and then ship.
Nevertheless, the following chart illustrates freight implications for each:
SGR8ENT
Trona
Sodium
Sesquicarbonate
Conventionally
Mined Nahcolite
Sodium 3icarbonate
Solution Mined
Mahcolite
Soda Ash for on-site
conversion
The carbon dioxide used in this carbonation concept is drawn from the stack gases.
Therefore, there is no freight cost for the gas:
Freight on C02 SO
In short, movement of soda ash for on-site conversion to sodium bicarbonate will
minimize unproductive and on-going freight costs.
AVAILABILITY
At this point, a comment on the availability of soda ash is appropriate. The
current producers in the U.S. and their capacities (as listed by the U.S. Bureau
of Mines) are as follows:
QUANTITY ANNUAL FREIGHT
REQUIRED COST AT S50/T
136,000 T S6.SCMH
117,000 5.85
U2,000 5.6Q
79,000 3.95
79.000 3.95
53,000 2.55
38-4
-------
Producer
Annual Capacity
AT 1ied
FMC
Stauffer
Kerr McGee
Tenneco
Texas Gulf
2.9MM tons
2.85
1.96
1.45
1.0
1.0
TOTAL
11.16MH tons
The production for the first six months of 1984 was 4.2MM tons or an annual rate
of :
Therefore, the present capacity utilization and the additional amount available,
up to capacity, is
Further, availability is not limited to this quantity since many of the operations
are expandable to meet an increased demand. In short, there is and likely will
be an ample supply of soda ash to meet the demand for its conversion to sodium
bicarbonate and soda ash is distributed through an extensive well established
network.
In contrast, trona until recently has not been commercially available and nahcoTlte
sources are still in development stages.
ON-SITE CAR30NATI0N
The following simplified flow chart illustrates that following a bag house, a
portion of the fly ash free gas 1s drawn into a unit to purify and concentrate
the carbon dioxide. The carbon dioxide is combined with soda ash in a reactor
to produce the sodium bicarbonate. This then is available for injection up stream
from the bag house for removal of sulfur dioxide.
OTHER ATTRACTIONS
The attractions of comparatively low capital requirement for a dry injection system
and its simplicity have been discussed. Burdensome freight costs can be held to a
minimum by moving readily available soda ash for conversion to bicarb on-site.
But, there are other attractions to the concept:
Since fewer tons are to be handled, hopper car unloading, bins and
handling equipment are proportionately reduced in size.
Space requirements are lower.
The sodium bicarbonate produced is comparatively fine and friable
the need for high capital grinding equipment is minimized.
There are virtually no insolubles which add to the waste load.
When considered comprehensively, these attractions are also quite compelling.
8.4MM tons
Capacity Utilization
Available Soda Ash
752
2.76MM tons
38-5
-------
FUJE GAS
EXHAUST
STACK —
SO OA
ASH
STORAGE
VENT
VENT
BICARB
DAY
STORAGE
cH
BAG HOUSE
LOWER
DIRTY FLUE GAS
CLEAN FLUE GAS
DRY WASTE
Figure 2. On-site Bicarb
38-5
-------
CAPITAL
COST
S/KV
OIL
21
Conventional Line Sodium
wet Limestone Soray Blcaroonate
System Dryer with Dry Injection
Figure 3.
38-7
-------
ECONOMICS
The comparatively low capital requirement for a dry injection unit is illustrated
in the following chart developed for the Kenosha facility.
Further, levelized bus bar costs for this location have been estimated. These
consider freight, capital, operating and sorbent costs for the Kenosha facility.
On the basis of a 30 year project life the comparison is as follows:
11.1
LEVELIZED
BUS BAR
7.3
COST
NILLS/KWH
5.3
Conventional
Lime
Sodium
wet Limestone Spray Bicarbonate
System Dryer with Dry Injection
Figure "4.
A shorter project life amplifies the economic advantage of the dry injection
technique using sodium bicarbonate produced on-site. To illustrate this a 15 year
life of these same facilities show the following comparison.
38-8
-------
10.3
LEVELIZED
BUS BAR
COST
NILLS/KWH
6.3
1.2
Conventional Lime Sodium
wet Limestone soray Bicaroonate
System Dryer Wltn Dry Ejection
Figure 5.
38-9
-------
The attractions to dry injection and to on-site preparation of sodium bicarbonate
are substantial.
SUMMARY
It is recognized that each power facility has its individual design criteria.
Coal quality, geography, size, retrofit options and many other factors will in-
fluence selection of collection techniques. Each location must, therefore, be
independently analyzed.
In summary, however, a technique has been conceived and a technology developed
which permits preparation of the preferred dry sorbent, sodium bicarbonate, at
the site of a power facility. This technique will strongly support the dry sorbent
injection alternative to control SO2 emissions and enhance its fundamental attrac-
tions of reduced capital and simplicity of operation.
38-10
-------
SESSION VIII: FIELD APPLICATIONS AND FULL-SCALE TESTING
Chairman, Richard Stem, EPA, IERL/RTP
39- i
-------
REDUCTION OF SO^-EMISSION IN BROWN COAL COMBUSTION;
RESULTS FROM RESEARCH AND LARGE SCALE DEMONSTRATION
K. R. 6. Hein, G. Kirchen
Rheini sch-Westfa'lisches Elektrizi tatswerk
Kruppstr. 5
4300 Essen
Federal Republic of Germany
ABSTRACT
For more than 10 years the Rheinisch-WestfJflisches ElektrizitStswerk (RWE),
Germany's largest utility company was involved in the development of the Dry
Additive Process (DAP) for SOa removal by utilizing dry calcium based materials.
Based upon results from trials at a combustion rig and a 60 MW utility boiler a ¦
full scale demonstration plant at a 300 We brown coal boiler was installed.
During a more than one years' program at this installation the reduction of SO,-
emission, the maximum possible amount of additives with regard to ooerational
behaviour of various power station components and different injection modes have
been investigated. The large scale operation was accompanied by rig tests con-
cerned with the application of CaO-rich ashes from different preparation proce-
dures.
The paper deals, apart from the major results for SO.-reduction of the three
different test scales, with various operational problems associated with the addi-
tive injection and discusses the experience with practial solutions.
INTRODUCTION
During the last decade an increased utilization of solid fossil fuels in large
scale heat and steam generation facilities (particularly in electricity production)
was observed. This tendency was especially well pronounced in countries which con-
tain coals of different ranks, which - up to a recent date - were not competitive
with cheaper imported fuels.
Ouring the same period of time, environmental considerations in industrial and uti-
lity combustion became a major concern; these concerns were expressed by the adop-
tion of clean air acts 1n several countries. Therefore, industry was forced to re-
duce and maintain certain concentrations of discharged solid and gaseous matter in
flue gases below a maximum concentration allowed, set forth 1n the clean air acts.
Among the noxious gases, sulfur oxides are of major importance; they become
available as combustion products from sulfur which is bound organically within the
39-1
-------
fuel as a mineral impurity.
The techniques for reduction of sulfur oxide emission are, in principle, known
and in many cases are used on present combustion systems. In general, there are
various methods applicable:
- fuel selection and blending
- sulfur removal prior to combustion
- wet flue gas cleaning
- retention of sulfur oxides during or after combustion
by dry sorbents.
The first two methods can be only applied under certain site specific conditions,
and are in most cases technically and/or economically efficient if stringent
emission limitations are set by performance standards. Wet flue gas cleaning, how-
aver, is at date a known technique and SO, scrubbing systems are installed e. g.
behind oil, bituminous, and subbituminous coal fired boilers.
Experience with coal fired units is, with restrictions, positive; but this may not
be necessarily transferable to systems burning other fossil fuels, e.g. low rank
fuels like brown coals. Also, phenomenological, technical, or economical conside-
rations very often show that the installation of scrubbing systems may not be the
most appropriate solution. This is particularly true if existing power stations
must be retrofitted with S0,-removal devices. In the above cases, the application
of processes using dry sorbents, which may be blended with the fuel or injected
either into the combustion chamber or the flue gas duct, offer major advantages.
BASIC CONSIDERATIONS
During combustion the sulfur content of the fuel is converted primarily to SO,.
The subsequent oxidation to S03 is kinetically limited and,therefore, its concen-
tration is small in most cases. For solid fuels with high concentration of basic
components, like coals from the Rhinish basin in the Federal Republic of Germany
a high percentage of the SO, is retained in the fly ash in the form of solid sul-
fates. It is believed that a catalytic surface reaction
MO + SO, + 1/2 0, MSO^ > (M » basic metal)
is responsible for the sulfation process. This "natural retention" is a hetero-
genous reaction which is not only dependent upon the local temperature and con-
centration of the reactants and their products, but also upon the mixing of the
species and the available surface area of the solid component. Since the thermo-
dynamic equilibrium conditions are not attained in practical combustion systems,
the residence time must also be considered. The sulfation process described above
can be used for further S0a removal if a basic oxide is added to the fuel or the
combustion products. The residence time available in the necessary temperature
range for sulfation is limited, and therefore a high specific surface area of the
solid additive and optimal mixing of the additive with SO, are vital conditions.
SPECIFIC PROPERTIES OF RHINISH BROWN COALS
In the Federal Republic of Germany the brown coal from the Rhinish basin is one of
the important primary energy sources with an annual mine production of 120 million
tons. 100 mill ion tons of these are burnt in power stations to generate almost
30 % of the total public electricity demand in the country.This fuel differs from
other solid fossil fuels (e.g. bituminous coals) in many respects. The high
39-2
-------
moisture content of 55 - 62 % leads not only to a considerable flue gas volume
but also limits the maximum flame temperature not to exceed 1150 °C. Also the
high specific fuel consumption of 1.1 - 1.4 tons/MWh, approximately 3 to 4 times
higher than for German bituminous coals, prevent sufficient blending which would
be necessary to guarantee a reasonably homogeneous fuel composition. Consequently
the utilities are faced with a large and unpredictable variation of fuel proper-
ties. Typical fluctuations based on shift averages for the two important components
Ca and S are shown in Figure 1; similar variations can be expected - and are
supported by measurements - on a smaller time scale. As a result SO, emission from
boilers will also vary unpredictably over time. The stack values (shift averages)
in Figure 2 show this for 4 boilers. It is notideable that with a similar fuel
composition the different installations produce absolute S03 emissions which differ
strongly. Obviously the "natural SO, retention" is dependent on the local boundary
conditions, in particular the time/temperature history of the sulfation process in
the combustion chamber. Values of the "natural retention", defined as given in the
Appendix, between 20 and 60 % are experienced /1/.
DRY ADOITIVE PROCESS TEST RESULTS
Based on the favourable effect of the "natural SO,-retention" and with the inten-
tion to further reduce the SO, emission as required the Rheinisch-WestfSlisches
ElektrizitXtswerk AG (RWE) initiated test work as early as 1974 in a combustion
test facility (0,5 - 1 MM thermal capacity). Major reasons for choosing the dry
additive process (OAP) for SO, removal from flue gases were that the typical com-
bustion conditions in brown coal firing systems favored the sulfation process, at
that time wet FGO systems showed major operational problems, and in particular, no
experience was available for fuels with strongly variable sulfur contents. The re-
sults of the test work /2/ are summarized in Figure 3, which shows qualitatively
the dependence of the sulfation reaction upon main combustion parameters as well
as properties of the sorbents. Eventually, an optimal temperature range with re-
gard to calcium sulfate formation was found somewhere between 600 and 1000 °C. In
order to illustrate the proposed layer-type reaction, Figure 4 shows a scanning
microscope analysis of an additive particle after its passage through a brown
coal fired combustion chamber. While the element calcium is evenly distributed
over the total cross-section indicating the particle being of additiveorigin
(Figure 4C), the distribution of sulfur (Figure 48) shows an enrichment at the
outer edges. This indicates that the SO, is clearly concentrated at the particle
surface. This result is further emphasized by the line scan analysis of sulfur
across the white center line (Figure 4A), which shows sulfur peaks on either side
of the particle.
Also by electron microscope analysis the structural changes of e.g. hydroxide sub-
jected to different temperatures can be clearly shown (Figure 5). In a gaseous
surrounding with a temperature of 500 ®C (Figure 5A) the original crystal struc-
ture of the additive, indicated by the sharp edges of the material, is still visi-
ble. When heated up to 1100 °C (Figure £3) the single particles are strongly in-
terlinked and their outer surfaces show a rounded shape which obviously results
in a reduction of the specific surface area. Further heating up to 1350 *C
(Figure 5C) results in a much stronger inter-connection between the particle and
an additional strong decrease of the available surface for reaction. This decay
of surface area at elevated temperatures, known as "deadburning" of the additive
was already shown elsewhere /3/ by measurements of specific surface areas for
various materials. It also was proven (Figure 6) that any variation of the tempe-
rature in the combustion chamber, expressed either as the maximum flame tempe-
rature Tmax or the chamber exit temperature Texit. greatly influences the SO,-re-
tention. Furthermore the SO,-partial pressure prior to sorbent utilization which,
39-3
-------
in turn, is strongly related to the sulfur content of the fuel and the Ca-based
natural retention, is a vital driving force for the sulfation reaction when sor-
bents are applied (Figure 7). Additional detailed investigations on almost 70
different additives also revealed /4,5/ that type, origin, and preparation of the
sorbents may substantially affect the SO, removal efficiency.
LARGE SCALE DEMONSTRATION EXPERIENCE
Based upon the described small scale results, a utility boiler with a capacity of
SO MWe was equipped with an additive feed and distribution system in order to
investigate the dry additive process under operating conditions. The results
gained at this boiler during detailed long term testing from 1977 up to 1979 were
very promising /2/, leading to the decision of a full scale demonstration at a
300 MWe boiler. The installation was erected in 1982 and a full year trial ope-
ration followed in 1983. Since January 1984 this boiler is run on base load ope-
ration with constant sorbent addition of 3 % pulverized limestone fed to the raw
coal prior to the mill. The large scale demonstration project follows the general
scheme which is shown in Figure 8. The additive is delivered to the site by rail
transport and is fed via storage bunkers and distribution vessels, such as screw
feeders or similar conveying systems, to the coal feeder which supplied the coal
to the mill. Both coal and additive are intimately mixed when passing through the
mill and the mixture is then transported to the burner. The calcination of CaCO,
or the dehydration of Ca(OH),, both resulting in free lime, and the subsequent
calcium sulfate formation takes place within the boiler. The product together with
the fly ash, is finally removed from the flue gases by the electrostatic precipi-
tator.
The trials were subdivided into several series burning a large variety of brown
coals with different compositions, in particular strong variations of sulfur and
calcium. Also various sorbents from different origins including on site prepared
hydroxides were tested. Some typical results are given in the following figures.
Figure 9, left, proves (although some scatter exists) that SO, emission after
natural retention is a function of the sulfur in the coal. The SO, removed by
natural retention alone (Figure 9, right) can be as high as 2500 mg/m*; the in-
creasing tendency with increasing sulfur content of the fuel is expected. Con-
sequently fairly high values for the retention efficiency and the utilization of
the calcium is the coal are calculated (Figure 10).
If the SOj-removal by Ca is plotted (Figure 11), the expected increase with both
Ca(QH), and CaCO, is shown, although the hydrate is more effective leading to a
steeper gradient. The strong scatter is typical for large scale operation, major
reasons are the time dependent fluctuations of the fuel composition and the ope-
ration boundary conditions. The calculated Ca-utilization (Figure 12) for both
the additives is - within limits - fairly constant over the range of sulfur in the
fuel investigated. The fairly low values are mainly due to the fact that the
demonstration boiler had peak temperatures above 1200 °C, which is higher than the
average when burning this fuel.
Parallel with the demonstration tests, comparative short term measurements of
various other brown coal fired boilers with a constant sorbent addition of 3 %
CaCO, to the fuel were carried out. Figure 13 shows - apart from the scatter -
that again the dependence of the SO, emission on the sulfur in the fuel is obvious.
The calculated difference of the regression curves with and without sorbent
addition, A SO,, also shows this tendency. Finally, Figure 14 compares these
SOj-removals (3 5 CaCO,) for 4 different power stations when the same sorbent type
and percentage was applied. It can be clearly seen that site dependent variations
in operational parameters will lead to different emission reductions and that
39-4
-------
variations up to 100 % for the same sulfur content in the fuel can be experienced.
INFLUENCE ON C0«USTI0N SYSTEM OPERATION
During the long term tests several effects of the OAP on operation were observed.
In large boilers the heat transfer pattern will change due to the more opaque
atmosphere in the combustion chamber. This results in a shift of the main tempe-
rature profile into the downstream direction. Typically, Figure 15 shows the
variation of the heat received by the various heat exchange surfaces. 100 % being
the case without any sorbent addition the change with increasing additive per-
centage - the values for 4 % and 10 X CaCO, to the fuel are given - is obvious.
Also a slight increase of the flue gas exit temperatureof 5 to 10 *C downstream
of the air preheater was observed.
An increased deposit formation is also unavoidable but can be dealt with by the
installed water - and steam-fed blowing devices. Only in high temperature areas
problems due to fast sintering of the deposits may ask for more attention, par-
ticularly on long term operation. In addition the air pre-heater tends to foul
more rapidly, but cleaning was even after 7000 hours of operation not yet neces-
sary.
Extensive grid measurements of the dust loading of the flue gas before and after
the electrostatic precipitator had shown that for the demonstration plant no
decrease of the precipitation efficiency occurred. However, an increase of the
voltage by up to 10 % above the normal operation value without sorbent injection
was observed after several days of high sorbent addition rates (> 10 2 relative to
the coal). Also with some precipitators of older design an increased occurrence
of field breakdown was observed. With variable sorbent percentage a recovery
effect was noticeable when the sorbent amount was reduced. A detailed observation
of the plattens revealed the build-up of a deposit layer which even by enhanced
rapping cycles was not removed completely.
The most problematic effect of the DAP was found in the ash handling system.
The high concentration of free CaO in the ash tends to hydrate immediately in the
presence of water. This not only leads to time dependenthardening of the ash
during transport but also results in steam formation of any remaining water due
to the exothermic hydration reaction. Consequently In-housed ash handling and
transportation systems are endangered by water vapor condensation and subsequent
corrosion. This problem can be only solved by temperature controlled hydration of
the total ash prior to handling for disposal oriUrther utilization.
Based on the positive results of the SO,-emission reduction from the large scale
demonstration and under careful consideration of the observed effects on the
boiler performance continuous ope'ration of this 300 MW base load unit with 3 %
CaCOj addition to the fuel flow commenced in January 1984. Between fall 1985 and
the end of 1986 a further 2600 MW (2 x 300 MW, 12 x 150 MW, 2 x 100 MW) will be
installed with the dry additive process bringing the capacity of boilers firing
Rhinish brown coals and equipped with the dry additive process for SO,-reduction
up to a total of 2900 MW.
39-5
-------
REFERENCES
!M K. Hein, W. Glaser; Proceedings of the 11th Lignite Symposium,
June 15-17, 1981, San Antonio, Texas.
Ill K. Hein and A. Schiffers; 8WK 31 (1979) 10, p. 389
/3/ K. Hein, W. Glaser; 6th Members Conference of the International Flame
Research Foundation, May 12-14, 1980; IJmuiden, The Netherlands
!M W. Glaser, K. Hein and G. Kirchen; 7th Members Conference of the Inter-
national Flame Research Foundation, May 9-11, 1983, IJmuiden, The
Netherlands
/SI W. Hlubek, K. Hein; VG3 63 (1983) 4, p. 327
39-6
-------
APPENDIX
1. Natural SO, Retention Efficiency:
ek "
S0»niax " S°2K
S0*max
with S0a ¦ theoretical maximum S0a concentration if all sulfur in
fuel were converted
S02K * actual SO, concentration prior to sorbent addition
2. SO, Removal by Sorbents:
A S0t ¦ so2K - SOj^
with S02^ ¦ SOj concentration after sorbent addition
3. SO, Retention by Sorbents:
'A '
so,K
4. Ca-Utilization:
n • Ca reacted to CaS0>)
* total Ca available
Index i: K for Ca in coal only
A for Ca in sorbent only
39-7
-------
15000
| 10000
.2
5
c
4*
5000
\aI
s calcium
M
. n\l
jh
^AoJ
kjA.
K K f \
Aa
i \
W *
sulfur
1
0 i* 8 12 days
Figure 1. Boiler fuels; 8-hour average analysis
3000
so2
mg
m3
2000
1000
boiler ' "
2 •
3 ~
A A
a-?
f
<
j
U,
9
y a a
» / I
Si
kf
tl-~ ' ¦ ¦ ¦
w
JL«
10 days
15
Figure 2. S02-emission for different boilers,
shift average values (example)
39-8
-------
CaO * S02 *V20Z — CaS04
solid * gas ~ gas ——solid
heterogeneous reaction J 2 phases
BO:
CaO
CaSO*
100
CaSCfe
CaO
0
100
\_
temperature—
mixing —•
CaSOa —
V
time —
surface area—*
# sintering
£00 600 800 1000 1200 °c
Figure 3. Sulfate reaction dependencies (schematic)
39-9
-------
A: Image of particle and B: Distribution of C: Distribution of
line scan of sulfur sulfur calcium
across the particle
along the white center
line
Fig. 4: Scanning microscopic analysis of an additive particle after having passed through the
flame zone (1 cm - 6 |im
-------
Fig. 5: Ca(CH) 2, subjected to
different tenceratures (1 on4 2,5 mn)
39-11
-------
•K
V.
? <
\ 0
1 .rmiw.
i..n
»
rn, '
Q 1
9-9
o ^
7
o/o
1
900 1000 TOO TOO 050 C
flue gas temperature
Figure 6. Natural retention and temperature
SOjtmssian -Knout 3Mitw« (mj/mJ). » <220 • 2950
¦ 2S3Q • tS00
O ctSOO • S3C3
o
0
o ~
0
o°
¦
•
0
0 o
o°2i* 0
0 0 •
O _ Oq"«
. i
• V
0
0
"V ¦ •
o 0v-i:.
_ « * * ¦
:S •• •;»
r
*
1,4
..'J
a ¦ *
•
»2
-ooc
•ax,
YJi
'5CC
2 )
Ca aaatd to oat
V.
Figure 7. S02-removal for different coals
39-12
-------
csntral bunkers inttrmtdiot* bunk«rsyst«n
•sp
.tack
disposal
coal mitt
additive discharge lime stakar
Figure 8. Demonstration Plant 300 MWe (scheme)
2500
2S00
1,5 V»
Sulfur in cool
Figure 9. S02-emission and natural retention A S0^
39-13
-------
TOO
so;
0
8° a
o
'i.
o
h
T° *
w
V
o
¦Vi
0.5
'.0
100!
V.
SO
0
0 0
o
0O§ «
o° «0 <
O 0 a
s
i
£
3'
°o ° <£
o 2oOa'
MS?*
o 0
*
£
1,5
Sulfur in coat
0?
\0
Figure 10. S02-retention and Ca-utilisation
10001
JOOOi
200C-
1000
3000
2000
100®
j.-.
coot only
Co in coat
1,5 V.
T
5«S
%° &
CaCOj
2.S
Co addtd to cool
Figure 11. SOz-removal by calcium
39-14
-------
1-Co
SO
•/.
25!
'%
1
1
k—
0.5
1.0
Co (OH).
1.5 V.
SO
•/.
251
0^5 1,0
Sulfur in cool
Co C03
1,5 V.
Figure 12. Utilisation of calcium
2000
£00'
XXX
SCO
so2 rj
without L. SOj
odd it iv t
o4 '«
V
* *
~ *¦ ±
¦fiA-
with
• odd 1 live
1
O
•
2
Q
¦
1
O
;
W
~
5
A
*
?
a
•
unit
oiinouC witn
addil iw*
(£ Qt 0,6 0,8
SUM M COAL
Figure 13. S02-emission from different boilers
39-15
-------
0,75
Q
i
v
Sulfur in coat
Station a : t boiler, long term tests
Station b: 5 boilers, short term tests
Station e: S boilers.short term tests
Station d: ' boiler, long term tests
Figure 14. $02-removal by 3 % CaCO, to coal
1
1
1
¦¦I
ip
I
Economizer 1
Reheater 1 Q
Superheater 1 J|
Tnflu*
•v
Superheater 2
J
Reheater 2
J
1
Superheater 4
Superheater 3 j
1
i
Combustion Chamber
30 90 100 no 120 00 14] cv.3
Figure 15. Variation of heat absorption
39-16
-------
REDUCTION OF SO- EMISSIONS FROM A
COAL FIRED POWER STATION BY DIRECT
INJECTION OF CALCIUM SORBENTS IN FURNACE
H. BR ICE(a), S. CHELU(b), G. FLAMENT(b), R. MANHAVAL(C), M. VANDYCKE(d)
(a) Charbonnages de France, Houillfcres de Lorraine
(b) Charbonnages de France, CERCHAR
(c) Charbonnages de France, Houilitres de Provence
(d) Stein Industrie
ABSTRACT
HOUILLERES de PROVENCE, a company of the Nationalized Group "CHARBONNAGES de
FRANCE" has conducted a trial series in a 50 MWe power station in GARDANNE (south
of France) in order to evaluate the feasibility of applying the direct SO- capture
in flames by dry calcium sorbents injection to a newly built 600 MWe unit.
This campaign of measurements on the 50 MWe boiler followed a preliminary study
that had been subcontracted to the International Flame Research Foundation
(Ijmuiden) 1n 1982 arrd where effects of sorbent quality, sorbent injection
location, flame temperature and flue gas recirculation upon efficiency of S02
capture had been determined.
The experiments have indicated similar trends on the 50 MWe boiler as on pilot
scale except for flue gas recycling which was effective in improving SO- capture
in the pilot scale experiments but had no effect on the boiler.
On the boiler 1t was found that natural retention of sulphur in the calcium rich
ash followed similar trends as retention by injected calcium carbonate ; more than
50 X SO. removal could be obtained with Ca/S * 3. Ca(OH)- was a much more
efficient sorbent and 60 % SO. removal could be obtained with some Ca(0H)2
injection and a high ash coal lit a total Ca/S ¦ 3 (2.4 for the ash and 0.6 for
Ca(0H)2).
Injection of sorbents above the upper burners elevation gave the best results.
The results of the 50 MWe tangentially fired boiler have been used to design the
modifications required for applying the technique to the 600 MWe boiler which
has just started operating.
40-1
-------
REDUCTION OF SO- EMISSIONS FROM A
COAL FIREO POWER STATION BY DIRECT
INJECTION OF CALCIUM SORBENTS IN FURNACE
INTRODUCTION
The Gardanne Coal
The coal considered here is produced, at a place called GARDANNE, located in
PROVENCE, about 30 km north of MARSEILLE, 1n the south of FRANCE. The coal is
mined by HOUILLERES de PROVENCE, a company of the Nationalized Group "CHARBONNAGES
de FRANCE". The output of the mine amounts to about 1.5 million tons per year and
a large fraction of it is used for electricity production in a power station owned
by HouillSres de -Provence and located at the same place. The rest (about
300 000 t) is cleaned to around B % ash and is used by the local industry.
Although mined underground the seams are thick and regular which allows a high
productivity -about double the average productivity in the country-. Moreover the
reserves are quite large (70 millions tons in the field under production plus
another field of 100 millions tons) and on the whole the mining activity 1n this
area has the potential to be economically viable for many years.
Unfortunately the GARDANNE coal contains a lot of sulphur. Table 1 gives analyses
of three qualities of the coal. The washed coal is used in industry but the power
station burns high ash coals.
The "base coal" which was considered for the boiler design has 12 % moisture,
22.3 « ash and 4.1 % sulphur. However the ash content varies and can be up to 35 5
although the fuel actually being sent to the boiler 1s usually below 30 % ash
("high ash coal" in Table IK The GARDANNE coal can be qualified as a sub--
bituminous coal but is close to a bituminous one. It has a high volatile matter
content - 38 % on raw coal but the coal minerals, being very rich in calcium
carbonate, a significant amount of the volatile matter is CO- coming from the
decomposition of carbonates : between 9 % and 14 % of the coal weight.
This high calcium content is a peculiar and interesting feature of the GARDANNE
coal. Figure 1 shows that when a range of coals having variable ash content is
considered, the CaO content in the ash 1s not constant but tends to increase
strongly with the ash content. If one considers the washed coal as one extreme of
the spectrum, it is very low 1n calcium. This result comes from the fact that
calcium is present in the coal minerals in the form of large inclusions of CaCO-
which are easily removable from the organic matrix. These inclusions can be from a
few milimeters in size up to real banks of a few meters length in the coal seams.
On the whole, as illustrated in Figure 1, the molar Ca/S ratio of the raw coal is
in the range 1.5 to 3 which provides an interesting potential for natural
retention of sulphur in the ash.
40-2
-------
The Provence power station
The power station is now made of 5 units :
- three 50/60 MWe units were built in the fifties
- one 250 MWe unit was built in the early seventies
- one 600 MWe unit which was commissioned in October 1984.
The first unit was built by Stein-Alsthom and is tangentially fired. The new
600 MW unit 1s also tangentially fired and has been constructed by STEIN-INDUSTRIE
whilst the three other units are wall-fired. As the 600 MWe unit has been put in
operation, this unit and the 250 MWe unit will ensure the electricity production
and the three 50 MW units are in the process of being shut down.
The environment
There is presently no general regulation in France concerning SO- emissions but in
most places and particularly in industrial and urban areas, SO. concentrations on
the ground are continously measured at numerous locations whi^h are known to be
critically exposed to pollutant falls. When these measurements indicate too high
concentrations, the usually well known SO- emitters are urged to reduce their
emissions by reducing outputs or by burning Tow sulphur fuels.
The urban area around MARSEILLE is particularly protected in this way due to the
presence of a number of large industries (oil refineries, iron and steel indus-
tries, power station, etc...) which are known to be SOg emitters.
There is also, for the city of MARSEILLE, 6a local regulation -.limiting the S0-
emissions to 0.58 g/MJ (equivalent 2.4 g/10 kcal or 1.32 lb/10 Btu). Thus there
has been, before and during the construction of the 600 MW unit a strong local
pressure towards a significant reduction of the local impact of SO- emissions from
this new unit of the power station. A first answer to the concern flas the erection
of a 300 m high chimney in order to improve the pollutant dispersion. The main
effect of this very high chimney was to attract further attention of people to the
subject which resulted in some more pressure to actually reduce SO, output. In
1981 Charbonnages de France studied the possibility of setting up an F.G.D. system
for the 600 MW unit but it was concluded that this solution would deteriorate to
an unacceptable level the profitability of the power station and consequently of
the mining activity itself.
Therefore, in April 1982, Charbonnages de France opted for direct SO- capture. The
objective was then to improve the natural retention if possible and to Inject
supplementary sorbent in order to achieve 60 X SO- capture at a much lower cost.
This option was considered to be an acceptable Ampromise between environmental
and economical demands. A research and development programme was then initiated in
order to test and demonstrate the viability of this technique for the new 600 MW
boiler that was already partially built.
PILOT SCALE INVESTIGATIONS
Charbonnages de France decided to set up a research contract with the
International Flame Research Foundation, Ijmuiden. A first trial series was
carried out in April 1982 in order to verify that the GARDANNE coals had a
specific behaviour with regards to SO- capture with sorbent injection and to
quantify the extent of sulphur retention nn the ash.
40-3
-------
The experiments were carried out under the following conditions :
- 2.3 MW thermal input in the 6.25 m long, 2 m square IFRF n° 1 furnace,
• around 50 % heat extraction equivalent to flue gas temperature of 1000 °C.
- An IFRF circular burner with variable swirl and provision for staging of the
combustion air with up to 50 % of the air being injected through four
tertiary air ports.
The details of the experimental conditions and the results have been fully
reported elsewhere (1) & (2) but it is worth recalling the main results :
- The parameter having the major influence on efficiency of SO- capture was
found to be flame temperature.* With a washed coal and Ca(0H)_ injection the
reduction of SO- emissions went from 52 % up to 80 % with a Ta/S of 2 when
peak flame temperature was reduced from 1400°C to 1270°C. A similar effect
was found with the high ash coal where natural retention of SO- in ash
increased from 31 % to 40 % at a Ca/S of 2 when peak flame temperfture was
reduced from 1480°C to 1370°C.
- The reduction of excess air, particularly below 25 was found to have a
strong negative effect on SO, capture for all sorbents.
- Staged combustion improved 33- capture only when it resulted in lower flame
temperatures.
- Sorbent injection location did not have any significant effect on efficiency
with these flames.
- CaCO- had very much the same efficiency when injected in the flame as when
already present in the coal ("natural retention") : 40 % SO- removal at a
Ca/S of 2 but Ca(OH)- gave much better results : more than 60 % removal
under the same condi ti
-------
worth looking through some salient results.
Figure 3 indicates very clearly that with the washed coal the injection of
combustion gases in the combustion air reduces dramatically flame temperatures,
particularly peak flame temperature which drops from 1400°C to 1240°C. This drop
is in fact associated with a shift of the ignition front which moves downstream by
more than one meter. The SO- capture that is achieved with Ca(OH)- mixed with the
coal is very significant!/ improved by 20 X flue gas injection ( SO- % in
figure 3 is calculated relative to S02 emissions without sorbent injection). A
further increase of the flue gas mass flow (25 X) did not improve the level of SO-
capture.
Figure 4 presents results for natural retention of SO- when burning the high ash
unwashed coal (Ca/S ¦ 2). Here again it was found tnat injection of combustion
gases reduced the peak flame temperature by more than 200°C by shifting the
ignition front by about 1.5 m and resulted in an increase of SO- retention in the
ash from 41 X up to 59 % (here SO, retention 1s calculated on the basis of
potential SO, emissions with total conversion of fuel sulphur). However when
furnace foullTig became too high the same Input conditions (1.e with 19.5 % F,G.R.)
produced a flame having a temperature profile and SO- emissions similar to the
baseline flame. In this case the higher furnace wall temperature (1020°C instead
of 940°C) had a favourable effect upon ignition and the location of the flame
temperature peak went upwards to the burner and was nearly as high as with the
"pure air" flame.
It was clear that Flue Gas Recirculation could improve significantly SO- capture
provided that it reduced peak flame temperature below 1250"C. This is illustrated
by Figure 5 where the reduction of SO, •wissions (on the basis of potential SO-
emissions with total fuel sulphur conversion for better comparison) has been
plotted as a function of peak flame temperature for washed and unwashed coal thus
including ash and injected sorbent retention.
On the basis of these results it was decided to carry out a trial series on the
50 MWe boiler that would include experiments with Flue Gas Recycling.
EXPERIMENTS ON 50 MWe BOILER
The objectives of these experiments were first to verify on an industrial scale
the encouraging results that had been obtained at pilot-scale and secondly to
define the optimum combination of firing conditions, sorbent type and sorbent
injection location that would give the highest sulphur capture on this unit in
order to be able to design an injection system for the 600 WW unit.
General conditions of the trials
The boilers. Figure 6 shows a cross-section of the 50 MW unit. It 1s a tangential-
ty fired boiler with four coal mills and four burner levels. Oue to the
characteristics of the GARDANNE coal (high ash, high calcium) the boiler had been
oversized : the volume of the radiant section 1s about 50 % higher than it would
be for a boiler fired with a more conventional bituminous coal. For the same
reason the boiler is run with 35 % excess air in order to maintain a low
temperature at the combustion chamber exit and avoid fouling.
The 600 MW unit was designed on the same basis. The cross-section of this unit
presented in Figure 7 indicates that it has seven burner levels widely spaced,
each burner level being fed by a vertical mill.
40-5
-------
Operating conditions of the 50 MW unit during tests. For the tests, the operating
conditions of tne isO ww unit were defined with the objective of simulating as
closely as possible the normal operating conditions of the 600 MW unit particular-
ly from the following, points of view :
- residence time of solid particles in the combustion chamber,
- heat input in the burner zone area,
- flame and flue gas temperature.
These considerations led to the following conditions for the 50 MW unit :
- the load was fixed at 45 MW (electric output) with three levels of burners
in operation. The upper level of burners was not in operation and was
available for sorbent injection,
- burner axis was kept horizontal (zero tilt),
- excess air was kept at 35 S based on 0* and CO- concentrations measured
after economizer,
- combustion air distribution at burners as indicated in Figure 2.
Under these conditions the gas temperature at the exit of the radiant section was
kept around 1100°C.
Measurements. Analyses of coal, particularly sulphur and calcium contents, were
carried out regularly on coal samples which were taken systematically for every
set of operating conditions.
Flue gas composition *0., SO-, CO, CO. and NO concentrations- was measured at
various points of the flue gas path iTi order to adjust inputs and to determine
efficiency of SO, capture. In a few cases S02 concentration was measured at two
points : after the economizer and after the electrostatic precipitator. This
allowed verifying that no significant sulphur capture took place after the
economizer and this sampling point was selected for all gas composition measure-
ments.
At this point, gas temperature is between 400°C and 500°C and the gas sampling
train was made of the following :
- a stainless s'teel sampling probe immediately followed by,
- a dust seperator (aerodynamic separation) followed by a porous membrane
filter,
- a cooler regulated at 0*C for condensation of the moisture.
The dry and clean gas sample was then transported by a flexible PVC tube to a
mobile laboratory for continuous analyses.
SO. concentration was measured with an Infra-Red Absorption analyser (LEYBOID
HERAUS, BINOS type). It was verified that no significant retention of measured
species would take place in the whole sampling train. In particular there was no
retention of SO. 1n the dry filter as long as it was kept dry. However the whole
line was cleanea every half an hour.
40-6
-------
Sorbents. Various sorbents were tested during the trials :
- An hydrated lime containing more than 98 5 Ca(OH)- that was delivered in the
form of a very fine powder (see Figure 8 for particle size distribution)
- A local limestone that was delivered in 0-12 mm grains and was pulverized in
one of the coal mills (the one corresponding to the fourth level of burners)
with a fineness that could be increased from 60 t smaller than 74 m to 90 %
smaller than 74 m (Fig. 8). This limestone had a CaC03 content ranging from
92 2 % to 94 6 %
* A Dolomitic "filler* containing 15.60 % MgCO- and 82.5 X CaCO- and that was
delivered as a fine powder (see particle size on Figure 8).
Results of measurements without F.fi.R
Natural retention. By firing coals having variable ash contents and therefore
variable Ca/5 ratio 1t was possible to determine the natural retention curve that
is presented 1n Figure 9(a). A few points have been put on this curve but in fact
the efficiency of sulphur capture by the coal ash was verified under many more
circumstances and this curve can be used with confidence to predict the SO-
natural retention of the GARDANNE coal from the value of Ca/S. The variation or
the load did not significantly alter the efficiency of natural retention but the
application of Over Fire Air had a slight negative effect upon SO, capture. It was
observed that the natural retention was not significantly altered by boiler
fouling (the furnace was cleaned by soot-blowers every five hours, before every
new experiment).
Finally, it is worth pointing out that 40 % natural retention was achieved with a
Ca/S of 2 which 1s similar to what was achieved in the pilot scale experiments
(See Figure 4).
Sorbent injection. On Figure 9(b) are presented the results of CaCO, injection.
The sorbent was pulverized in the available coal mill injected in the furnace
through the transport air ducts of the fourth burner level. On this figure are
presented the baseline natural retention curve, the natural retention values that
were measured without CaCO- injection for various values of Ca/S (open symbols)
and the increase 1n SO, capture that was achieved by Injecting variable amounts of
sorbent. The interesting thing 1s that CaCO- injection gave the same sulphur
retention as natural retention and this was arso found on pilot scale when CaCO*
was injected with the circular swirl burner. This result 1s quite different than
what has been observed by other workers with German brown coals (4) where 1t was
found that calcium in the coal has an efficiency for sulphur capture which 1s
always better than any sorbent. This specific behaviour of the GAROANNE coal is
probably due to the presence of calcium 1n the form of large inclusions of CaCO-
which are easily separated from the organic part of the coal during grinding ana
subsequently behave like separately injected CaCOj particles.
Some limited tests were carried out with the "dolomitic filler" and this product
gave the same efficiency of SO2 capture than the limestone.
It was also observed that the variation of CaCO, particle size within the range
defined above (Figure 8) did not alter the results of 50- removal. This 1s in
agreement with the pilot-scale trials which did not show any benefit 1n using an
ultra-fine carbohate.
Fioure 10 shows the results that were achieved by using the hydrated lime powder
Ca(0H)«. Figure 10(a) refers to the Injection of the powder in the flame : Ca(OH)-
was pneumatically transported up to the 12 operating burners and was injected on
the burner axis or very close to it through simple pipes. Under these conditions
40-7
-------
the SO- reduction was not really better than with natural retention or CaCO-
inject-ron in the upper raw of burners. The same conclusion applies to Figure 10
-------
This is a major difference between the pilot scale experiments and the boiler
experiments. One explanation can be put forward : in the pilot scale experiments
it was seen that the reduction in peak flame temperature was due to a shift of the
ignition front and was thus associated with a shift of the location of this peak
downstream in the flame (See Figures 3 and 4). In the corner fired boiler this can
work only to a point where one flame interferes with the one coming from the next
corner. Therefore the latest ignition will be at the Intersection of the flames.
For the 50 MW boiler this represents a maximum distance of about 4 m. Considering
that the burners in the boiler have a 12 MW capacity and assuming similarity of
jet aerodynamics in the two systems these 4 m are equivalent to 1.7 m in the
2.2 MW flame. From Figure 4 it can be seen that to get a peak flan# temperature
lower that 1300°C -which is required for real improvement of SO- capture
(Figure 5)- one needs this peak to be shifted by more than 1.7 m. It4 is worth
pointing out that the assumption of a good similarity between the near burner
aerodynamics of the two flames (2.2 MW and 12 MW) leads to predicting that the
peak flame temperature measured with the 2.2 MW baseline flame -1440*C at 1.5 m-
should be equivalent to a peak flame temperature of the same level at 3.5 m and
that 1430#C was measured at 3 m from the burner mouth (location 3, 2 m from wall).
On the whole 1t is believed that the mechanism by which F.6.R. was effective, 1n
shifting and reducing peak flame temperature in the pilot scale experiments with
one burner in a coaxial furnace was not effective to the same extent in the corner
fired 50 MW boiler and that peak flame temperature was not sufficiently reduced to
really improve SOj capture.
Fouling and slagging
During the experiments which lasted over ten weeks there was no significant
alteration of ash deposits on the heat transfer surfaces in the furnace nor 1n the
convection banks. It should however be recalled that the PROVENCE POWER STATION
BOILERS are oversized and superheater banks specially designed to avoid fouling.
CONCLUSION AND PROSPECTS
The experiments on the 50 MW boiler provided a set of reliable data on natural
retention of S02 in the coal ash. They also demonstrated that Flue Gas Recircula-
tion was not beneficial for SO- capture and the optimum Injection location for
Ca(OH)- has been found. These results made It possible to define the conditions of
application of the direct sulphur capture technique to the 600 MW unit which was
already under construction. On this unit the direct desulphurlration will be
applied as follows :
- Addition of limestone to the raw coal, before the mills in order to reach a
Ca/S ratio of around 2.5 at the burners. At full load the mass flow of
limestone will vary between 0 and 40 t/hr, depending upon the quality of the
raw coal.
- Supplementary injection of hydrated Hme (Ca(OH). 1n order to reach 60 %
sulphur capture (relative to potential SO- emissions). Ca(OH)- will be
injected above the upper level of burners fn operation with secondary air
injection around the sorbent jets. At full load the mass flow rate of
Ca(OH)- should be constant and around 15 t/hr to reach a total Ca/S ratio of
3. 2
- The experience gained with the 50 MW boiler has led to reconsider the design
of the electrostatic precipitator : a fifth field has been added to the
system initially designed with four fields.
40-9
-------
Considering the costs of limestone -around 22 F/ton- and of hydrated lime -around
360 F/ton- and their respective efficiencies, the choice that was made was based
on a compromise between to extreme solutions :
- The Injection of limestone only, being much cheaper but resulting in a
significantly higher solid loading in flue gas with associated drawbacks.
- The injection of Ca(OH)- only to minimize the solid loading 1n flue gas but
with unacceptable costs.
With the assumption of 3S00 hours of operation per year at full load, the
operating costs of the sorbent injection have been evaluated at 0.015 F/kWh with
an investment cost of 75 mill ion F.
Under the same conditions the costs of an F.G.D. unit was evaluated at 0.05 F/kWh
with an investment cost of 500 million F.
REFERENCES
1. E. PARODI and G. FLAMENT : "Direct SO- removal from Gardanne coal flames by the
injection of calcium based sorbents with an IFRF experimental staged mixing
burner". Report of the CDF 1 trials, Ijmuiden, December 1983. Ooc. n° 3106/2/83
2. G. FLAWENT and E. PARODI : "Direct reduction of sulphur dioxyde emission with
pulverized coal firing using calcium based sorbents". VOI-Berichte Nr 498, 1983
3. W.S. THORNEYCROFT and G. FLAMENT : "Olrect SO- capture by ash or calcium-based
additives 1n long pulverized coal flames with flue gas recycling for washed and
unwashed french coals". Report on the CDF 3 trials, Ijmuiden, December 1983-.
Ooc. n9 3108/2/83.
4. K. HEIN and W. GLAZER : "Dry additive process for SO- - removal during the
combustion of brown coals".
Proceedings of the sixth members conference, May 1980; International Flame
Research Foundation, Ijmuiden, the Nederlands.
40-1"
-------
Table 1
TYPICAL ANALYSES OF GAROANNE COALS
(as fired basis)
PROXIMATE, WTS
Moi sture
Volatile matter
(including CO.)
Fixed carbon
Ash
CO.
Washed coal Unwashed coal
Typical Base coal Hign asn coal
8.1
40.5
43.9
7.5
12.0
38.2
27.0
22.8
9.1
10.7
38.4
22.9
28.0
13.2
L
ULTIMATE, WTX (including C02
from carbonate)
Moi sture
8.1
12.0
10.7
Ash
7.5
22.8
28.0
Carbon
63.0
45.7
41.4
Hydrogen
4.3
3.1
2.9
Organic sulphur
4.4
3.3
3.1
Pyritic sulphur
1.1
0.8
0.8
Nitrogen
1.6
0.9
1.2
' Oxygen (DIFF)
10.0
11.4
11.9
HIGHER HEATING VALUE
KCal/kg
6 290
4 360
3 790
Btu/lb
11 320
7 850
6 820
MJ/kg
26.335
18.254
15.868
ASH, WTS
S102
23.4
16.0
12.0
A12°3
14.0
7.4
5.5
Fe2°3
13.4
5.0
5.4
CaO
22.3
51.0
59.9
MgO
2.7
1.5
1.3
NagO
0.3
0.2
0.15
K?0
0.7
0.5
0.3
3
22.6
16.0
13.6
Ca/S MOLAR RATIO
0.17
1.6
2.5
TOTAL SULPHUR CONTENT
Kg/106 KCal
8.7
9.4
10.3
lb/106 Btu
4.8
5.2
5.7
g/MJ
2.08
2.245
2.46
40-11
-------
% CaO
m4th
60
SO
UO
30
JO.
40.
o
/ O
X.
1
/
/
/
§i
/
/
f
J
/
/
A-
S
s
J
2
cy*
. 3
10 20 30 40
ash content d coat &dry basis)
• ~ washed coal
o A r«w cod
FIGURE 1 : CALCIUM CONTENT AND Ca/S MOLAR RATIO OF GARCASfcE
r®ng« of prafica/ use
fi»ramnC*am of
toC*l vr Flow
SBCondmry air K %
adjacent sir
.secondary air
M %
*%
FIGURE 2 : PROVENCE POWER STATION N°1 UNIT (50 MW) - AIR DISTRIBUTION
AT THE BURNERS
40-12
-------
r
distance (m)
Flue gas
injection nate
Flue a as injection
mode J
~
0
-—BBS
V
0.1S5
Adiac&ntartd secondary air
c
0.1$ 5
Adjacent And
transport air
~
0.245
FIGURE 3 : WASHED COAL + Ca(0H)2 MIXED WITH COAL ;
EFFECT OF FLUE GAS INJECTION ON FLAME TEMPERATURE
AND ON SOg REMOVAL RATES WITH A 2.2 MW BURNER
40-13
-------
TCc)
i+co
1200
iOOO
30O
600
400
zoo
0.
0
i
2 3
4.
5
6
fhj0q&$
fhiecfionrafct
Wue gas
injechorr moda
ppmdry
•SCjcaptuni
%
NQr
ppmdt>
Qt
# tin Hue
~—a
0
2545
41
1020
3.5
V V
0.135
adjacent and
iSOO
SB
430
2.0
V---V
0.155
s+condary air
2604
41
€60
1.3
FIGURE 4 : UNWASHED COAL ; EFFECT OF FLUE GAS INJECTION
AND FURNACE FOULING ON FLAME TEMPERATURE AND
S02 NATURAL RETENTION WITH A 2.2 MW BURNER
40-14
stfycnass
Id Furnace
Z
unwashed coal
c*/s=z
axial distance
m)
-------
%soz
capture
80.
*0.
60
SO,
30.
40
ff0O 1200 /30<3 .1+00 t
peak Name temperature (*c)
«___ washed coal + C*(0H)z mixed with co*l; Cs/$ = "1.82
unwashed coal natural retention ;2.0
FIGURE 5 : EFFECT OF PEAK FLAME TEMPERATURE ON
S02 CAPTURE WITH 2.2 MW BURNER
hot furna
40-15
-------
CENTRALE DE GAROANNE
G4n4rateur de vapeur de 200-240 t/h
FIGURE 6 : 50 MW BOILER
40-16
-------
HOUIUIUS 06 8ASSIN OU CSNTRI FT OU MIDI
CINTIAU Of MOVING! . TRANCH! 5 • *00 MW
Oowwuw •» »«>wr
I:t7«7l/k
Pi»ii«ii wratNMUt*: HI bmt
Tni»«murt it turctiaulf*: S*3"C
Twmnmi dm mwiMIt: Ml C
"TTSp*.:•,.IfflTT- )' T [ IJIP 11' J~$~~—:
FIGURE 7 : 600 MW BOILER
40-17
-------
100
%Cvmif&v
DelvmTM fi Ur>
(?W, IA
«H>
-------
Z*Oi
rmnswaf
fO
90
SO
+o
so
so
19
I
t.
.openaymbcL: natural jc
ratenfion
.doftedeyrnbahrG&t&o
injection
to
^ 3 7*<=*s
a-Cs(M)z injected in the names
z j
o„C*(OHk injected in transport air before
coal mills
FIGURE 10 : 50 MW BOILER EXPERIMENTS ; Ca(0H>2 INJECTION IN OPERATING BURNERS
%3Qi,
Mm
re
to
so
40
JO
to
MO
¦
r
~
A
V
rf
/
/
%30±
a - without secondary air
€0
30
40
SP
20
10
0
1
>
**/
»
i
/
/
V
0 1 i
I
4C4U«
«. .. writtwvt Meondaiy «ir
with Meondary air
-O— natural retention
FIGURE n : 50 MM 80ILER EXPERIMENTS ; Ca(0H)2 INJECTION IN THE UPPER BURNER LEVEL
40-19
-------
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4+00
4300
4200
4100
10 00
' /"\
h -£ location 3
location i
1 i
diatuicm framwall: m
Typical temperature profiles
o without gas recirculation
A with gas recirculation
FIGURE 12 : TEMPERATURE MEASUREMENTS IN 50 MW BOILER
40-20
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DIRECT DESULFURIZATION AT THE
700-MW WEIHER III UNIT
M. Y. Chugtal
L2C Stelnmuller GmbH
5270 Gummersbach 1
WEST GERMANY
Paper unavailable for publication. Contact the author directly for further
Information.
41-1
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LABORATORY TESTS. FIELD TRIALS, AND APPLICATION
OF FURNACE LIMESTONE INJECTION IN AUSTRIA
G. Staudinger
Technical University Graz
Institut fUr Verfahrenstechnik
Inffeldgasse 25
A-8010 Graz, Austria
H. Schrtffelbauer
Ostarreichische Draukraftwerke AS
Kohldorferstrafle 98
A-9020 Klagenfurt, Austria
ABSTRACT
In Austria six boilers ranging from 20 to 330 MWel having tangential firing or
wail-firing are equipped with furnace injection. In all cases the limestone
powder is introduced with the secondary air. Addition of the additive through
the coal mills was less effective. Ca/S molar ratios of 3 to 4 gave average
sulfur removal rates of 50 .to 60 S, depending on the type and size of the furnace
and on fuel. Fouling is a serious problem with hard coal at full load, but not
at all at reduced load and only under certain circumstances with lignite.
Furnace conditions were simulated in laboratory experiments by putting single
limestone particles with diameters from 3 to 100 pro for 3 to 20 seconds into a
hot flue gas stream. The question on reaction rates as a function of particle
size, S0« concentration, temperature (900 to US0*C) and residence time could be
answered?
Experiments in a pilot bag filter with 1 m* filter area and jet cleaning showed
that the poor utilization of dry limestone in furnace injection of only 10 %
can be Improved to up to 26 » if the ash is separated from the flue gas,
optionally milled, treated with steam and reinjected into the cold flue gas.
Sulfur removal of up to 80 5i and S02 outlet concentrations as low as 100 ppm were
achieved.
42-1
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LABORATORY TESTS, FIELD TRIALS, AND APPLICATION
OF FURNACE LIMESTONE INJECTION IN AUSTRIA
With "FURNACE INJECTION" in general the supply of some additive in addition to
the fuel Into the combustion chamber of a boiler is meant. The function of the
additive is to absorb or react with some gaseous or solid component, which should
not be emitted to the environment mostly in order to prevent the environment
from damage. "Acid" gases like SO-, SO-, HC1, HF (and In principle C02) can
react with basic solids like CaO, MgOT Na«0 and so on. Since the Austrian
mountains are built of limestone rock to a great extent, limestone should be the
basic agent and since Austrian brown coals hardly contain any fluorine or
chlorine only the sorption of S0« and SO, by CaCO, shall be considered. The basic
reactions are:
CaC03 CaO * C02 (1)
CaO ~ S02 ~ 1/2 02 CaS04 (2)
CaS04, unreacted CaCO- and CaO are the only products. Other compounds like CaS
or CaS05 were only produced in laboratory scale work,-but were never found in the
ashes of commercial, coal fired installations, probably because the flue gas
always contains more than 4 % of oxygen.
Magnesia seems not to form stable sulfur compounds at furnace conditions, but it
nay help to improve the utilization of the calcium in a dolomitic additive.
Since the equilibrium of equation (2) is temperature sensitive the temperature
of the furnace as a whole and the method of addition is of major importance for
the process.
The additive may be supplied to the furnace by different methods:
- addition to the coal before it enters the mill
- injection into the mill
- injection into the furnace at a selected position
- injection into the furnace with the overfire or underfire air
(secondary or tertiary air with wall burners).
Based on the results from large scale trials by Osterreichische Oraukraftwerke AG
(UQK) in Austria furnace limestone injection has become a common practice. All
suitable boilers are equipped with injection facilities and achieve more than
50 % sulfur removal. The large scale applications are backed up by laboratory
experiments. Pilot scale trials showed, that a considerable improvement of the
poor additive utilization is possible if the ash is treated and collected on a
fabric filter.
42-2
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LARGE SCALE FURNACE LIMESTONE INJECTION (LIMB)
Experiments
Most of the experiments were done on three different plants of ODK, i.e.
Voitsberg No.2, St.Andrii No.2 and Voitsberg No.3, which are listed with other
plants having LIMB in Table 1. All three plants have beater mills with hot gas
recycle from the combustion chamber and corner firing. The fuel is a local brown
coal with high ash and water content. The sulfur content changes in a wide range
from 0,4 to 1,5 %, The SO--concentration in the flue gas may change over a factor
two within twenty minutes; for very short times peaks up to 7000 mg/m3 may occur.
Additives. The additives came from different quarries within Austria, having
different chemical compositions. As can be seen from Table 2, some of them were
very pure calcites, some were dolomitic. Also the particle size and particle size
distribution was very different for the test-powders, as can be seen from
Figure 1.
Furnace Temperature. It was known from literature (1, 2, 3, 4, 5) that the
furnace temperature greatly influences the efficiency of the process. Therefore
before any changes were made on the system or the mode of operation the
temperature distribution throughout the combustion chamber was measured with a
bare thermocouple (6). By doing so not the true flue gas temperature was
determined, but the temperature, which a lime particle at this particular position
in the furnace might obtain. The thermocouple was positioned at the hottest point
in the furnace and the temperature recorded throughout all testruns, although the
location of the hottest point may move when the operating conditions are changed
e.g. through flue gas recycle or Increase of the air factor.
Already the first testruns showed, that in many applications a reduction of the
furnace temperature below normal operating conditions will be required, in order
to achieve a satisfactory limestone utilization. Methods to reduce the furnace
temperature are: cold flue gas recirculation, increase of air factor and
reduction of boiler load. The injection of water 1n addition to the moisture of
the coal was not Investigated.
The hottest furnace temperatures were
Voitsberg No.2 1150aC
St.AndrS No.2 1227'C
Voitsberg No.3 not measured.
The relation between furnace temperature and additive utilization 1s treated 1n
an earlier publication (7). In short: If 17 to 18 % of the flue gas flow is
recycled, limestone utilization and desulfurization efficiency may Increase by
a factor 1.3.
If the furnace temperature becomes as low as 950 °C (which is only of academic
interest in pulverized fuel combustion) the limestone utilization drops again
because of incomplete decomposition of the limestone.
It seems, that the optimum furnace temperature for the best additive utilization
in a commercial Size boiltr is close to 1070®C. Whether this is obtained through
a very moist fuel, operational measures or an appropriate design of the
combustion chamber should not matter.
42-3
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Mode of Limestone Addition. Limestone powder was supplied by truck and stored
in silos, from where it was dosed by star valves onto a conveyor belt and dropped
on the coal or into a pneumatic feed line.
If the limestone powder is dropped onto the conveyor belt the dust developing at
the dropping points at the end of the belt causes quite some annoyance.
All later experiments and all permanent installations apply pneumatic conveying
which does not cause any problems - if It is properly designed. In one experiment
the limestone powder was injected Into the coal mill, but desulfurization was less
than with other methods. Today all installations Inject the additive 1n the
overfire air duct, since this causes no operational problems and gives the highest
desulfurization and best limestone utilization.
Electrostatic Precipitator. All plants are equipped with electrostatic
precipitators of appropriate size, such that dust concentrations of 150 mg/m*
and lower are usual operating conditions. Only the ESP of St.AndrS No.2 will not
fulfill future emission standards and will be replaced by a baghouse.
During the experiments with limestone addition the dust concentration in the clean
gas was measured and compared with measurements done shortly before and after the
trials. A significant difference in the emission could only be found with the ESP
of St.AndrS No.2 and with unpractically high additive/fuel ratios, e.g. 170 kg of
additive per 1000 kg of fuel (which equals a Ca/S ratio of about 7).
Results. A set of results, obtained 1n Yoitsberg No.2 with the limestone powders
listed in Table 2, of which the particle size distributions are given in Figure 1
are given in Table 3. In this set of experiments the additive was blown into the
hot gas suction duct leading from the upper part of the combustion chamber to the
coal mill. Today we know that this method of addition gives least desulfurization
and additive utilization. However this set of experiments compares many powders
and operation with and without flue gas recycle.
The desulfurization 0(A) was calculated from the formula
«/*> _ Sulfur 1n ash
D(A) ' Sulfar in coal
which showed the most reliable results. In Figure 2 the results of Table 3 are
plotted against the powder/sulfur ratio. This powder/sulfur ratio gives a better
indication of the effectiveness of a particular powder than the Ca/S ratio (which
is often used), especially if calcltic powders are to be compared with powders
which contain magnesia or inert substances.
Further 1n Table 3 the sulfurdioxide concentration in the flue gas duct and the
molar ratio of (Ca ~ Mg)/S entering the system is shown. All values are
determined from the ash analysis. This means that the calcium and magnesium which
are contained in the coal ash are also included. This is justified, since we
found that the utilization of the earth alkaline metals contained in the ash is
about equal to the utilization of the additive. Although magnesia 1s supposed
to form no compounds with sulfur oxides under the prevailing conditions the sum
of the moles of earth alkaline metals was calculated, since magnesia seems to
promote desulfurization. ALKU is the molar ratio of (Ca + Mg)/S found in the ash.
42-4
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In all experiments the ashes from the furnace bottom and the filter ash were
sampled, analysed and the results summed up in accordance with the relative mass
fractions of the ash flows.
In Table 3 and Figure 2 run numbers 2, 3 and 5 had no flue gas recycle, all
others had. Since flue gas recycle (at least at Voitsberg No.2) increases the
desulfurlzation by a factor 1.3, the desulfurlzation of these runs as it would
have been if they had flue gas recycle can be estimated and plotted into Figure 2.
With these three points corrected to equal operating conditions a relative ranking
of the different powders becomes possible, although the sulfur dioxide
concentration, mainly due to the changing coal properties, but also due to reduced
additive dosing, was not constant. The ranking of the powders Is: 0, F, E, B, C,
A, G, H and I. The small difference between powders B, £, F and D may be due to
experimental inaccuracy.
Furnace limestone injection may cause three different kinds of losses:
- heat of decomposition of the limestone
- increased loss of carbon 1n the ash
- increased stack loss through higher stack temperature.
The heat required for decomposition of the limestone as well as the heat gained
from the formation of calciu...sulfate can easily be calculated. Together with the
heat required for heating up the additive to the flue gas temperature the heat
requirement of the additive may amount up to 1,5 2 of the heating value of the
fuel.
Increased loss of carbon in the ash may occur when the additive is added to the
coal. No increased loss of carbon could be found if the additive was injected
with the overfire air.
If the temperature of the combustion chamber was reduced by recycling cold flue
gas or increasing the air factor the stack loss increased because of a higher
gas temperature - and in the case of the greater air factor - an increased gas
mass flow to the stack.
Injection of the additive with the overfire air gives much better desulfurlzation
and additive utilization than any other method of addition. This can be shown by
comparing runs which both used additive S but one time added to the coal on the
conveyor belt, and the other time Injected with the overfire air.
This experiment was done in St.AndrS No.2. The runs with comparable operating
conditions are listed in Table 4. The St.Andr* No.2 plant 1s - because of Its
high furnace temperature - not well suited for LIMB which can be seen from the
poor utilization of the earth alkaline metals (ALKU) of run numbers 2 to 7. If
the limestone powder is injected with the overfire air AIKU Increases by a factor
1.7. About the same Improvement was found in Voitsberg No.2 after retrofitting
the plant with permanent injection equipment.
Application of Furnace limestone Injection
Operating Plants with LIMB. At present four Installations with 6 boilers operate
with limb uaDie i;. The normal dosing rate is 80 kg of additive per 1000 kg of
brown coal.
42-5
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All boilers inject the additive with the overfire air-respectively the secondary
air if wall firing is applied since this method gave the best additive utilization
and no operational problems.
Experience with Operating LIMB. Desulfurization in all cases is better than
50 «. with the smaller plants it may be better than 60 In Figure 3 the
desulfurization obtained in Voltsberg No.3 during the first full operating period
is plotted. The full line shows the desulfurization averaged over a period of one
week. The dotted line shows the average per month with the days on which
operational problems did not allow normal operation disregarded (which is in
compliance with Austrian legal regulations). During this period the Ca/S ratio
was 2.5 if a dolomitic powder was used and 4 with calcite.
Deposition of slag or ash is never a problem. Only Voitsberg No.3 has soot
blowers, which are operated once a day. In the other plants probably some more
build ups of deposits in the convection section were observed which were removed
during the annual outage. The build-ups had no strength and were removed easier
than the normal deposits of earlier years. The heat transfer in the convection
section was not changed by the deposits.
The ash contains up to 20 % of Calcium in the form of CaO which reacts with the
water after wetting of the ash. This may lead to the development of water vapor
if the ash is hot before wetting. Cold ash - e.g. after pneumatic conveying over
a few hundered meters distance - reacts slowly with the water and thus develops
no steam. The water flow into the ash wetting equipment (mixer) must be accurately
controlled, otherwise the mixer may plug up with solidified ash.
Future of LIMB in Austria
Two different developments can be foreseen for the near future, depending on
whether the particular plant is expected to have a long or a short renaining life
time.
Old Plants. All old plants - like Voitsberg No.2 - are of smaller size and will
comply with the legal requirements, at least with what they are now, 1f they bum
the local brown coal and apply LIMB.
New Plants. Several new power plants are being built at the moment but only
Voitsberg No.3 1s fired with brown coal and equipped with LIMB. The other plants
will be equipped with conventional FGO. Voitsberg No.3 too gets a wet FGD which
treats 100 S of the flue gasflow, but it will be difficult to comply with the
emission standard of 400 mg/m3 if a high sulfur peak of 7000 mg/ma occurs. To
achieve the required high degree of desulfurization a combination of LIMB and wet
FGO will be applied in Voitsberg No.3 according to Figure 4. Under normal
operating conditions the LIMB equipment will be stand-by and no limestone will be
injected. If however a $0- concentration higher than about 4000 mg/m1 is measured
in the raw gas the LIMB wTll be activated within a few seconds in order to remove
some of the sulfur dioxide from the raw gas. By this "peak shaving" a more stable
operation of the wet FGO is achieved as is illustrated by Figure 5 (8).
42-6
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LABORATORY EXPERIMENTS ON LIMB
The SO«-pickup of limestone and dolomites was investigated by several
researchers (9, 10, 11, 12, 13). The investigations however did not cover the
ranges of residence times, temperatures or grain sizes which are practical in
LIMB. Consequently it was our task to investigate the SO«rpickup of powders
with particle diameters of 60 m or smaller, at temperatures as high as 1100°C
and exposure times of three to twenty seconds in a flue gas atmosphere with
1QQ0 to 2000 ppm of SO?.
Experimental Setup
Synthetic flue gas could be produced from an experimental furnace which burned
natural gas with a varying air excess and with different amounts of SO? added
to the air before combustion. The flue gas temperature could be adjusted by the
burner throughput. Since the heat loss remains almost constant, a smaller
throughput gives a lower flue gas temperature.
The ZOO mg powder sample was distributed evenly on a 500 mm diameter fiIt of heat
resistant material (AUQ3 fibers) and covered with an other layer of felt. A
thermocouple from 0,1 ram thick wires was also imbedded between the two felt
layers. This raw sample was inserted into a "pipe", as shown in Figure 6. Sas was
sucked through the pipe by a vacuum pump, and the gas flow measured. The pipe
could easily be moved into and out of the flue gas stream which left the furnace
(Figure 7). The actual temperature and residence time could be read from the
recording of the thermocouple.
Each sample was analysed for Ca, Mg and S.
First Results
First results are shown graphically in Figures 6 to 11. Figure 8 shows the
conversion of a calcite and a dolomite powder of a narrow size range between
25 and 28 urn as a function of time at different temperatures as the parameter.
In this set of runs the SO? concentration could not be adjusted accurately due to
technical reasons. Thus the SO2 concentration is not the same 1n all runs!
However, with the temperature of 950 to 960*C the best conversion could be
obtained, although the SO2 concentration was lowest. For the very short residence
times of two and three seconds the higher temperatures gave a better conversion.
This fact will be analysed more quantitatively 1n the future. The calcite seems
to need more time for burning than the dolomite. But, 1f the residence time is
long enough the calcite A picks up more SO2 than the dolomite S. In all cases
the conversion is defined by the formula:
moles of S in sample
Conversion ALKU • SdT«s of ICi ~HjJ In i'wpTS (3'
The effect of temperature on the conversion of different powders is shown in
figure 9. Again the experimental conditions are not perfectly the same.
Nevertheless clear trends can already be deduced: The dolomite powder S gives
* very high conversion of (Ca * Mg) at 950°C and drops off markedly at higher
ttmperature. The calcite powder A seems to be less sensitive to temperature.
42-7
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Surprisingly low conversions were obtained with powders J and K, although
these had by far the smallest particle diameter. The only possible interpretation
is, that powder J comes from a chemical precipitation and therefore may consist
of very perfect cristals which do not produce a great reactive surface. Powder K
is a milled, very white marbel. It takes at identical conditions some what more
sulfurdioxide than powder J but is significantly less active than the more
"ordinary"- powders, despite the smaller particle size.
The effect of particle size, shown in Figure 10, is not dramatic, as long as the
particle diameter is somewhere between 25 und 120 urn. Two runs with a very
fine fraction of dolomite G showed a surprisingly high conversion of 50 X, which
means, that 85i of the calcium had been converted.
The effect of SOg concentration on conversion is shown in Figure 11. Since the
shape of this curve is very similar to the ones of Figure 8 - for comparison:
doubling the residence time from 10 to 20 seconds effects the conversion in the
same amount as doubling the SO? concentration from 1500 to 3000 ppm - some coomon
controlling mechanisms can be assumed, probably the build up of a restriction for
diffusion of SOg to the CaO or simply the consumption of open pore volume.
Future Work
Future work will concentrate on
1 gather more information at residence times shorter than 5 seconds,
temperatures around 1100*C and SOg concentrations at and below
1000 ppm. Also particles with 10 pm . diameter of both, calcite and
dolomite powders will be investigated.
2 Construction of a continous vertical flow reactor for residence times
smaller than 5 seconds in order to produce larger samples of sulfated
limestone for the determination of BET-surface,pore diameter and pore
volume.
3 Try to identify the change of crystal structure during the first seconds
of heating the particle with the aid of an electron microscope and
x-ray diffraction.
SECONQARY UTILIZATION OF LIMB-ASH
Since the conversion of an additive injected into a pulverized fuel fired
furnace 1n practice hardly exceeds 12 X, an other means must be found to
utilize the CaO, which is contained in the ash with a three to eightfold
excess relative to the remaining SOj in the flue gas. This high alkaline ash
can be slaked and used as an absorbent in a spray dryer or 1n a wet FGD. Both
applications may be economically advantageous under certain circumstances.
A more attractive method would be to increase the residence time of the additive
particle in the flue gas and let it react with the SOg. This can easily be
achieved with a fabric filter. However the rate of reaction at usual operating
temperatures is very small and as a result of this unpractically long residence
times would be required. Only activation of the ash by some means can make the
fabric filter work as a piece of desulfurization equipment.
42-8
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From literature (14) it is known, that the sulfation of calciumoxide is a very
slow reaction if the temperature is lower than 400°C. Reasonable reaction
velocities are to be expected if calciumhydroxide is used as absorbent even at
temperatures between 100 and 2Q0*C. A number of dry processes are based on this
reaction.
The missing step is the conversion of the CaO contained in the fly ash Into an
active form of CatOH^.
Activation of LIMB-Fly Ash
According to Schlegel (15) the CaO should react Quickly with the up to 15 t H-0
of the flue gas. A number of trials with filters showed that this does not occur.
Cutler (16) reported, that treatment of CaO with CO2 at a temperature between
340 and 882°C did slow down a following hydration considerably. The fly ash was
in contact with the CO? of the flue gas during cooling down. With the surface
covered with CaC03 a following hydration will be slow.
But even 1f hydration of the CaO at an active site would occur, the SOj and COg
would react with the just forming Ca(0H)2 immediately and build up an
impermeable layer of CaS03 or CaCO? on all active surfaces. This coincidence
of the hydration reaction with the suTfation/carbonation reactions could be the
cause for the low sulfur capture of LIMB-fly ash in fabric filters.
Thus: The hydration of the CaO must occur in the absence of SOg and CO?. This
means: The ash must be separated from the flue gas, treated with steam and
remixed with the flue gas for SOj absorption. An additional disintegration step
before the steam treatment may spe«d up the hydration reaction and improve the
absorption capacity of the ash.
The LIMB-FILTER Process
Figure 12 shows a process, which realizes the required steps
• separation of the ash from the flue gas
- mechanical disintegration
- steam treatment '
- recycling of the treated ash into the flue gas stream and
deposition, preferably on a fabric filter.
A process of this kind can be very attractive to those boiler operators, who have
to retrofit their plant with new dust removal equipment because of new, more
stringent regulations.
Experiments
To show that the LIMB-filter works, a pilot jet filter having one bag with 1 m*
filter area was operated at the cogeneration plant at Graz (FHKW of Table 1)
during LIMB trials with ash produced 1n these trials. A diagram of the plant, is
given in Figure 13.
For the tests clean flue gas was taken downstream of the ID-fan of boiler No.3,
flow, temperature and SO? concentration were measured. This flue gas flow
contained less than 150 mg/m* of dust. The flue gas passed through the single
42-9
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filter bag, temperature and SO2 concentration were measured at the exit. The
bottom of the filter casing could hold up to 14 kg of ash, which was fluidized
with steam. The central nozzle formed a spout, which mixed partially with the
incoming flue gas. By doing so a redistribution of the ash in the flue gas stream
was achieved. The ash could be lock hoppered in and out during the experiment.
Actual operation however was batchwise and the lock hoppers were only used for
sampling. The exposure time for one batch of ash was between 6 and 41 hours.
The SO2 concentration of the raw gas changed during one run between 330 and
830 ppm. The SOg concentration in the exit gas was sometimes brought down to
100 ppm.
Results
Desulfurization. The experiments were done in the months April and May when the
boiler load of the cogeneration plant had to be turned down to only 50 S of its
normal rating. As a result, the flue gas conditions too changed in a wide range.
Since it was not possible to measure the SO2 concentration before and after the
filter at the same time, it is no surprise, that the calculated degree of
desulfurization scatters in a wide range. Figure 14 shows measured degrees of
desulfurization as it is obtained with one batch of ash in the filter alone. Thus
the desulfurization in the furnace has to be added according to the formula
°UMB * Filter " °tIMB * (1 " °LIMBJ * Din Filter
Sulfur* - Sulfur.,,*
with 0 * Degree of Desulfurization
Sulfur^
The most reliable basis to calculate the pickup of sulfur is the ash analysis like
in LIMB-experiments. The analyses for five-runs are given in Table 5. The first
five rows show the composition of the ashes after utilization in the pilot filter.
The most important figure is the calcium utilization which is 0,26 in run No.7
and higher than 0,2 in three more runs. The sixth column shows a typical
composition of the LIMB-ash before it was charged to the pilot plant.
When using air instead of steam in the primary nozzle (to generate the spout) the
calcium utilization 1s considerably less, although the other operating conditions
are identical with those of run Nos. 7 and 8.
The ash of run No.9 was milled in a ball mill prior charging to the pilot filter.
The calcium utilization is not better than in other comparable runs.
Future Work
More experiments on both bench and pilot scale are required in order to get more
insight into the governing mechanisms.
42-10
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CONCLUSIONS
- Furnace limestone injection is a technically available process. It may be
applied to boilers which bum fuels having a relatively high water content.
- In a commercial furnace different limestones are equal active on a weight
basis irrespective whether they are calcites or dolomites. In laboratory
tests exotic materials like precipitated CaC03 or very pure marbel showed
a considerably lower utilization than ordinary limestones.
- Injection of the limestone together with the overfire air gives the best
utilization of the limestone. •
- Increase of the air excess above the normal level allows application of
LIMB also to furnaces burning higher heating value fuels.
- The cooler the furnace is, the better the results obtained with LIMB are.
- Laboratory experiments show a "normal" dependence of the conversion from the
SOg concentration and from the residence time (after substraction of the
time of calcination).
- For a residence time of 10 seconds there is an optimum temperature at 950*C.
Shorter residence times may have a higher optimum temperature.
- Secondary utilization of LIMB fly ash may more than double the utilization
of the additive.
ACKNOWLEDGMENTS
This work is supported by the Fonds zur FBrderung der wissenschaftlichen
Forschung, Project No. P 5261 and die Austrian Minlstery for Science and
Research, MR. Zellhofer being the Project Officer.
42-11
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Ven-ingerung des SOg-Auswurfes". Mittenungen der VG8. Heft 83, April 1963.
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entschwefelung mit Verbindungen der Erdalkalimetalle". VOI Fortschr. Berichte,
Reihe 3, Nr.22, Okt. 1967.
3. Full Scale Oesulfurization of Stack Gas by Dry Limestone Injection.
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1G. R. W. Coutant, J. S. McNulty, R. E. Barret et. al. "Investigation of the
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Summary Report. Battelle Memorial Institute Columbus Laboratories 505,
Xing Avenue, Columbus.Ohio 43201, U.S.A.
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the Grain Model". AIChe Journal. Vol.22, No.3, 1976, pp. 490-498.
12. R. H. Borgwardt and R. 0. Harvey. "Properties of Carbonate Rocks Related to
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pp. 350-360.
13. R. H. Borgwardt. "Kinetics of the Reaction of SO2 with Calcined Limestone".
Environmental Science and Technology, Vol. 4, No.1, 1970, pp. 59-63.
14. W. I. Davis and T. C. Keener. "Chemical Kinetic Studies on Dry Sorbents",
Literature review, DOE/FC/10184-2 (DE 820 12763).
15. E. Schlegel. Silikattechnik, 27, 1976, pp. 377-378.
16. I. B. Cutler, R. L. Felix and L. P. Caywood, Ceramic Bulletin. 49. 1970.
pp. 531-533.
42-12
-------
Table 1
INSTALLATIONS UITII FURNACE LIMESTONE INJECTION
Plant LIMB Power Heating Water Ash Burner Soot
PLANT NAME OWNER erection Install, rating value content content Sulfur type blowing
lower KJ/kg I t %
St.AndrS
No. 2
year
year
HW
Voltsberg DDK
No. 2
m
Voltsberg DDK
No. 3
1956
1959
1983
Cogeneratlon STIWEA6 1964
plant, Graz xx)
Riedersbach OKA 1969
No. 1 xxx)
1982*'
1983*'
1983
1984
Jan
65
110
330
3 x 18 12800*
1985
xxxx)
55
10500
9500-1300 35
10500
32: 15*
38 30*
15*
25*
10400-
12000
32s 15;
38' 30
36
30
12
0,4 - 1,5 4 comer not
available
0,5 >1,2 4 corner not
available
0,4 - 1,5 6 corner once a
day
0,4 - 1,2 4 wall not
available
23.5 0,45 - 1,9 4 corner not
available
x) Year of permanent Installation
xx) Stelrtsche Wasserkraft und ElektrlzltSts AG
xxx) OberiisterreicMsche Kraftwerke AG
xxxx) peraianent If trials are positive
-------
Table 2
CHEMICAL COMPOSITION AND SURFACE AREA OF ADDITIVES
Additive
Nr.
A
0
C
D
E
F
6
H
I
J
K
water
o.lO
0.02
0.11
0.08
0.02
0.05
0.02
0.38
0.07
0.8
0.0
insoluble
(Si02)
t .66
1.46
1.01
0.94
1.39
1.39
6.02
17.92
2.85
CaO
53.36
52.85
38.25
54.15
53.37
48.89
32.37
41.16
52.36
53.7
54.4
MgO
0.72
1.93
14.98
1.09
0.93
4.92
16.61
3.43
1.45
0.3
0.2
Fe2°3
0.17
0.17
0.11
0.12
0.05
0.14
0.26
1.07
0.34
Al2°3
0.52
traces
0.14
0.32
0.31
traces
0.33
1.04
0.52
C02
43.14
43.45
45.61
43.42
43.52
43.86
44.37
34.47
41.24
42.0
44.5
SO3
0.08
0.06
0.07
0.02
0.05
0.05
0.01
0.17
0.30
Blaine
c«* /g
2432
5097
4307
3825
3723
6120
4307
4732
1580
tested In Voltsberg Nr. 2 Laboratory
tests only
-------
Table 3
RESULTS OF VOITSBERG NR. 2 TESTS
Run.
Nr.
Additive
kg/t of
brown coal
Additive
Nr.
Hue gas
recycle
SO. in flue
gaS ppm
Ca+Mg
DIA)
ALKU
1
.
no
1224
1.75
0.095
0.055
2
70
B
no
1135 '
3.66
0.307
0.084
3
100
B
no
718.8
6.0
0.427
0.071
5
91
A
no
790.5
4.81
0.348
0.072
7/1
100
E
yes
666.6
5.75
0.552
0.096
9
65
F
yes
983.2
3.21
0.353
0.11
10
92
F
yes
663.8
5.0
0.519
0.104
11
-
m
no
1131
2.0
0.193
0.095
12
88
D
yes
689
5.37
0.498
0.093
14
96
C
yes
634
5.8
0.488
0.084
16
90
6
y«s
712
5.6
0.432
0.077
18
94
H
yes
709
4.94
0.392
0.079
20
93
I
yes
837
4.39
0.313
0.071
42-15
-------
Table 4
UTILIZATION OF AOOITIVE 6 AT ST.ANORK NO. 2 WITH
DIFFERENT METHODS OF ADDITION
Plant load 90 MW (plant rated power * 110 MW), S0--
concentration 530-800 ppm
Additive G
dropped on conveyor belt Injected with overflre air
Run No. ALKU 5 Run No. ALKU S
2 3T3 ~T7 5772—
3 5.7 18 9.25
4 5.3 23 8.32
5 5.5 27 9.38
7 5.28 31 9.84
Table 5
ASH ANALYSES FROM LIMB-FILTER, COGENERATION-PLANT GRA2 1983
SiO,
C50
MgO
SO,
3
h20
Ash kg
Run-Time
hours
Treatment
Run number of LIMB-FILTER
5
7
8
9
10
LIMB
ash'
27.92
35.94
28.70
30.32
30.35
20.86
26.32
21.99
22.32
23.01
24.26
21.19
27.47
27.70
27.33
26.94
3.09
1.56
2.31
2.76
2.20
1.17
9.73
7.93
8.73
8.11
6.85
3.65
11.65
6.18
9.15
8.07
8.84
2.78
1
1.77
0.29
0.39
0.32
0.34
-
99.28
99.41
98.74
99.60
98.92
•MM
M«M
¦MM
MMM
M*M
mmmmm
(M
•
o
c
o
•r
0.26
0.222
0.205
0.175
0.095
11
12
12
12
12
I 41
24
26
25
13
2kg ash
milled
milled
Fluidiz.
prim.
(spout)
steam steam
steam
steam
air
42-16
-------
° 100
10-
X
m
80
SO
:o
10
¦ ' portid»«siz* *, >an
Figur* 1 PtrticL«-ili«-di»tributien» o£ ttha usad additives
oui
0.3 •
s « «
•UUS&SSI
«•*
Figura 2 D«»ulfuris*t.ion (A) as a function of povd*r/sulfur
ratio
42-17
-------
November 1383 to April 1984
100
a 70
Novtmbcr Dtetmbir Jonuory February Mareh
April
Figure 3 D«sulfurization through LIMB in Voitsb«rg No.3
BOILER ESP
LIMESTONE
WET
1 I
CoO«CoSOt
LIMESTONE GYPSUM
Figur* 4 D«»ulfuriz«tion in Voit«b«rg No.3
42-18
-------
£2000
WITHOUT UMB
WITH UMS
? 1000
lim*. haun
Figura S SO. Concentration la raw gas with and without LIMB
in Voitabarg No.3
FlBERFRAX PUT
LIMESTONE
SAMPLE
thermocouple
SUPPORT RING
TO VACUUM PUMP
rigur* 6 Pip* for holding liaastona •ample
42-19
-------
TO GAS ANALYSIS
'TfRE BOX-
BUWNSR
NATURAL GAS
Figure 7 Laboratory setup for sulfation of limestone
SYMSOL
AC3ITIVS
PARTICLE
OlAMfTC*
!m<"I
t*Cl ! law* T/.voll
e
A
zs - zs
980
12S0 ' 3.5 | 9.3
X
s
25-21
I4C-M0
1590 1 4.3
9
0
A
0
0__
"o
0
25 ' 21
980 *9SS
1286 J i
9
«-2»
a . 28
9K • 1000
1870 | S.2
9
10SC-H30
1870
S.2
9
30 Me
10 19 20
— t, HCSIttt
Figure 8 Conversion of limestone as a function of time
42-20
-------
-if
• 40-
I
m 30
S
20
10
StmSOL
AOOlTIVt
PARTICLE
oumktck
Ifiwl
ACSIOINCE
TIMC
|*#eond«!
o*5 c
DNCENTRATtON
50,
lPO">l
(V.,ol|
CO,
X
6
25 • 21
to
nil
4
9
•
A
28 - 28
5 - 1
1933
4.2
1.8
0
i
0.4
•
2075
4.8
9.8
B
K
0.3
6
2071
4.1
8.8
MO
800
no
Figure 9 Conversion of limestone as a function of tespera<
ture
SYMML
AOOTtve
hcsioCnce
TlMt
l*»e«n«)
TCMPOM-rue
(•CI
OAS CONCENTRATION
SO, 1 0,
|p#m|
CO,
l%««l
s
ft
10
950 • 960 11288 i 4
8
•
A
5 - «
880 MHO 1 3.8
8.3
#
Figure 10
20V«osow70HMioonono
¦ PAHTICtf • DIAMCTER tp.pm
Conversion of liaestone as a function of particle
sis*
42-21
-------
AOoiTivt a
4p • IS • 2«>*it
S»
b
*
*
0.3*
10-
woo
2000
3000
concsntratiqm or so,. pw*
Figure 11 Conversion of liseston* as * function of SO. con-
centration 2
8AO
HOUSE
ASM ro 0131*03At.
Figure 12 LIMB-Filter Process
42-22
-------
rmsH tm (T\
JY
\ $©:
V
i
i
f • ,
6 L~J
ruue OAS OUCT ;_
BOILER M*. 3 S
\ •¦
2,5 CMi
Figure 13 X.XMB-FXLTER *xp«ria«ntal plant
100-
90
7
M<
s
JO
*
th
6
<0-
e
10
to.
30'
20-
10 •
* v
tton*, hour*
36
Figur# 14 DSSUirURXZATZON (%) in £ilt«r, run No.5
42-23
-------
EXPERIENCE WITH FURNACE INJECTION OF PRESSURE HYDRATED LIME
AT THE 50-MW HOOT LAKE STATION
H. Ness and T. P. Dorchak
U.S. Department of Energy
Grand Forks Projects Office
Morgantovn Energy Technology Cancer
Jams R. Reese
Energy and Environmental Research Corporation
Verlln Menze
Oteer Tail Power Company
ABSTRACT
A series of tests was recently completed at a 50-MW power plane to evaluate direct
furnace injection of pressure hydrated line to reduce sulfur dioxide emissions.
Both high calciua and dolomitic limes were evaluated over a range of injection
rates. The sorbents vera injected at selected points above the burners in the
radiant sections of the boiler. Temperatures in these sections ranged from about
2,000* to over 2,500*F. The low-sulfur lignite fired was from the Beulah mine in
North Dakota. The boiler. Hoot Lake Station. Unit 2, was a cangentially fired,
balanced draft unit equipped with an electrostatic precipitator for particulate
emission control. The burners were operated within normal ranges except in one
test with a low NO configuration. Some 30 short-tern tests were conducted,
typically 2 to 4 hours in duration. The tests also included injecting hydrated
line for a continuous 30-hour period to evaluate longer tera effects on boiler
performance.
This report presents" preliminary results of sulfur reduction and calcium
utilization. Sulfur reduction values ara based on sulfur dioxide measurements in
the gas stream. The simple pneumatic system, used to inject the dry sorbents Is
also described. The results are compared to those from an earlier test series at
the station evaluating limestone as the sorbent. Impacts on the performance of
the boiler and precipitator are briefly described.
INTRODUCTION
The reduction of stack gas sulfur dioxide emissions by direet injection of calcium
compounds Into the furnace chamber has been under investigation for over 30 years.
In general, the results of these tests indicate that although high sulfur dioxide
removals could be achieved, th« corresponding sorbent requirement mis very high
(1,2). There were also potential problems with slagging, fouling, and
collectibility of the resulting fly ash sorbent particulate matter. The high
additive rates requirements were due to:
e Inadequate residence time of the sorbent particles in the
temperature region where sorbent-sulfur dioxide reactions ara
favored;
e Deadbuming (sintering) of the sorbent surf act, reducing otherwise
available reactive surface area;
• Infraction (lntlmata mixing of molten ash and sorbent) to deactivate
the sorbent; and
e Inferior sorbent characteristics, including large particle size* low
porosity, and low specific surface araa.
43-1
-------
Recently, burner modifications that reduce flan* temperatures Co raduca nlcrogan
oxida emissions hava baan developed that partially ovarcoraa son* of the abova
problems. As a result, graacar opportunity for increased aorbanc utilization has
presented itself, i.a., lass daad burning whan the sorbent la injactad directly
inco tha burnar zone(s). Residence times hava also Incraasad dua eo mora conser-
vative,. largar, aodarn bollar designs. Tharafora, undar cartaln slea spacific
constraints, a succassful dry sorbent process may present an economically
attractiva altamaciva eo mora conventional proeassss. Potantial advantagas
includa:
a Simplicity, size, and cost of equipment,
a Easa of backfittlng existing plants,
a Production of dry solid waste (a dry-to-dry procass).
a Raducad water requirements.
a Limitad impact on boilar operation/equipment.
a Incraaaad thermal afficiancy.
Potantial disadvantages includa:
a Incraasad particulate Missions,
a Incraasad boilar slagging,
a Incraasad boilar fouling,
a Lower sorbant utilization.
A dry sorbant procass being investigated by the Department of Energy (DOE) is the
direct injection of pressure hydrated lime. The hydraee is Injected into the
upper radiant sections of the furnace where it dehydrates and resets with sulfur
oxides in the gas. Temperatures are well belov those in the combustion flame or
its vicinity, but yet sufficiently high to favor the reaction of sorbent with
sulfur dioxide. Deadburniag (sintering) and ash deactivating effects can be
minimized at optimized injection sites while still providing adequate residence
times. The work here is part of a simultaneous SO /NO emission control project
being investigated by the University of North Dakota Energy Research Center
(UNDERC) sponsored by the DOE. The sorbents of choice for SO control were
pressure hydrated dolomitic and high-calcium limes. x
Pressure hydrators are commonly used by Industry to fully hydrate dolomitic
quicklime. Dolomitic lime contains a high proportion of magnesium oxide,
resistant to hydration at atmospheric conditions. The pressure vessels are
generally operated at pressures ranging from 100 to 120 psig and temperatures
ranging from 200" up to 300*7. Temperatures and pressures are produced
autogeneously in the sesled vessel due to the heat generated by the hydration
reaction. When the hydrated material is released from tha pressurized vessel, the
particles typically have a diameter of less than 1 micron with high surface area
(over 15 ma/g). Nondolomitic, high-calcium quicklimes hydrated in similar fashion
in the laboratory can have similar properties. Pilot plant results (4) indicated
that 40 percent sorbent utilization or better could be readily achieved at
reasonable stoichiometric ratios (Ca/S near 1.0). The sorbent particle size was
in that instance approximately 0.4 microns. Encouraged by the pilot plant
results, plans were developed to continue the investigation at a suitable
full-scale operating boilar.
EXPERIMENTAL
A field test was conducted at a 50-MW western boiler to evaluate direct injection
of pressure hydrated lime to reduce sulfur dioxide amissions. This paper presents
the preliminary results obtained during the field test, and includes a comparison
of the preliminary data to prior results obtained in 1982 by Injection of
limestone. In both instances, the tests were conducted at the Root Lake Station,
43-2
-------
Unit 2, operated by the Otter Tall Power Company. The station firea a low sulfur
North Dakota lignite from the Beulah Mine of the Knife River Coal Company. The
present tasts were conducted from September 26, 1984, to October 13, 1984.
Thirty-two (32) teats in all were conducted. These Included a period when a high
calcium hydrate was injected continuously for 30 hours. In five of ehe tests, a
magnesium-containing doloolcic hydrate was employed, also for comparative
purposes. In all tests, the sorbeat was injected into the furnaee above the
tangentially fired burners.
The main components of the field test included:
1.0 Injection system optimization.
2.0 Determination of S02 reduction and llae utilization rates.
3.0 Evaluation of the effects on electrostatic precipitation performance and
particulate emissions.
4.0 Measurement of boiler performance effects in terms of operation, fouling,
draft losses, and efficienciee.
5.0 Characterization of sorbent and sorbent-ash mixtures, particularly in
view of sorbent's commercial origin.
This report diseusses preliminary results obtained in meeting the first two
objectives, and are presented without detailed analytical analyses of samples
collected during each test series. Therefore, the final data points may be
slightly different from the preliminary results presented in this report; however,
the numerical magnitude and trends are considered representative. The final
report (prepared by E8&C) is expected eo be completed by May, 1983. Some
observations and data gathered in meeting the last three objectives will be
briefly highlighted.
Sorbent Injection System. The sorbent injection system specifically designed for
the testing at Hoot Lake Unit 2 is pictured in Figure 1. Key features of the
injection system included:
e Hydrate storage.
e Feed rate control and turndown (10:1).
e Variable injection aite selection,
e Variable injection velocity.
Pressure-hydrated llae was delivered in 1-ton bulk bags for storage on site.
Approximately 200 bags In all were delivered, each bag numbered and tared. As
required, hydratad lime from the bulk bags waa dumped Into a 250-cubic foot day
storage hopper using a forkllft truck. The hopper was equipped with a vibrating
bottom to facilitate flow of the material. Due to fluctuations in the density of
the lime, the original screw feeder produced erratic flow rates during the initial
tests. The screw feeder was replaced with a dlgltailzed weigh feeder, vhleh
provided accurate and constant feed rates. Feed rates were also measured by the
known weight of material added to the hopper for comparison to the weight feeder.
From the feeder, the lime flowed through a rotary airlock to a pneumatic conveying
line. During the tests, lime feed rates were varied from 400 to 4,400 Ibs/hr.
Conveying air was supplied to the system at up to 120 inches static pressure from
43-3
-------
a ranted compressor. Air flow ranged up Co 1,400 sc£m. Tha material flowed
through cha 6-tnch diameter line, to cha primary splieeer locafiad on eha
sacond level of eha power station. From tha primary split tar, eha flow was
•furehar split by a pair of secondary splitters. As originally installed, as shown
in Figure 1. four flexible injection liaas vara usad to shoot eha lime into eha
furnaca. gas. Later, an additional splittar was addad to furthar split oaa-half of
eha flow ineo four pares. This gsva a six-nozzle dallvary system. Tha plpa
nozzles wara raadlly raplaead to vary inj action velocities from 200 Co 300 fps.
Thraa aozzle slzas wara availabla: a 1.56-inch round, a 2.06-inch round, and a
1.0 by 2.44-inch rectangular. Via ehasa nozzles, sorbane was fad ehrough
availabla obsarvaeion doors, ovar-flra air ports, and othar pores at various
lavals of cha furnaca as indicated in Figura 2. Although a temporary
installation, many features and operations would be similar in a permanent one.
PRELIMINARY TEST RESULTS
After a series of shakedown runs to east eha sorbane system's operability and eha
analytical testing procedures, testing commenced on September 26 and was completed
on October 13, 1984. Pressure hydratad high-calclua and dolomitlc sorbants wara
tasted. The actual tasting proceeded In a series of four phases, differentiated
by eheir objective(s);
e Injection system optimization, using four nozzles at 44 or lower
MWG.
• Improved sorbent dispersion, using six nozzles at 44 MGW.
• Impact of varied Ca/S ratios, by varying the sorbane injection
races.
a Longer Cera effects during ehlrey-hours of coneinuous injection.
The inieial eese phase was dadicaead to eha optimization of injection locations
and nozzle geometry. Initially, sorbane was injected through four nozzles at
individual levels of ehe furnaca (at levels 3 or 4 or 5) to evaluate temperature
and dispersion affects. The plant maintained a constant generating load of 44 MWG
with tha top laval of burners out of service. This gave a heae release rata of
15,000 Beu/fe* hr in line wieh eurrene U.S. boiler standards. Under these
conditions sulfur reduction ranged from about 20 eo about 49 percent when the
Ca/SOj mole ratio was varied from 1.5 to 3.5, as shown In Figure 3. Calcium
utilization rates were unexpectedly low, as shown by eha dashed llna in Figure 4.
However, sulfur dioxide content of tha gas was also low, ranging from aboue
500 ppm eo 700 ppm, corrected for dilution. Ac concentrations below 1000 ppm,
utilization rates can drop drastically. Sulfur analysis of tha ligniea fired ae
eha elma of 0.55 eo 0.76 parcene confirmed eha lower than expected SOa
measurements. (The eypical lignite at tha plant ranges about 1.1 percent in
sulfur content.)
Results while injecting entirely on ehe fourth floor (four nozzles) appeared
superior to ehose at eha oeher two levels (corresponding eo different injection
temperatures) at constant load. This is illustrated in Figure 3 where flue gas
sulfur dioxide reduction (Z) results tend to fall about ehe lower dashed line
during the inieial tests. Injection on the fifth level front produced an
exceeding poor result falling wall below ehe line due to poor sorbent
distribution. Rasules se Level 3 were average or below. Ae ehe call end of ehe
initial tests, an additional two easts wara conducted while ehe burners wera fired
in a "low NO " configuration. Temperaeures were reduced in ehe furnace. Sulfur
reduceion values did improve eo a modest degree falling aboue the upper dashed
line of Figure 3. Calcium utilization rose to near 13 percent at a stoichlometry
near 3.0. In general, however, SOa removal efficiency and sorbent utilization
values wera significantly below expeceatlons based on pilot plant studies. This
43-4
-------
vas also the ease in eha f«v tests Conducted at still lower loads (34-38MWC).
Visual observation of the sorbent streams in eha furnaee, indicated that sorbent
dispersion in the flue gas was not optiaal. Therefore, a six nozzle system was
devised in an attempt to achieve batter dispersion. Subsequent analyses of the
hydraeed material indicated chat varying sorbent properties may also have
contributed to the low removal efficiencies in eha initial easts.
The six nozzle system was evaluated at various furnace levels, including the sixch
as well as the fourth and fifth levels. Simultaneous injeceion at several levels
was the norm. Seven different configurations were investigated at a nominal
constant stoichiometric raelo ranging from 1.4 Co 1.7. Also, during this period,
a digital weigh feeder replaced the screw feeder to obeain better control of
sorbent feed. Sulfur reduction was improved over ehe earlier tests, as
illustrated by the cluacer of daea points falling on the higher solid line shown
in Figure 3. Some partial evidence also suggests sorbent properties may have
simultaneously Improved as well. Calcium utilization values also clustered abouc
Che aid to upper 20 percent levels, at an appoximate stoichiometric raelo of 1.5,
as shown in Figure 4. Of ehe eonflguraeions inveselgated, the more successful
appeared to be those which Included injeceion ae the rear of eha fourth level.
This provided ereacmene of ehe gas tucking under ehe pendane superheater. Other
than this observation, no real differences In results were apparent among the
various eonflguraeions so ehe eescs continued with injection both on the fourth
(two nozzles) and fifeh floors (four nozzles). This injeceion configuraelon was a
compromise between considerations of residence elmes versus excessive tem-
peratures. Using this configuraelon, the easts continued to the key objective of
determining the effectiveness of varying sorbent rates on sulfur reduction.
Injection raees ware systemaeicslly varied eo produce molar Ca/S02 ratios ranging
from 0.5 to 4.7. Sulfur reductions increased in a near monotonia progression
from about 22 percent up to 73 percent, wieh increasing molar ratio. The data
falls aboue the upper solid line in boeh Figures 3 and 4. Near « molar raelo of
2.0, a 50 percene sulfur dioxide reduction was observed, resulting from s
25 percent utilization of ehe hydraeed 11m. £t is also shown that somewhat
improved results were obtained using dolomlelc lime. These are preseneed in the
uppermost dashed line in Figures 3 and 4. However, since the dolomite contains
45 pereent unreactive magnesium oxide, aboue twice ehe weight of material muat be
used to give equivalent molar raeios of calcium eo SO*. Boilar operationa and
economies, therefore, may favor the high calelele hydraeed lime.
At ehe conclusion of the feed rate parametric testing, a 30-hour test was
initiated to confirm S03 removal efficiency data, to identify operational
problems, and to characterize the impact on ESP operation. During the extended
period of injection, sulfur content in the lignite varied from about 0.6
to 0.9 percent, ineraaaing baseline sulfur dioxide levels. Also, sodium levels in
the coal doubled fros 4.8 to 9.6 percent. Soot blowing vas increased to levels
normal for the high sodium coneene. As sorbent injection conelnuad, controlled
sulfur dioxide concsseratlons fall to 280 ppm, equal to about a 67 pereane
reduction at a Ca/S ratio of about 2.7. The preliminary results are presented as
a sear in Figures 3 and 4, and are approximately comparable to the best results
obtained with the dolomltle hydrate. Possible explanations for the higher S03
removal efficiency compared to the parametric data include: 1) Coal sulfur levels
rose above those in any other teat; 2) Sorbent properties improved, i.e., particle
size, specific surface area and porosity; 3) Dynamic buildup of the sorbent on
furnace tubes continually presenting reaceive surfaces for sulfur dioxide capture.
Differentiating among any of theaa or other poaslbilleles is beyond ths scope of
our preliminary discussion hare.
43-5
-------
LIMESTONE INJECTION COMPARISON
Seven casts war* conducted at Che Hooc Lake Station In 1982 (2) to determine the
effectiveness of S03 removal using limestone injection. The limestone was
injectad either with the lignite through the burners, i.e., pulverized with the
coal, or directly into the furnace at the fourth level. A -200 mesh material was
used for the direct injection. The boiler vas operated at 44 Mtf vith the top rov
of burners out of service as in the present tests. Most of the 1982 tests were
conducted vith a low NO burner configuration employing the burn*r-out-of- service
(BOOS) method. x
During the 1982 series, the Ca/S (injected limestone to coal sulfur) mole ratios
varied from 1.6 to 5.0 while apparent S03 removal (based on flue gas analysis)
increased from 21 to 47 percent. Note that the mole ratio is different from that
used in the present study. Results from the present test were thus converted to
the same basis for comparison and are illustrated in Figures 5 and 6. The lover
line depicts the limestone data; the upper two lines, the band of SOa removal data
obtained upon injection of the hydrated lime. As the hydrated lime Ca/S (coal)
mole ratio was varied from about 0.4 up to about 4.2, sulfur removal efficiency
ranged from about 16 up to about 83 percent, as shown in the banded data. At a
stoichiometric ratio of about 1.6, the limestone achieved only a 21 percent sulfur
removal; the pressure hydrated lime at the same stoichlometry removed 40 to
55 percent of the flue gas sulfur dioxide, a 90 to 160 percent Improvement. The
dolomltlc hydrate appears even more effective, removing about 65 percene of the
sulfur dioxide at the same stiochioaetric ratio. High calcium hydrated lima in
the 24-hour test gave comparable results to the doloaitic hydrated lima.
The greater effectiveness of the hydrated limes is also demonstrated in terms of
calcium utilization presented in Figure 6. At the lover Ca/S ratioa, 1.6 and
belov, utilization of the lime sorbent was two to three times that of the
limestone. To reduce sulfur dioxide concentrations by 50 percent required a Ca/S
mole ratio greater than 4.7 with the limestone. With the pressure hydrated lime,
the Ca/S mole requirement was about 1.8 based on coal sulfur content. On a weight
basis, over three times the amount of limestone must be injected in comparison to
the hydrated lime. This will of course have significant economic impact on
operating eosts.
PLANT OPERATIONS
Boiler Performance. Boiler operation during the tests vas continuously monitored
by plant and EERC personnel. The data collected has yet to be analyzed in any
quantitative manner. Qualitatively, however, it vas observed that there vas no
significant impact on boiler performance related to the sorbent injection. Soot
bloving schedules, if at all, were curtailed so as not to interfere with test
measurements. Due to the rise in sodium in the coal during the 30-hour injection
phase, soot bloving frequency vas increased to a schedule normal for high sodium
situations. No significant Increase in draft losses vas noted.
Fouling probe data has been partially analyzed indicating an approximate doubling
of the fouling rate. Deposits, hovever, vere soft and fluffy, readily removed by
soot bloving. In areas not accessible to the blowers, deposit grovth appeared
limited, sloughing off the tubes once grovth (velght) exceeded adhesive forces.
High sodium conditions apparently aggravated the situation. Nevertheless, the
plant operators through normal procedures vere able to control boiler tempera-
tures and pressures within their normal operating ranges. More quantitative
results aveit further data reduction,
43-6
-------
Precipitator Performance. Impact on precipitator performance vas evaluated by two
mean*:
e Observation of the existing precipitator in terms of power levels,
resultant stack opacity levels, and in the 24-hour test phase by the
determination of collection efficiency. Particle size distributions
of the eorbent-fly ash mixtures were also determined by Anderson
cascade lmpaetors to estimate fine particulate penetration.
e Determinations of resistivity and ability to improve performance by
conditioning the ash vith moisture and/or sulfur trloxlds using a
slip stresa of the flue gas.
Without any optimization of the precipitator controls, opacity levels read from
the plane transmissometer during the entire test phase never exceeded 10 percent,
veil belev the 20 percent NSPS requirements. Stack appearance remained
essentially clear. In the four-field precipitator, power levels in the first field
decreesed by about 6 to 7 percent. This vas due to the slight current suppression
effect caused by the increased loading. Pover stood constant in the remaining
three fields. In this ease of e hlghg sodium fly ash (sodium enhances
conductivity), resistivity never exceeded 10 ohm-cm. Some representative values
are given in Table 1. Any attempted conditioning of the already low-resistivity
ash failed to make any significant reduction in resistivity. The advantage of
reduced sorbent addition, therefore, also accrued to the precipitator's control
function. In contrast, during the 1982 tests vith high rates of limestone
addition, opacity levels did approach 20 percent.
CONCLUSION
The preliminary results of this field test indicate that 50 pet. removal of SO. at
calciua-eo-suifur ratio of 2.0, corresponding to a calcium utilization of 25 pet
can be achieved. Sulfur capture and utilization rates in this test series were
superior to those demonstrated at the station in an earlier 1982 test series
evaluating injection of limestone.
aoctowledczments
We wish to acknowledge the outstanding cooperation of the people of the Otter Tall
Power Company. These Include Robert Middleton, Director, Production Operations;
Robert G. Johnson, Manager, Steem Generation; and Norman Ringstrom, Plant Manager,
Root Lake Station. Roy Payne, EERC, is alao to be thanked for hla critical
insights and guidance in furthering the work here.
43-7
-------
REFERENCES
1. Tannassaa Vallay Authority, Full-Scala Dasulfurizatlon of Stack Caa by Dry
Limastona In1action. Voluma I. EPA 650/2-73-019a US Environmental Protection
Agency, Washington, OC, August 1973.
2. Blytha, G. M., Dry Liaaatona Injection Test at * Low-Rank Coal-Fired Povar
Plane. DOE/FC/10200-T5, November, 1982.
3. Cara, P. L. et al, LIMB Tasting; The Use of Dry Sorbant Co Reduce Sulfur
Oxide Emissions from PulvarlzadCoal Flames ffnder Lov SOx Conditions. Joint
Symposium on Stationary Combustion NOx Control, November 1-4, 1982, Dallas
Texas.
4. Weber, G., "Pilot-Scale Studies of In-Furnaca Hydratad Lima Inlaction." Coal
Technology, Sepe. 17-21, 1984, Pittsburgh, PA.
43-8
-------
Dry Sorbent Injection System
H;0m«a Lima Fumaea inj—tun Tna4»
MM
Figure 1. Dry Sorbent Injection System
•0.0.
low
T»
n*
Figure 2. Elevation of Hoot Lake Unit 2
43-9
-------
BO
24 HR TEST
60
5
t-
U
3
Q
III
C
40
0
01
A
cajciic mcmn
MWG Mint rUKMS
U*fi 10WMO.
Z6/
/ /a3
20
MONUUM ftOONS
BO-QMinCIWrottAK
SUKASOWSKNOii UlCIKNltMU
2 0
4 0
6 O
MOLAR Ca/SC»2 RATIO
Figure 3. S0« Reduction By Pressure Hydrated Lime
As Sorbent Feed Rate Was Varied
4Q -
A
* V>Y
*o\\
4.S* ,
* '
V
\ o
vo
\
\
¦ OOiOMtltC
_* 24 •«
W t£ST
.<•6
V V
\i4
N
N
A6
J-
-U
2 0 4 0
MOLAR Ca/S02 RATIO
60
Figure 4. Calcium Utilization As Sorbent Feed
Rate Was Varied
-------
BO
24 in
IEST
eo
IM2
UMESIOME ItSIS
40
CMOWMWRMI
k MUiW-lf MOONS
• tow NO.
noons
20
oaoMiic tirotwn
SUKMSCM»IS OENOK VUtCIKM IEV11S
40
MOtAR Ca/S (COM4 RATIO
Figure 5. SO, Emissions - Pressure Hydrated Line
Compared To Limestone Trials In 1982 (2)
eo -
CAtaic hvoraie
MOLAR Ca/S (COALf RATIO
Figure 6. Calcium Utilization - Pressure Hydrated Lime
Compared To Limestone Trials In 1982 (2)
-------
Table I
ltf-SITU :RESISTIVITY RESULTS
EXTENDED TEST PERIOD OCTOBER 11-13, 1984
Precipitator Slip Streaa
Sorbent Temperature Resistivity
Date
Tiae
lb/hr
Flue Gas Conditioning
•f
oha-CM
10/11
10S0
—
None
350
4.3 x 10®
10/11
2220
2.880
None
360
9.2 x 10®
10/12
0S10
2.S20
None
360
8.7 x 10®
10/12
0540
2.520
30 ppa SOj
360
7.9 x 10®
10/12
0600
2.520
60 ppa SO,
360
8.4 x 10®
10/12
0630
2.520
•
Cooling
280
3.5 x 10®
10/12
0710
2.520
Cooling
200
3.0 x 10®
-------
EPA WALL-FIRED LIMB DEMONSTRATION
Robert V. Hendrlks
U.S. Environmental Protection Agency
Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
ABSTRACT
The U.S. Environmental Protection Agency 1s engaged In a research program to
develop Improved control technologies for emissions of sulfur and nitrogen
oxides (SOx and N0X) from the combustion of fossil fuels. Previously
developed low N0X systems for coal combustion are being demonstrated, and
methods for removal of S0X in the combustion process 1n conjunction with
these systems are under development.
A low-cost method for S0X control is the use of Limestone Injection with a
Multistage Burner (1-e., Tow M0X burner). This technology, abbreviated LIMB,
promises to be retrofittable to large and snail coal-fired boilers at a lower
capital and operating cost than currently available pollution control
alternatives such as flue gas desulfurizatlon.
EPA has recently awarded a contract to Babcock I Wilcox (BAW) for a full-scale
utility size demonstration of LIMB. This paper describes the recently Initiated
EPA LIMB Demonstration Project with emphasis on outlining the project objectives
and scope and describing the demonstration host site.
INTRODUCTION
Nearly all approaches to meeting the country's energy needs call for an increasing
reliance on American coal. But coal burning must be accomplished without compro-
mising the country's environmental goals, necessitating technology which will
minimize the environmental Impact of coal burning at an acceptable cost to the
utility customer.
The U.S Environmental Protection Agency 1s engaged in a research program to
develop improved control technologies for emissions of sulfur and nitrogen
oxides (S0X and N0X) from the combustion of fossil fuels. These emissions
are important because of their magnitude and their apparent link to acid rain.
Previously developed low N0X system for coal combustion are being demon-
strated, and methods for removal of S0X in the combustion process 1n conjunction
with these systems are under development.
44-1
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A low-cost method for S0X control is the use of Limestone Injection with a
Multistage Burner (I.e., low NOx burner). This technology, abbreviated LIMB,
promises to be retrofittable to large and small coal-fired boilers at a lower
cost than currently available pollution control alternatives such as flue gas
desulfurfzation. The process, if successful, would also enable many existing
older power plants to reduce amissions while burning high sulfur coal, which 1s
lower 1n cost than low sulfur coal which might otherwise be required.
Recently, EPA requested and received proposals for a full-scale utility size
demonstration of LIMB. A proposal from Babcock & Wilcox (B4W), a major utility
boiler manufacturer located 1n Alliance, Ohio, was selected for contract award.
34W proposes a 3-1/2 year project that includes design and installation of a LIMB
system at Ohio Edison's 105 MW coal-fired Edgewater Station 1n Lorain, Ohio, and
a full year of operating and testing to demonstrate its capabilities. EPA will
share the cost of the project with the major project participants - BAW, Ohio
Edison, the State of Ohio, Stone A Webster Engineering, and Radian Corporation.
HISTORICAL PERSPECTIVE
Qry sorbent Injection was evaluated by EPA 1n a full-scale demonstration at TVA's
Shawnee plant from 1968 to 1971. The general conclusions from that study were
that there was Insufficient S0X removal (15-50%), that thermal deactivation
(deadbuming) of the sorbent and decomposition of the sorbent/sul fur complex
were a major problem, and that there was inefficient mixing of sorbent with
combustion gases. In addition, power plant operational problems occurred
including fouling 1n the convective passes and loss In electrostatic precipitator
efficiency. The technology was put on the shelf until 1979 when EPA pilot plant
tests Indicated the possibility of 70* removal of S0X with limestone injection
through low-N0x burners. These tests renewed interest In limestone Injection
technology and launched EPA Into a research program to define reaction mechanisms
and identify conditions to optimize the technology.
In recent years, progress has been made on many fronts in understanding sorbent
injection technology and resolving problems identified with the use of the
technology. The mechanisms and kinetics of sorbent reaction with S0X have been
studied, and the critical Importance of an optimum temperature range has been
identified. The negative Influence of flyash on sorbent utilization has been
identified, and methods have been evaluated for minimizing deactivation of the
sorbent. Recent EPA research has concentrated on production of highly reactive
sorbents which promise to Increase sorbent utilization and reduce the quantity of
sorbent required. Other studies are evaluating the effects of sorbent injection
on flyash characteristics and electrostatic precipitator performance, the effects
of Injection parameters on sorbent mixing and subsequent utilization, and the
effects of boiler design and operation on sorbent reaction conditions.
Full-scale trials of dry sorbent Injection are planned or are in progress in the
United States and In several other countries which will give further experience
with the technology. To mention a few, at Otter Tall Power Company's Hoot Lake
Unit 2 in the U.S., lime was injected in a tangential-fired 53 MW boiler burning
lignite for a 3-week evaluation of S0X reduction. Pennsylvania Electric Company
is evaluating sorbent injection in a 640 MW wall-fired boiler burning low sulfur
cleaned coal. Also in the U.S., Conoco is evaluating sorbent injection in a
44-2
-------
15 MW industrial boiler firing a high sulfur coal. In the Federal Republic of
Germany, injection tests on a 60 MW utility boiler and a follow-up demonstration
at a 300 MW brown-coal-fired boiler have recently been completed. Also in
Germany, a demonstration of sorbent injection 1s now underway on the 700 MW
Weiher III tower boiler burning a low sulfur coal. In France, experiments with
sorbent injection on a 50 MW tangentially fired boiler have been used to design a
system for applying the technique to a new 600 MW boiler. In Austria, six boilers
ranging in size from 20 to 330 MW have been evaluated with furnace injection.
Finally, full scale limestone trials at Saskatchewan Power in Canada on a
lignite fired utility boiler were recently completed.
Based upon an improved understanding of dry sorbent injection technology and the
additional experience that can be brought to bear upon the design of an injection
system, EPA feels that a demonstration of the LIMB technology on a U.S. coal-
ffred utility boiler 1s now timely as a culmination and confirmation of the
improved knowledge that has been obtained within the last few years.
LIMB DEMONSTRATION OBJECTIVES
The basic goal of the LIMB Demonstration 1s to extend the LIMB technology devel-
opment to a full-scale application on a wall-fired utility boiler. By co-funding
such a demonstration with industry, EPA hopes to encourage the acceptance and
ultimate commercialization of this technology In the shortest possible time.
The successful retrofit of LIMB to an existing boiler is expected to demonstrate
that (a) reductions of 50 to 70% in S0X and N0X emissions can be achieved at a
fraction of the cost of add-on flue gas desulfurlzation systems, (b) boiler
reliability, opers&ility, and steam production can be maintained at levels
existing prior to LIMB retrofit, and (c} technical difficulties attributable
to LIMB operation - such an additional slagging and fouling, changes in ash
disposal requirements, and an increased particulate load - can be resolved 1n
a cost-effective manner. A more definitive expression of these goals will be
developed early in the project to be used to guide project decisions and to
measure the success of the demonstration program.
PROJECT TEAM AMD FACILITIES
The LIMB Demonstration contract was awarded to Babcock « mi™* *o
19B4, based upon a competitive procurement process The MW 28*
consists of Babcock * Wilcox (project management. InjectlS!
Ohio Edison (host utility), Stone i Webster "If0*-, ,
^'KittT^tfgsrs siissu js sx *
utility site wfll be Ohio Edison's 105 MW Edgewater Unit
Ohio. The unit (Figure 1) is a BiW-^signed!wffwwLr.mS elliEKl:
wall-fired boiler for pulverized coal firing. The ? 4 ? c,
sulfur cot! but .(11 svrftcft to 3S mlfur cMl during t». £r"o
-------
Major components of the boiler are superheaters, a pendant reheater located in
the convection pass, economizers, and air heaters. Water and steam pass through
the boiler under natural circulation. The precipitator Is typical of precipita-
tors retrofitted to utility boilers In the last 5 years and Includes ample
collection surface and power supply to enable compliance with particulate require-
ments when burning low sulfur coals. The power supply and rapper controls offer
complete flexibility to examine alternate operating modes so as to more fully
characterize the Impact LIMB will have on the wide range of equipment installed
on utility boilers. A summary of boiler descriptive data is provided in Ta Table 1.
SCOPE OF THE PROJECT
The demonstration project proposed 1s a 3-1/2 year effort 1n which a LIMB system
will be retrofitted to the Edgewater Boiler No. 4, operated, and evaluated. A
project schedule is shown 1n Figure 2. The project consists of several distinct
phases - a preliminary stage to develop the LIMB process design applicable to
Edgewater 4, a construction and start-up stage, and an operation and evaluation
stage. These stages are more specifically described below.
Preliminary Activities
The preliminary phase of the project is a recognition of the dynamic state of
LIMB technology development at this time. On-going LIMB developmental work at
EPA and in the private sector 1s expected to provide resolution of many of the
technical issues that affect process design within the time frame required for
the specification of the final design for this demonstration. The preliminary
phase will enable the contractor to evaluate new work with respect to LIMB
retrofit to the host site and to tailor a process design specific to the host
site. EPA Is expecting to work closely with the contractor during this pre-
liminary activity to participate In specifying the design parameters for the
LIMB system to be demonstrated. It 1s expected that the development of the
process design will also Involve consultation with major LIMB researchers as
well as conduct of limited on-site studies to characterize the boiler and other
studies to further refine the selection of LIMB design parameters. On-site
studies might Include measurement of boiler temperature and velocity patterns,
evaluation of boiler structural components, and similar activities. Other
limited studies to refine LIMB design parameters might Include specific sorbent
and coal characterization studies, investigation of deposition and collection
characteristics of sorbent/ash mixture, and similar s1t«-spec1f1c investigations.
The primary product of this phase will be a preliminary design for a LIMB retrofit
to the Edgewater 8o11er No. 4. This preliminary design will include a description
of key design features, general process description, a process flowsheet, equip-
ment and structural layouts, and a description of other requirements. A cost
estimate and a project schedule will also be prepared.
This phase will also enable the contractor to clarify and upgrade the expected
performance goals for the demonstration project within the capabilities of the
preliminary design. The performance goals will address the expected emission
control performance, boiler performance and reliability, boiler operab111ty,
and downstream effects.
44-4
-------
Upon completion of the preliminary phase, expected by August 1985, a package will
be prepared that includes a process design, estimated cost, schedule, and
reassessed performance goajs. The preliminary package will be evaluated by EPA
for technical merit and for assurance that the project goals can be met as
proposed within funding available. A go/no-go decision will be made prior to
the Installation of the proposed LIMB system.
Design and Installation of LIM8 Retrofit
Upon approval of the preliminary design concept, the contractor will proceed with
the engineering design, installation, and start-up of the LIMB retrofit. Major
retrofit components are not yet defined, but the original proposal was based on
the following Items:
a. B4W Dual Register Burners/Modified W1ndboxes/Overf1 re
A1r Ports
b. Sorbent Handling and Injection System
c. Additional Sootblowers
d. B4W Continuous Gaseous Emission Monitoring Equipment
e. Support Structures, Miscellaneous Equipment
Upon completion of equipment Installation and check-out, the system will be oper-
ated during a brief optimization period before the test phase begins to examine
the various operating alternatives and select the best procedure for the I-year
performance test. These tests will be short-term in nature and will not be
analyzed as extensively as the performance tests. It is expected that the system
will be available for a performance evaluation by January 1987.
Performance Evaluation
A broad and complete evaluation is required to characterize the performance of
the retrofit LIMB system. Because LIMB 1s an emission control technology,
emission characterization 1s »n Important aspect of the performance evaluation.
However, operational aspects of LIMB must also be determined. For example, we
know, based on the Shawnee experience and our experience with LIMB technology
of recent years, that LIMB application can:
• Alter the boiler's temperature profile which may Impact
boiler efficiency.
* Increase the amount of mass loading which may result 1n
convection pass plugging and accompanying draft losses,
Increased tube erosion, greater sootblowing requirements,
and Increased particulate emissions.
44-5
-------
* Alter the chemical composition of solids going overhead which
may result 1n Increased furnace slagging, tube corrosion, and
decreased ESP performance.
* Potentially affect the solid waste disposal requirements,
since Increased solid wastes with a different chemical
composition will result.
To quantify these and other effects, a two-part program has been devised to
provide a full characterization of the LIMB retrofit. A baseline test will be
made early In the project to quantify and document normal operations that occur
1n the absence of LIMB. The baseline test will Include a rigorous test program
of on-site measurements coupled with an analysis of historical boiler records.
Following system start-up and documentation, a 1-year performance test will
be made to measure all aspects of LIMB performance. The overall objective of
the performance tests Is to demonstrate the program goals In conjunction with
continuous operation of the LIMB system. Briefly stated, these goals are:
(1) significantly reduce S0X and NOx emissions, (2) avoid negative Impacts on
reliability, operablllty, and steam production, and (3) resolve problems such
as Increased fouling potential and Increased particulate collection and hand-
ling problems in a cost-effective manner. Demonstration of each of these
goals will require a variety of measurements. For ease of discussion, these
measurements are described for the I-year performance tests only; similar
measurements will be performed during the baseline tests.
Emission Characterizat1 on. Measurement of emissions during the i-year test
period will be made to establish long-term emission characteristics of the
system. The 1-year test period will Include three 30-day test sequences
when full emission testing will be conducted with optimum LIMB operating
conditions. These measurements will Include continuous monitoring of S0X,
N0X, CO, CQj, Oj, and hydrocarbons using standard EPA sampling and analysis
methods. Manual measurement of particulate mass, composition, and size
distribution before and after the electrostatic precipitator (ESP) will also
be made at frequent intervals. Other measurements, such as fuel analysis and
continuous recording of boiler operating conditions, will be made to enable
correlation of emissions with parameters that affect emissions.
Boiler Performance and Reliability. Continuous monitoring and/or documentation
of steam production, operating time, and outages will be conducted during the
1-year test to evaluate the effects of sorbent Injection on boiler performance
and reliability. Slagging and fouling characterisites during LIMB operation
will be determined In tests collecting and evaluating operating data such as
steam temperature and pressure drop, visual Inspection of radiant and convec-
tive sections, and direct measurement of build-up on steam tubes. The extent of
corrosion and erosion will be determined by visual Inspection and measurement of
tube wall thickness at frequent Intervals. Solid deposition on furnace walls and
tube surfaces will be sampled and analyzed to further Identify and quantify
problem areas. In addition, monitoring of flue gas temperatures at several
points will be made to characterize the boiler thermal environment.
44-6
-------
Boiler OperabiHty. Boiler operablHty 1s measured by the maintenance and oper-
ating requirements of the system. The measurements collected to determine boiler
reliability will be used 1n conjunction with a log which keeps track of how much
additional attention, in terms of both manpower and instrumentation, 1s necessary
when LIMB is 1n operation. The need for additional manpower will be assessed
in the data evaluation phase.
Downstream Impacts. The increased solids-loading and the change 1n particulate
characteristics due to LIMB will Impact the ESP. These Impacts will be assessed
by an analysis of the data collected by particulate methods. In addition, samples
of the ash will be analyzed for resistivity, and ESP operating conditions will be
recorded.
The final downstream impact to be considered will be the handling and disposal
of the collected ash. Factors to be measured to assess the ash disposal impacts
include amount of additional ash, chemical content, hazardous potential, and
handling properties.
Operating Cost. The 1-year test will also be used to gather the data necessary
to calculate tne operating costs associated with the LIMB system. The capital
costs data will be determined from actual invoices. To allow the costs to be
calculated later, the on-site analysis will keep track of:
• Sorberrt usage,
• Steam production and power generation,
• Fuel 1 nput,
• Electrical charges,
• Maintenance requirements (labor and materials),
• Additional operating labor,
• Precipitator operation,
• Limestone feed system labor and power requirements.
DEMONSTRATION RESULTS
Upon completion of the performance test, a final report will be prepared that
will address the overall performance of the system in terms of the goals
established for the demonstration project. The report will include an evalua-
tion of the LIMB design and its operational and maintenance features and will
address the experience gained during construction, start-up, and year-long
demonstration. In addition, potential modifications which would improve the
technical and cost characteristics of the system will be Identified. Finally,
the report will present rtconroendatlons and guidelines for the further commer-
cialization and applications of the LIMB process to major classes of boilers
for both retrofit and new boiler installations.
44-7
-------
Although the LIMB Demonstration report is expected to be the focal point of
EPA-generated information on the application of LIMB technology, it will,
by no means, be the only available aid in extending LIMB technology to other
applications. A body of Information 1s now being generated which will address
specific aspects of LIMB design and operation, enable extension of the technology
to boiler systems differing 1n design and operation from the demonstration host
site, and aid in prediction of LIMB operation and costs for potential boiler
applications. This Information will include large data bases on various sorbents
and coals, design Information on low-NOx burners and other LIMB components,
results of combustion studies under a variety of conditions, results of studies
to Improve removal and collection of ash, and computer models to predict SQX
removal under a variety of boiler design and sorbent injection conditions, just
to mention a few. Assuming a successful demonstration of the LIMB system and the
generation of supporting applications data, EPA expects that LIMB will become
a viable, low-cost commercial technology by 1990.
UNIT CONVERSION TABLE
To Convert From
pounds/hour
cubic feet
British thermal units/hour
degree Fahrenheit
cubic feet/minute
pounds/square inch
tons/hour
square feet
inch/second
To
kilograms/second
cubic meters
watts
degree Celsius
cubic meters/second
pascals
kilograms/second
square meters
centimeters/second
Multiply By
1.259 x 10-4
2.831 x 10-2
2.928 x 10-1
(T-32)/18
4.719 x 10-4
6.894 x 103
2.519 x 10-1
9.290 x 10-2
2.54
44-3
-------
Secondary Reheater
iat<
X
Superheater /
Burners ...
Heater
Primary
Superheater
Economizer
w
V
Figure 1. Boiler Schematic for L1M8 Demonstration,
Edgewater Station, Unit 4.
44-9
-------
Activity | 1884 | 1886 | 1986 | 1987 I 1986 |
Otvtlap Prsliminuy LIMB Concapt mmmmmmmm
Datermina BiistiM Conditions ¦ "
Piiptn Ewjin—»m>8 Dtiiga ¦ ¦ n
Procure, tniUN Equipment 1 ' 1
Opanli System mmmw
Evaluate Perlormanca mmmmh
Evaluate Test Data w
Figure 2. Project Schedule
-------
Table 1
CHARACTERISTICS OF HOST
SITE BOILER*
UTILITY
UNIT
RATING
TYPE
INITIAL OPERATION
MANUFACTURER
BOILER TYPE
STEAM FLOW
Ohio Edison Company
Edgewater No. 4, Lorain, Ohio
10S MWe
Steam Turbine
June 1957
Babcock & Wilcox
Radiant* Wall-Fired
690,000 lb/hr
DEMONSTRATION FUEL - Ohio Bituminous, 2% or Greater Sulfur
BOILER DESIGN
Furnace Volume
Heat Release Rate
Gas Temperatures
Convectlve Pass Design
Sootblowing Capacity
Coal Mills
PARTICULATE CONTROL
Type
Installation Date
Collection Surface
Design Performance
Design Drift Velocity
52,300 ft*
9.34 x 108 Btu/hr
Leaving Economizer 605*F
Leaving A1r Heater 275'F
Pendant Secondary Superheater and Reheater
Horizontal Primary Superheater and Economizer
Tubular A1r Heaters
2 at 1150 CFM, 300 ps1g each
4 mills at 13-14 tons/hr each
Lodge-Cottrel 1 Electrostatic Precipitator
1982
316,800 ft*
518,000 acfm at 280*F at an Efficiency of 99.38:
4.2 cm/sec
* Units most familiar to the reader have been used 1n this table.
A unit conversion table Is provided at the end of this paper
for convenience.
44-11
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THE HOMER CITY EXPERIENCE IN DEVELOPING A
LIMB PROCESS FOR USE WITH COAL PREPARATION
D. W. Carey, 0. I. Cessna, J. H. T1ce
Pennsylvania Electric Company
1001 Broad Street
Johnstown, PA 15907
The New York State Electric and Gas Corporation
Homer City Generating Station
Homer City, PA 15748
ABSTRACT
Pennsylvania Electric and the New York State Electric and Gas Corporation have
been experimenting with and further developing a system of Limestone Injection -
Miiltl-Stage Burner (LIMB) that can supplement an existing coal cleaning applica-
tion to bring their Homer City #3 unit Into compliance with EPA's 1971 New Source
Perfomance Standard. Two series of limestone Injection tests have been carried
out during short runs on the full-scale unit with encouraging results. A series
of small scale combustion tests 1s now being done by selected contractors to lead
to the design of a flexible boiler LIMB retrofit. This flexible system will be
operated while varying the parameters of Injection location, furnace load, firing
mode, and limestone type during a four-month test series planned for late-1985.
The objectives for the Homer City retrofit are 25 percent SO2 removal from flue
gas containing 1.6 lbs SOj/lO® BTV using a calcium/sulfur ratio of 1.0 or
less. This report presents the results of the Owners' tests to date and their
plans for further LIMB development specific to Unit #3.
INTRODUCTION
The Homer City Power Complex 1s a mine-mouth power plant with three coal-fired
boilers. This facility began commercial operation 1n 1969 with two 600 MW units
(Units 1 and 2). A 650 MW boiler (Unit 3) was put Into commercial operation In
December, 1977. The power station obtains approximately 60 percent of Its coal
from two dedicated mines at the plant site. The remaining coal 1s purchased from
other mines within 30 miles of the power station.
Units 1 and 2 must comply with an SOj emission limit of 3.7 lbs/10® BTU, as
prescribed by the Pennsylvania Department of Environmental Resources (PaDER).
Unit 3 must comply with Federal New Source Performance Standards (NSPS) which
limit SO2 emissions to 1.2 lbs/106 BTU.
The owners of the Homer City Power Complex, Pennsylvania Electric Company and The
New York State Electric and Gas Corporation, Initially considered two different
strategies for complying with these emission regulations. The first Involved
using cleaned coal 1n Units 1 and 2 and installing a flue gas desulfurizatlon
45-1
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system (FGD) on Unit 3. The second strategy, called the Multi-Stream Coal Clean-
ing System (MCCS), Involved the construction and operation of a coal preparation
plant to produce compliance coal capable of meeting both emission regulations at
the power complex. An analysis of these strategies indicated that the MCCS would
produce substantial operating, maintenance, effluent disposal, and boiler
operating cost savings when compared with installation of an FGO system on Unit
3. The MCCS was therefore selected by the owners as the best technology for
complying with SO2 emission regulations at the power station.
The complex MCCS began operation in 1977 but has not been able to clean coal to
the conditions specified 1n the plant design. An extensive test and evaluation
program designed to identify and correct the causes of plant operating problems
continues. While progress has been made in cleaning sized coal from the Helen and
Helvetia on-site coal reserves, current operation dictates that a quality
"plateau" at 1.5 to l.S lbs SOj per million BTU has been reached. Further coal
cleaning modifications to reach the 1.2 pound limit have been proposed and are
currently being tested by partial incorporation in the plant circuits, but the
cost and feasibility of these remedies is not fully known yet.
A LIMESTONE INJECTION SUPPLEMENT
Limestone Injection was one of a number of supplementary SO2 control tech-
nologies investigated for use with coal cleaning in the mld-1970's. A full scale
test of Unestone Injection with coal was tried on a 40 MWe unit at Penelec's
Front Street Station In 1977. West Virginia University had some bench scale tests
of a process that they called "Sulfurtatlne1' to fix SO2 1n combustion fly ash.
While their pilot-scale unit worked very well with the system, Penelec's Front
Street unit showed no measurable reduction 1n SO2 despite a tremendous increase
in particulate emissions during the test.
After that discouraging show, the process was dormant in both Penelec and NYSE2G
until 1t resurfaced with the qualifier of low temperature, low N0X staged com-
bustion in 1981. The limestone injection process, now the Limestone Injection -
Multi-Stage Burner (LIMB) process, emerged once again for Homer City Unit 3
compliance when a state-imposed consent order was about to expire with no practi-
cal system for emission reduction at hand. The LIMB system was quickly dusted off
and plans for a short-term, full scale trial on Unit #3 with the best available
cleaned coal were made.
THE 1982 LIMB TEST
During an annual outage period on Unit #3, seven hundred and fifty tons of high
calcium limestone, with a size consist of approximately l-1nch x 1/2- Inch, was
purchased from M4M Lime Company, R. 0. 1, Worthlngton, Pennsylvania, and stock-
piled in the area just adjacent to the coal reclaim hopper. Approximately 550
tons of tiiis material was put into the reclaim hopper and directed to the
previously emptied "A" pulverizer storage bunker.
Deep cleaned coal from the low gravity side of the Homer City Coal Cleaning Plant
was stockpiled in the clean coal silos for a period of three weeks, and then fed
to the specially emptied min bunkers "B" through "F." The output coal sampled
during this stocking operation had a quality to produce an emission level of 1.34
lbs S02/108 8TU.
Several days of delay in the start-up of Unit #3 after its two-week scheduled out-
age and a last minute forced outage on the "F" pulverizer preceded the limestone
45-2
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test. The original plan was to operate one pulverizer with a limestone feed while
carrying full load with the remaining five coal mills.
Testing began with injection of limestone from the "A" mill and clean coal from
mills "B" through "E." The "F" mill was Inoperable for this phase of the test,
resulting 1n a reduced load for the unit. The Initial tonnage was approximately
8.2 TPH. This small volumetric flow may have contributed to feeder problems which
resulted in the feeder stopping several times, but 1t was successfully restarted
after each motor overload trip. In order to avoid these feeding problems, the
rate was Increased to 13.7 TPH until 11:00 PM; at which time the "A" mill was
taken out of service until the following morning to conserve limestone.
The following day, limestone was Injected at an Increased feed rate of 16.4 TPH.
The "F" mill had been restored to service and the unit was operating at a 640 MW
load. Four hours after reintroducing limestone, the "0* mill, with burners
located directly opposite "A," was removed from service, reducing the unit load to
540 MW (gross). This was the same load obtained when the "F" mill was not
operable the previous day. Approximately four hours after removing the *D" mill,
1t was restored to service, Increasing the unit to full load at 640 MW. In con-
junction with this change, the limestone Injection rate was Increased to 24.6 TPH
and continued until 5:50 AM the third day, at which time all of the limestone
supply had been exhausted (see Table I).
SO? concentration 1n the ffue gas was monitored continuously before and during
injection of the limestone. Limestone samples were collected every three hours
from a coal pipe sampler, and analyzed according to procedures defined for calcium
content and size distribution. Coal samples were also taken every three hours and
analyzed for moisture, ash, sulfur, BTU, and particle size. Samples of dust
leaving the air heater were collected by high volume samplers and analyzed for
lime reactivity and sulfur content.
For analysis purposes, this test was separated Into five test periods with
distinct operating variables to distinguish each of them. The average SO2
removal results for these test periods are shown in Table I. The overall test
results concerning Sfl2 removal are plotted in Figure 1.
Summarizing the results of this first full-scale, short duration test series:
• SO? removal rates were measured by comparing the sulfur level 1n
the as-f1red coal (sampled hourly) to the hour-long wet train gas
1 samples. During limestone injection, these removal rates ranged
between 20 and 40 percent.
e The removal rates seemed to be more dependent on the firing rate or
firing pattern than on the amount of limestone injected between 1
and 3 stoichiometric.
• There did not appear to be any Increase in ash deposition caused by
limestone Injection.
t The secondary, or large, air preheaters experienced an abnomal
increase in pressure differential across the elements during this
test.
e The electrostatic precipitator performance deteriorated during the
Injection series. Monitored opacity increased from six percent
before Injection to 12 or 15 percent during the two stoichiometric
45-3
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runs. In the three stoichiometric run, the opacity approached the
20 percent regulated limit as the test ended.
t There was a perceptible hydration reaction in the fly ash that was
generated by this test series. The "water stabilized" and piled
ash was noticeably warm, with steam emerging to produce noticeable
heaving 1n the freshly compacted material.
The most interesting result, as far as our respective company managements were
concerned, was the Unit #3 had been well within SOj compliance during a con-
siderable portion of the test period. A formal Research and Development effort
was initiated to further improve the process specific to Unit #3, and 1t became a
viable option in a second Consent Decree that was executed between PaOER and the
Owners.
THE 1983 LIMB TEST
A second full-scale, short-term trial was set up on Unit #3 for March of 1983.
After receiving technical Input from EPA, EPRI, consultants, and others with some
LIMB experience, we decided to try Injection with coal supplying the two top rows
of burners. The test was set up similar to the 1982 trial, except that the unit
was about to begin a scheduled maintenance outage period. Ourfng the 1982 test,
the unit was returning to service from a scheduled outage.
Limestone from the same supplier and coal were pre-nrixed to target a stolchionetry
of two, and the mix was put into empty coal bunkers of the "A" and "0" pul-
verizers. Specially produced cleaning plant coal was stockpiled to be used in the
other pulverizers 1n the course of this test. When these pulverizers were placed
in service, the test period began. We quickly noticed that the removal rates were
not nearly equivalent to those of the earlier test, and that the coal quality was
greatly affected by residual coal in the bunkers feeding the other pulverizers.
Results of this trial prompted us to try restructuring the test part way through.
The remaining limestone was reserved to be fed into the "A" and "0" bunkers after
all of the coal/limestone mixture was exhausted. This constituted a second test
period within the overall trail.
The results of this second full-scale trial were:
e SO2 removal was always less than 15 percent when a l.S stoichio-
metric mixture of coal and limestone were fired 1n the top rows of
burners. Both front and rear wall burner rows were used in this
test. (Figure 2)
e SO? removal ranged between 15 and 20 percent when limestone alone
(with considerable coal contamination) was fired.
e The secondary air preheater pressure drop Increased perceptibly
during the test period; although they had been badly fouled before
the test.
e The electrostatic precipitator performance degraded as the amount
of limestone feed increased. Opacity was four to eight percent
before the test, and increased to 15 percent during the coal/lime-
stone mix trial. When contaminated limestone was fed at two times
stoichiometric, the opacity went to 24 percent.
e The ash hydration reaction was noted again.
45-4
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• No Increase 1n slagging was observed.
AIR PREHEATER EXAMINATION
In the course of the 1983 outage, one major project was to replace the hot and
intermediate temperature baskets of the secondary air preheaters. The low
temperature elements had been replaced previously, and were found to be clear of
deposits after water washing. The hot and Intermediate sections were both badly
obstructed and badly deteriorated. A program of sampling, destructive basket
examination, and deposit analysis was Initiated Immediately at the beginning of
the outage.
Sorre conclusions reached during this test series were:
e Dilute sulfuric acid, formed when water from the air heater steam
blower combined with the sulfur trioxide in the gas, was the
primary cause of the air heater fouling. All of the plates had a
0.5 to 1 mm rough layer that bloomed away from the surface and
partially blocked the gas passages.
• Fly ash particles readily adhered to the rough layer causing 30-40
percent of the examined plates to have a loose deposit blocking the
available air passages. These deposits ranged In length from a few
Inches to the entire length of the basket.
• All of the deposits originated at areas of severe corrosion near
the "cold" end and built up toward the gas Inlet. These were
easily removed with high-pressure washing; however, low-pressure
washing formed a fly ash sludge that promoted additional corrosion.
e The limestone Injection tests complicated the problem by depositing
calcium oxide and calcium sulfate-rich fly ash on the existing
deposits. When exposed to moisture - possibly from the steam-
blower or washing - these deposits hardened to cap existing
deposits.
e Additional fly ash loading during the test put an even larger
burden on the open air heater passages.
While limestone injection was a factor In the air heater fouling, the blockage was
due primarily to corrosion of the basket fill material, steam blower operations,
and method of cleaning during unit outages.
MODELING STUDIES
After the 1983 test, a program to try and optimize Injection locations for Unit #3
using modeling, temperature profiling, and furnace model testing was begun. A
number of prospective contractors were requested to provide a series of tests that
could meet the following objectives and be specific to Unit #3:
e Optimize the Injection process by selecting an Injection location
that minimizes the amount of Injection needed for a 25 percent
SO2 removal.
e Evaluates the effects of limestone Injection on boiler operation.
45-5
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• Evaluates the Impact of coal quality (sulfur and ash levels)
1n SO2 removal efficiency.
• Provide a preliminary design for a limestone injection retrofit on
Unit #3.
A technical evaluation of the proposals received resulted in selection of two
contractors, Babcock & Wilcox and Research-Cottrell, to perform wo He 1n parallel.
Each one has had a history of work In L1M8 development, and each proposed a dif-
ferent approach to achieve the set objectives. B£W proposed to do furnace testing
on a small scale model with an array of multi-stage burners, while Research-
Cottrell proposed to do furnace tests on one nearly full-scale burner operating
alone. Both organizations are doing gas flow modeling studies and both will
produce a reconmendatlon for Injection locations. Research-Cottrel1 is also
studying the problem of ESP operation with low resistivity fly ash.
1985 PROPOSED TESTS
The research and development group has proposed to the Homer City Owners that a
temporary system for limestone injection 1s operated for a four-month period on
Unit #3. The Injection locations will be those proposed by both B£W and R-C. The
RID group has also recommended that the Owners modify the top rows of burners on
both front and rear walls to reduce the flame temperatures in those rows. Other
Injection locations will also be considered.
During the four-month trial, Unit #3 win be operated for weekly test periods with
one discrete set of limestone Injection variables fixed; I.e., injection location,
firing configuration, limestone type, and coal type. By analyzing the results of
these individual runs, the R&D group hopes to find a mode of limestone injection
that produces the best calcium utilization with a 25 percent SO2 removal rate.
A 25 percent removal was fixed because Homer City's coal cleaning plant is cur-
rently able to produce coal containing less than 1.6 lbs S02/million BTUs, and a
currently-running program of Improvements will certainly improve that operation
somewhat. During these test runs, separate experiments will also be structured to
determine limestone effects on the convection tubes, air preheaters, ESP, and ash
disposal equipment. Successful conclusion of these trials will provide design
Information that can be used for a permanent installation and modifications to the
auxiliary equipment.
Under the terns of the Owners1 Consent Oecree with the PaDER, the unit must be
operating in full emission compliance with limestone Injection by December 30,
1988. This research program 1s structured to meet that compliance schedule.
(Table II)
LIMB'S ROLE
The Homer City Owners currently have a number of parallel research and technology
improvement programs in process, each with the intent of bringing Homer City #3
into compliance at a reasonable cost. Limestone injection appears to be highly
competitive with these other compliance scenarios because 1t promises Increased
flexibility In purchasing, processing, and blending coal for the unit at a reason-
able Installation cost. We also note that it could be the only low cost candidate
that can maintain its full removal rate 1n accord with the current three-hour
emission averaging that is used to determine compliance.
45-6
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The limestone Injection research program at Homer City 1s still dependent upon the
results of & number of other events that influence the unit's legal status. Near
tern developments will determine how far the injection technology for Unit #3 will
be pursued.
CONCLUSION
The Honer City Owners view limestone injection as a feasible, low cost process to
supplement coal cleaning on Unit #3 for SOg emission compliance. Preliminary
tests have Indicated that the process Is workable and that boiler equipment can be
modified to operate with limestone Injection. Future work to optimize the
process, Its reagents, and to promote further downstream SO2 capture can further
enhance a workable system that will soon be developed for Unit #3.
45-7
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HOMER CITY #3 UNIT
INPUT COAL QUALITY & MEASURED EMISSIONS
VS. TIME
Emission Rate
1.5-
1.4 -
1.3-
1.2 -
1.1 ~
1.0-
Sampled Coal Quality
CEM Readings
DER - F Factor
DER - Input Coal Calc.
Limestone Addition
0.8
6/24-Noon
Midnight
Midnight
6/26 - Noon
Midnight
6/25 - Noon
1983
FIGURE 1
-------
ut
t
(O
# scyio* BTU
2.5
2.3 -
2.1 -
1.9-
1.7 -
1.5-
1.3 -
1.1 -1
FIGURE 2
LIMESTONE INJECTION TEST II
EMISSION RATE
# SO2/10° BTU
ft-
I Ini
Llnesfcone and Coal Mixed
Injected In Both Top Burner Rows
A H:
Limesttme Injected „
Separately Tlirough
Both Top Burner Rows O
fnpul Coal Quality
CEMethod
Method 6B (Continuous)
Method 8 CAE
1—T
1—i—i—1—r
1500 2100
1200
March 9
1—I—I—T~
0300 0900
1—r~
1500
1—r
2100
March 10
1—1—i—r
1
2400
1
t—r
1500
1—r~
2100
1200 1000
March 11
1983
-------
Table I
HOMER CITY STATION - UNIT #3
DRV LIMESTONE INJECTION TEST RESULTS
4*
Ut
I
Gross
Generation
IKUI
540
640
640
540
Boiler
Operation
"F" Hill
Off
Full Load
Full Load
"D" Mill
Off
Linestone
Injection
Rate
(Tons/Hr)
13.7
16.4
16.4
16.4
Input
Coal
Quality
(# SOo/lO* «
SO?/10° BTU)
1.53
1.53
1.53
1.47
F Factor
1.171
1.260
1.249
1.137
Emission Rate
(i SOp/1p6 BTU)
Calculated*
P Input Coal
1.031
1 .233
1.187
1.150
X
Eailssion
Reduction
Input Coal
30.0
23.8
24.7
26.1
640
Full Load
24.6
1.53
1.194
1.209
25.7
*DER preferred nethod. F Factor used as backup.
-------
Table II
DEVELOPMENT SCHEDULE - LIMESTONE INJECTION FOR HOMER CITY #3
To Novenber 30, 1984
February 1, 1985
August 1, 1985
September 1, 1985
January 1, 1986
April 1, 1986
May 1, 1986
March 1, 1988
June 1, 1988
Decenber 31, 1988
— Pilot-scale tests designed to optimize SO2 capture
1n Homer City #3.
— Begin installation of a partial LIMB/LI conversion to
quantify removal efficiency and long-term operating
effects.
— Unit outage for Installation of injection ports.
— Begin testing the partial conversion.
— Begin detailed evaluation of partial conversion.
— Report due on partial conversion.
— Begin detailed engineering on a full-scale conversion
with auxiliaries for Unit #3.
— Start-up full-scale Unit #3 conversion.
— Begin performance tests - Unit #3 LIMB conversion.
— Compliance with consent decree.
45-11
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NOy/SO2 CONTROL EXPERIENCE AT SASKATCHEWAN CORPORATION'S
BOUNDARY OAM Q.S. — UNIT #6
R. 0. W1nsh1p
Combustion Englne«r1ng-Superheater Ltd.
Ottawa, Ontario CANAOA
J. A. Haynes
Saskatchewan Power Corporation
Reglna, Saskatchewan CANAOA
46-1
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INTRODUCTION
Fossil electric power generation in Canada uses coal aa Its primary fuel
source and with its us« public concern haa aaealacad about the control of
S02 ind N0X emissions due to their environmental impacts • Uiastarn
Canadian coals typically contain .32 - 12 sulphur, whereas Eastern
Canadian coals typically have sulphur contents of 22 - 52. Conaaquantly,
S02 emission control philosophias should ba tailored to mat tha
severity of tha specific problem. Similarly with NOx, diffarant coals
and diffarant firing conditions will dictata tha naeaaaity of diffarant
systaaa for N0X control. Tha currant Canadian federal aaisaion
guidelines for both SO* and M0_ amission is 0.6 lb/106 Btu. (258
ng/J).
Praaantad in this paper ara tast rasults of C-E Canada's Hodifiad
Combustion Technique, which radueaa SOj and N0X amissions. Tha work
was dona in 1983 and 1984 at Saskatchewan Power's Boundary Oaa Generating
Station. Tha system includes overfire air and Low N0X Concentric Firing
(LNCFS) with Umaatona injection for tha control of both SO2 and H0X
emissions. This paper discusses operation, test results, economic
feasibility and gives a programme for ongoing tast work.
Tha tast work was carried out with a Saskatechwan lignite containing
.32 -.52 sulphur and a heating value of 6600 Btu/lb. (15300 kJ/Kg)
It is felt that this.demonstration in a unit of 300 MW in an actual
operating environment provided substantial banaflts in tha development of
this promising new technology.
STEAM GENERATOR DESCRIPTION & MODIFICATIONS
Tha tast unit for this project was Saskatchewan Power Corporation's
Boundary 0am Unit #6 - a Combustion Engineering natural circulation
tangsntially firad unit with a divided furnace. (Figure 1). Tha unit was
constructed and commlsaioned in 1978 and is rated ae 300 MW output. Tha
unit performance data is indicated in Table I with a typical analysis of
tha lignite coal fired in Table 2. This coal has a low sulphur content
typical of many Wastarn Canadian coals and has a high inherent calcium to
sulphur ratio. Tha heat raleaaa rate par plan area in the furnace is
typical of lignite fired units (1.46 x 10 Btu/hr ftz) (4600 KU/mz)
and therefore would be relatively low compared with a furnace designed to
fire bituminous coal.
Prior to modification, the firing system was a conventional divided
furnace with a C-E Tangential Firing System consisting of eight (8)
windboxes, each containing a series of coal and air compartments. With
the C-E system one pulverizer feeds one elevation of burners. Tha
arrangement of the windboxes is depicted in Figure 2. There ara five (5)
elevations of coal nozzles with adjacent auxiliary air ports and an
uppermost integral overfire air compartment.
In the spring of 1983 modifications were performed to the windboxes of one
furnace to convert it to a C-E Low NO Concentric Firing System (LNCFS)
for the admission of auxiliary air. The arrangement of these offsets and
nozzles is shown in Figures 3 and 4. For tha tast, concentric firing air
nozzles were installed having tha capability of tilting horizontally as
46-2
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well as vertically (typically both fuel and air nozzles have the
capability of dicing only vertically). The distribution and control of
primary air, auxiliary air, fuel air and overfire air in both sides of th«
divided furnace were modified.
H0X AND SO2 FORMATION
The two major pollutants resulting from thermal power generation are N0X
and SOj. N0_, which is a collective reference representing both NO
and NO2, will form in and around the high temperature regions of the
flame as a consequence of the combustion process. The formation of
nitrogen oxides is derived from two sources, nitrogen contained within the
combustion air and that contained in the fuel. N0X formed from nitrogen
contained within the fuel, termed fuel N0X, is dependent en oxygen and
nitrogen in the fuel which varies with the rank of eoal. The N0X formed
from fuel nitrogen ean best be controlled by limiting the oxygen
concentration in the primary combustion region, fuel N0X formation is
relatively insensitive to temperature. N0X formed from the fixation of
atmospheric nitrogen, termed thermal N0X, is very affected by flame
temperature and to a lesser degree by available oxygen. Overfire air and
LNCFS employ the principles of reducing flame temperatures while removing
available oxygen and nitrogen from the primary flame rone to reduce the
N0X emission levels.
SOj and SO3 are formed from the combustion of sulphur contained within
the eoal. However, the amount of SO3 usually accounts for less than It
of the total sulphur oxide emission. SO* discharged to the atmoephere
contribute* to 'acid rain' formation. "Direct furnace sorbent injection"
refers to a sorbent which is pulverised in much the same manner as coal
and then injected directly into the furnece. In thia specific situation
limestone was used aa the added sorbent. It was inter-mixed with the coal
at the feeder level after which it underwent pulverization and was
thenlnjected into either of the bottom two eoal elevations.
The inorganic material In many coals contains calcium and other basic
compounds which are available to react with the SO*. This was the ease
with the lignite tested at Saskatchewan, at least half of the calelum
reported in the test results originated from the ash.
Upon entering the furnace the limestone undergoes calcination where COj
is freed in a manner depending upon the type of limestone sad initial
heating rate leaving CaO. Under suitable furnace conditions, solid CaO
will then inter-mix with the gaseous SO5 to create a reaction in which
solid calelum sulphate (CaSO^) is formed. This solid product can then
be removed by a precipitator and disposed of. These reactions are
dependent upon temperature, and for optimum capture rates the sorbent
(i.e. limestone) should be injected away from the higher temperature
portions of the flame. Ac very high temperatures limestone particles will
sinter and lose their porosity, thus becoming chemically unreective. The
capture rate is also very dependant on both the degree of mixing and the
residence time of the limestone in the furnace.
The reduction of SO2 and H0X is complementary when sorbent injection
philosophy is applied in combination with the low NO burner technology
due to the inherent lower combustion temperatures, which provide
appropriate conditions for both H0X reduction and SOj capture.
46-3
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OPERATION
An important pare of the Boundary Dam Station test programs was Co
demonstrate that the Modified Combustion Techniques, aither la combination
with, limestone injection or without it, could b« operated successfully by
the plane staff and control systems and that there would be oo significant
adverse affaee on unit reliability, afficiancy or slagging.
Sinea tha tast startad in May 1983 tha unit has oparatad sueeassfuXly with
soma form of tha Modiflad Combustion Technique. Continuous limestone
injaction for SO2 control has only baan usad during tha tast periods.
Tha control room oparacors ara not aware of any differences in oparation
with tha modifiad combustion taehnlqua* To take full advantage of tha
system, a mora complax air distribution control system would b« required
to control: tha oxygen in tha primary burner ragion, tha deslrad overfire
air amount, tha dasirad auxiliary to fual air ratio, and tha air velocity
or wlndbax to furnace differential pressure. During the tests these
rstios were manually set at MC& and the dampers left in that position
during operation.
Tha C-E Low NO Concentric Firing System incorporates auxiliary air
nozzles that offset a portion of combustion air outside of the primary
firing circle, hence, the name concentric firing. Introducing auxiliary
air outside of the primary combustion zone results in a significant
portion of tha nitrogen and oxygen contained in the auxiliary air being
removed from tha high temperature primary flame region, and also results
in the lowering of flame temperature in this region. Tha auxiliary air
which comprises a significant amount of tha total combustion air is
directed along tha walls. Teets have shown that an oxygen rich layer is
formed around the complete perimeter of tha furnace. This rich oxygen
zone Is felt to be responsible for the reduction of slagging in the burner
region of the furnace due to maintaining the ash constituents (the ash
fusion temperatures ara higher in an oxidizing atmosphere than in a
reducing atmosphere) in an oxidizing atmosphere and by providing an air
screen through which the esh particles have to pass in order to Impinge on
the furnace walls. At the same time this produces a reducing atmosphere
at tha centre of the furnace which aids in overall N0X control.
Figure 3 shows that the furnace ash deposition was evaluated as being less
severe with tha LNC7S firing compared to the normal tangential firing. An
overall average assessment of furnece deposits Indicates a reduction in
furnace slagging of approximately 20 X In the UlCFS furnace, with the major
reduction in slagging being nearer the corners of the unit. This was felt
to result from relatively low concentric air velocities compared with
normal design velocities, because only a portion of the burner
compartments were altered.
During the test period the rate of fouling in the superheater region was
monitored using ash deposition probes. Due to tha limestone injection and
the lower rate of ash deposition in the furnece there would be a slightly
higher ash loading to tha superheater. In the case of the Boundary Dam
test, the increased ash loading was not of major significance due to the
fact that the bulk of the calcium present was inherent In the coal ash.
It was possible to keep the superheaters and tha reheaters clean
throughout the test period by normal sootblowlng cycles.
46-4
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The addition of Limestone to the furnace results in a modified ash
composition viehin the furnace and superheater regions. Depending upon
the ash composition, eh* addition of calcium may either increase or
decrease the average ash fusion temperatures. In the case of the
Saskatchewan lignite with the relatively high sodium content, the addition
of limestone was normally beneficial in increasing the ash fusion
temperatures thereby reducing the slagging and fouling problems in both
the furnace and superheater. Zt is Important to realize that with other
fuels the addition of limestone might substantially depress the ash fusion
temperatures and cause Increased rates of slagging and fouling, even in
boiler regions not normally subjected to deposits.
The carbon in the fly ash was measured in many of the tests. However it
was not possible to correlate the carbon loss with any of the operating
parameters such as furnace oxygen level, pereent overfire air or ratio of
auxiliary to fuel air. During the test period the pulverised fuel sizing
was relatively coarse with 50Z to 602 through a 200 mash screen, end the
carbon in the fly ash varied from .5 to 1.51 with IZ carbon in the fly ash
representing an efficiency loss below .22. Previous tests have indicated
that under modified firing conditions and particularly low 02t (used in
order to reduce H0_ levels) that the carbon in the fly ash had
Increased. Using lignite with a fineness of 63X through 200 mesh, carbon
in the ash increased from 0.1Z at normal excess air levels and operating
conditions, to IZ using 1Z 0j levels and maximum overfire air
operation. In a unit designed initially for Modified Combustion
Techniques the coal fineness and degree of turbulence would be Increased
slightly in order to maintain the desired heat loss due to unburnt
combustible matter and ehe overall unit efficiency.
The unit operated reliably and without serious problems throughout ehe
test program, and for over a year since the conversion, with the operation
continuing to be similar to that with conventional firing techniques.
Since the installation of the LNCFS buckets, the fuel content has varied
ov«r its normal range including variations in sulphur, sodium, moisture
and calcium contents without demonstrating any abnormal operating
conditions.
TEST RESULTS
The major objectives of the emissions research portions of the test were
to investigate the following:
1) The effect of combustion modifications such as overfire air and LNCFS
on N0X emission level;
2) The effects of combustion modifications on SO2 capture by sorbents
inherent to the coel ash;
3) The additional capture rates achievable through the use of injected
sorbents;
4) The effects of combustion modifications and limestone injection on ash
deposition within the furnace.
Prior to converting one of the furnaces to concentric firing, some
baseline test work was done in 1982. Following the installation of the
concentric firing air nozzles three periods of tests were carried out at
46-5
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Saskatchewan Power Corporation's Boundary Daa G.S. In all, over 100 case
configurations vara used and eha variables included primary air flow,
auxiliary air flow, fuel air flow, overfira air flow, excess air level,
LNCFS and nozzle deflection angle.
The firse series of pose modification esses were conducted is June and
July of 1983 eo determine ehe effects of ehe LNCFS system on N0X
formation. Mose of ehese tests were conducted with ehe unit running ae
full load with the off see angle of ehe LNCFS nozzles ae maxima (25s).
Figure 6 shows ehe effece of varying ehe offsee angles of ehe LNCFS
nozzles and the amoune of overfire air. Ae full load, ehe lowese N0X
emission level measured during eha firse pose modificaeion esse period
varied becween 167 and 195 ppm which is a 572 eo 632 reduction from ehe
baseline during normal operaeing conditions. This same range of N0X
emission levels and reduceion was then demonstraced during ehe sorbene
injection testing.
The effece of limeseons injection on SO* reduceion ae various calcium to
sulphur raeios was also inveseigaead. The inherene calcium eo sulphur
racio of ehe coal varied becween l.S eo 2.5 and injeceed amounts increased
this racio up eo 3.8. The capeure races were influenced by several
faceors and Increased as ehe concancraeion of SO2 formed increased, and
as ehe calcium eo sulphur rseio Increased.
Figure 7 is based on a capeure race from a eheorecical sulphur coneene in
the coal as daearained by our laboratory analysis. Anoeher curve is shown
using an axerapolaeion based on a differene coal sulphur coneene which, as
noced previously, resules in higher capeures based on ehe greaear SO2
formed.
For ehe Boundary Dam eases with .342 sulphur, ehe S02 removal with a
calcium/sulphur racio of approximaeely 2.5 was 422; extrapolating this eo
a typical .52 sulphur fuel would give a capeure in ehe order of 502.
In November 1983 a second series of pose modificaeion eases was con-
ducted. Ies purpose was twofold: a verificaeion of previous resules, and
aore detailed work with regard eo sorbene injection and ehe SO2 emission
seudy. The resules of ehese eeses esseneially verified ehe previous
resules.
PRELIMINARY ECONOMIC EVALUATION
Initially ehe C-E Canada Modified Combuseion Technique for sorbene
injeceion was eargeeed ae low sulphur sub-bituminous and lignite fuels.
Ic is fele ehae eha system would be economically aetraceive for ehese
fuels because of eheir relatively low sulphur coneene (in Canada) and
because ehey coneain a significane amoune of alkaline maeerials in ehe
ash. In ehese cases, ehe capital cose of an inseallaclon is going eo be
low relative eo oeher alternatives such as dry and wee scrubbing, the
operaeing coses (excluding sorbene ucilizaeion) will be low compared eo
alternative technologies, and ehe cose of limescone would be similar eo
alearnaeive technologies for ehe same removal efficiencies (402 eo 602).
The economic scudies and research eo daee indicate ehae this conclusion is
corTace, and preliminary economic scudies by C-E Canada indicaee ehae this
syseem may be compecieive for fuels concaining sulphur coneene in the
region of 22.
46-6
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The major factors affecting the economic evaluation are:
1) The fuel analysis, particularly the lulphur and inherent calcium
sulphur content;
2) The type of firing system utilized;
3) The furnace beat release rata (temperature profile);
4) The cost and reactivity of limastone sorbenc;
5) The percentage sulphur capture required to meet emission guidelines.
On retrofit installations the suitability of Misting equipment to
operating under the new conditions is also a significant factor. This
Includes the performance of the electrostatic precipitator or bag filter,
the capacity of the ash removal systems, and the sootblover coverage. In
addition, the retrofit installation must have suitable real estate for
the addition of a limestone handling and pulverization system, and
sufficient space to fit the limestone injection system to the furnace.
A C-E Inc. study undertaken for E?R1 on the feasibility of limestone
injection for SO2 control on a 500 MW unit demonstrated that the system
could be economic for coals containing sulphur contents up to 42. The
advantage of the modified combustion technique for limestone injection is
the low capital eosc. However, in the case of higher sulphur fuels the
sorbent cost would trad to be higher than for other types of systems
(i,e. flue gas desulphurisatlon). This C-E Inc. study considered the
alternative of purchasing lower sulphur fuel. Clearly the economic
picture with regards to the Modified Combustion Technique with sorbent
injection is enhanced for units burning variable sulphur fuels and for
operation at lower load factors, where the lower capital cost may more
than coapensace for the higher sorbent costs.
The estimated cost of this technology (Including limestone pulverization
equipment coats) for a new unit handling Western Canadian coal with a
sulphur content below IS will range from approximately $22/kW to 915/kW
Installed, for unit sizes of 150 end 400 MW, respectively. For
retrofitting units, (not including the upgrading of the particulate
collection equipment) the costs are approximately $28/kW and $20/kW
Installed for unit sizes of 150 and 400 MW, respectively.
It should be noted once again that these capital costs are very much
lower than the capital cose of any other comparable SOj removal
technologies end the added advantage of the C-E Canada Modified Combustion
Technique is that it will reduce nitrogen oxide emission levels as well as
so2.
CONCLUSIONS & FUTURE PLANKING
The C-E Modified Combustion Firing System with direct limestone injection
has proven to be an effective and viable method of reducing NO and
SO2 emissions that result from burning Saskatchewan lignite. Results
derived from three series of tests conducted at Saskatchewan Power have
shown that a S0Z to 60t reduction in N0^ levels csn be achieved compared
with conventional tangential firing. The S02 emission levels for
46-7
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lignite vera reduced oa average co 5QZ of ch« theoretical lavels generated
utilizing naioly the inherent alkalai material of the lignite with a
calcium ca sulphur molar ratio of 2:1 based on a .52 sulphur coal. These
Cases also demonscraced Chat direct sorbent injection into the combustion
chamber will further reduce SOj emissions. The resules of these tests
showed that this technique can be effectively used co reduce the SO2
emissions of the tested lignite to meet the present federal guidelines of
0.6 lb/106 Btu (258 ng/J).
A significant conclusion of these tests was that the boiler with the
modified combustion technique can be successfully operated and controlled
by existing plant staff and control systems. It was also determined that
the increase in carbon loss due to the firing modLfications was
insignificant. Slagging in the lower furnace was less severe during tests
with the Modified Combustion Technique. Sorbenc injection was found to
increase the ash shedding rate and unit cleanliness was maintained with
routine sootblowing operation.
Additional research work is planned in the near future. Saskatchewan
Power and Combustion Engineering Canada are planning the demonstration of
an improved combustion system in the near future. This major
demonstration would investigate improved burners, location of overfire
air, location of limestone injection and sizing of limestone further to
tests reported herein.
46-8
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(Unpresented Paper)
SUCTION PYROMETRY TESTS ON INNOVATIVE FURNACE
5. L. Rakes
U.S. Environmental Protection Agency
Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Parte, NC 27711
6. T. Joseph
Northrop Services, Inc.
Research Triangle Park, NC 27709
ABSTRACT
Suction pyrometry tests were conducted on the Environmental Protection Agency
innovative furnace in the Environmental Research Center to establish the actual
gas temperatures at several points 1n the furnace at specified operating condi-
tions. Gas residence times were calculated using the temperatures established
by the suction pyromttry tests and gas compositions measured by the monitors.
At the selected firing rate of 47,300 Btu/hr {14 kW) thermal Input, gas residence
times of approximately 1.5 seconds between the temperatures of 2250 and 1600*F
(1232 and 871#C) were calculated.
INTRODUCTION
Northrop Services 1s responsible for the operation and maintenance of a pilot-
scale coal burning furnace owned by the Environmental Protection Agency. The
furnace is used to study techniques for limestone Injection through a multlstaged
burner (LIMB). The purpose of the LIMB furnace Is to test Innovative combustion
technologies: specifically, methods to reduce 502 emissions from coal-fired burn-
ers. The primary SO2 reduction technique to be tested is the Injection of lime-
stone at various points 1n the furnace and/or bumtr. From previous laboratory
studies, 1t has been shown that two Important furnace parameters that affect SO2
capture on 11mestone are: the temperature profile 1n the furnace and the resi-
dence time. This paper presents the results of testing to determine the temper-
ature and residence time of the gases in the LIMB furnace.
The LIMB furnace is versatile 1n operation in that air and fuel can be Injected
Into the furnace at a number of points. The exact configuration and combustion
conditions will be a function of the research objective of each test plan.• To
estimate the temperature, a baseline configuration was chosen. This condition
was to have all the fuel and combustion air nrixtd at the burner. (Mote; A
small flow of air Is always metered to the gas pilot to prevent heat damage.)
The air and fuel combust, and the resulting hot flue products travel through the
refractory core of the furnace and then pass through a water-jacketed section-
to reduce the temperature and quench any reactions that may be occurring. Ex-
47-1
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tensive temperature measurements were conducted with this furnace configuration
employing various excess air rates while burning both propane and coal. After
these tests were completed, the effect of adding staging air (or sortent carrier
air) was also Investigated.
Measurement of the furnace temperatures and residence times took place in two
phases. Figure la Is a schematic of the LIMB furnace as 1t was originally de-
signed. Tests conducted on this furnace configuration are referred to as Phase
I. Figure lb 1s a schematic of the furnace after two new sections were added
increasing the furnace length by 36 Inches (0.91 m). Tests conducted on the
longer furnace are referred to as Phase II. As part of the furnace, Type B
thermocouples are permanently located at various distances from the burner (see
Figure la and b for dimensions). The thermocouples are recessed approximately
1 inch (25.4 mm) back Into the refractory and therefore do not come 1n direct
contact with the flue gases. All the thermocouples are wired Into one of two
selective readouts on the control panel. To measure the true temperature of the
gas stream It is necessary to sample at the ports located in the furnace. The
following section gives a brief explanation of the theory used In making temper-
ature measurements. See Appendix A for sample calculations.
GAS TEMPERATURE MEASUREMENT THEORY
There are numerous methods and sensors that can be used to measure temperature.
In all cases, the temperature sensing element approaches a temperature 1n equi-
librium with the conditions of its environment. A temperature sensor receives
heat primarily by convective heat transfer from the hot gases in which it 1s
immersed. However, the sensor is also subject to heat loss or gain by radiation
to and from the surrounding surfaces and to a lesser extent by conduction through
the instrument itself. Therefore, if the temperature of the surrounding surfaces
1s higher or lower than that of the gases, the temperature of the sensor will be
correspondingly higher or lower than the true temperature of the gases (due to
radiation losses or gains).
For testing in the LIMB furnace, the best instrument available for negating ra-
diation losses and therefore measuring the true temperature of gases was deter-
mined to be a multiple-shield, high-velocity thermocouple (MHVT) also referred
to as a suction pyrometer.*1' Figure 2 illustrates the suction pyrometer used
to measure temperature 1n the LIMB furnace. These devices consist of a pair of
small diameter thermocouple wires surrounded by a series of ceramic shields
which Isolate the thermocouple from the surrounding radiation. A known volume
of flue gas 1s pulled over the shields containing the thermocouple. By inducing
a high rate of gas flow over the shields, the transfer of heat due to convection
Increases while the losses due to radiation are minimized. The small diameter
thermocouple wires (approximately 0.25 mi) negate conductive heat losses. There-
fore, the temperature of the thermocouple junction may be brought to equilibrium
with the true temperature of the gases.
The output of a suction pyrometer Increases to an equilibrium maximum, with an
Increase in gas mass velocity flowing between the outer and inner shields. Fig-
ure 3 illustrates this relationship between mass velocity and temperature indi-
cated by a suction pyrometer. It is important when performing suction pyrometer
testing to ensure that an adequate mass velocity Is maintained. It is recom-
mended that the gas mass velocity between the shields not be less than 15,000 lb/
ft2 hr (1,221 kg/m2s)J') a curve similar to that Illustrated in Figure 3 should
be developed for each individual suction pyrometer design. (See Appendix 3.)
This is accomplished by sampling at a low gas mass velocity (approximately 10 per-
47-2
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cent of capacity) and recording the corresponding temperature; the gas mass ve-
locity 1s then Increased and a new temperature recorded; and eventually the
temperature will reach a plateau (equilibrium). This temperature is the true
temperature of the gas stream, and the corresponding gas mass velocity where the
temperature levels off Is the minimum flow rate that must be pulled for that
pyrometer design.*2)
EQUIPMENT AND PROCEDURES
Figure 2 is a schematic of the suction pyrometer used to measure gas temperature
in the LIMB furnace. The following is a list of the Individual equipment pieces:
1. Outer ceramic shield
• 1/2-inch {12 nm) Inner diameter
• 3/8-inch (9.5 m) hole at tip
• 99* + alumina
2. Inner ceramic sheath
• 3/8-Inch (9.5 mm) outer diameter
• 1/4-inch (6.4 nm) inner diameter
• 99% «¦ alumina
3. Ceramic thermocouple wire support
4. Thermocouple wire
• platinum'- 6S rhodium
• platinum - 302 rhodium
• each wire 0.01 inch (0.25 im) diameter
5. Water jacketed stain!es steel probe
6. Condensation trap - impinger system
7. Pump
8. Dry gas meter
The following procedures were followed when conducting a suction pyrometer test:
1. The Impingers, pump, md dry gas meter were assembled according to the
procedures given 1n EPA Reference Method 5.*3' The first two impingers
were charged with approximately 200 ml of water, the 3rd 1mp1ng»r was
left dry, and the 4th Impinger was loaded about 1/3 full of silica gel.
2. The system was then leak checked from the sample line probe junction,
beck through the dry gas meter. A leak was any flow greater than
0.02 cfta (9.4 jmVs) with the line plugged.
3. The suction pyrometer was assembled by threading the two thermocouple
wires through the holes in the ceramic support, and then welding them
together. The support was then placed inside the Inner sheath, and the
sheath was then put inside the probe. The back-end of the sheath/probe
47-3
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was sealed with ceramic cement to prevent flue gases from bypassing the
sample line. Finally, the outer ceramic shield was placed over the
sheath so that the thermocouple junction was 1/4 to 1 Inch {6.4 mm to
25 mm) downstream of the hole In the shield.
4. The water and sample lines were then connected to the probe. The Type
3 thermocouple connector wires were connected from the pyrometer to the
panel temperature readout. (Note both panel and pyrometer used the
same readout.)
5. Before initial testing, the pyrometer was Inserted Into the stack along
with a Type K thermocouple, to provide a quick check as to the reliabil-
ity of construction of the pyrometer. A Type K thermocouple was Inserted
Into the double-shielded area of the suction pyrometer; I.e., 1t replaced
Type B. This Type < thermocouple was then inserted Into the stack at a
port where the temperature is approximately 1300*F (704*C). Next, the
suction pyrometer with the Type B thermocouple was placed 1n the same
port. No flow was pulled on either. The pyrometer was accepted as sat-
isfactory if the two temperatures were within * 5 percent. This was
done to verify adequacy of construction of the~pyrometer, not as a cali-
bration.
6. The probe was then marked off so that the hole in the shield 1s at the
sample point; I.e., the middle of the stack.
7. The pyrometer was allowed to reach thermal equilibrium without suction,
and the static temperature recorded.
8. A temperature versus sampling rate curve was Initially developed for this
pyrometer configuration at each sampling port. The pump was turned on
and adjusted to pull approximately 1Q, 25, 50, 75, and 100 percent of the
maximum sampling rate. At each sampling rate, the equilibrium tempera-
ture and exact sampling rate were recorded.
9. From testing It was determined that at least 15,000 lb/ft? hr (1,221 kg/
m^s) or 2.0 scfm (994 um^/s) measured at the dry gas meter must be pulled
to reach equilibrium. In subsequent tests, only one sampling flow rate
was pulled. This rate is 1n excess of where the temperature leveled off.
This flow rate constitutes 20 to 50 percent of the total flow In the
furnace.
RESULTS AND DISCUSSION
Numerous suction pyrometer tests have been conducted at the LIMB furnace. Tests
were conducted first to determine the true temperature profile and residence
times at a given firing rate and then to determine 1f/how furnace variables (e.g.,
burner design, excess air) affect the temperature profile. Also as a result of
tests performed, two new sections were added to the furnace. Results of the
earlier suction pyrometer tests, with the shorter furnace, are discussed in
Phase I, while results of testing the current furnace are given in Phase II.
Phase I Testing
Initial testing was begun using a propane firing rate of 67,500 Btu/hr (19.8 kW),
which Is equivalent to burning 5.0 Ib/hr (0,63 g/s) coal. The stoichiometric
47-4
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ratio (SR) of combustion air to fuel was set at 1.1 (or also referred to as 10
percent excess air). It was originally assumed that firing propane or coal at
this rate would produce the desired temperature profile and an adequate residence
time to perform limestone injection testing. Results of these suction pyrometer
tests, plotting residence time versus measured temperature, are given 1n Figure
4. Frequent breakage of the ceramic shield and sheath occurred during the early
tests. Therefore, the two tests in Figure 4 were performed over a period of
days. As can be seen from this figure, the upper temperatures are close to
3000*F (1649*C) and the residence time of the flue gases 1n the furnace 1s less
than 1.0 second. To reduce the temperature and increase the residence time,
lower fuel firing rates were tested.
As noted in the theory section, to ensure that the true temperature of the gas
Is being measured, curves showing the relationship between pyrometer mass flow
rate versus temperature must be developed. For the data In Figure 4, these
curves are presented 1n Appendix B. From these curves 1t was noted that at least
15,000 lb/ft? hr (1,221 kg/m2*) Cor 2.0 scfm (900 vnP/s) measured at the dry gas
meter] must be pulled over the thermocouple junction to reach in equilibrium tem-
perature— i.e., the flat portion of the curve. Dependent on the firing rate and
stoichiometric ratio (SR) this sample rate can represent 20 to 50 percent of the
total volume of flue gases 1n the furnace. Pulling this large a percentage of
the total volume will eventually affect furnace conditions; however, this did not
appear to affect the measured gas temperature. First, the sampling time Is short,
approximately 2.0 to 5.0 minutes at each port. Secondly, before any sampling was
performed the furnace was allowed to equilibrate for at least 16 or more hours at
the desired conditions. Therefore, it was assumed that upsetting the furnace
conditions for that short a period of time would not greatly affect the thermal
profile of the system since thermal Inertia was so great.
The next firing rate tested was 47,3Q0 Btu/hr (14 kW) which corresponds to burn*
ing 3.5 lb/hr (0.44 g/sJ coal. This value was chosen because it is the lowest
feed rate of propane that can be burned in the furnace while simultaneously in-
jecting limestone at the burner. At lower propane flow rates, combustion condi-
tions in the furnace become very erratic. Figure 5 shows the results of two
suction pyrometer tests performed at this lower firing rate. Both tests were
performed while burning at an SR of approximately 1.25. However, after the test
on 11/8/83, a new section of furnace was added between the fourth port and the
water jacketed section. The new furnace section does not have a port, so no
suction pyrometer data 1s availablt. A thermocouple, recessed 1 Inch (25.4 m)
into the refractory, gave a temperature readout of approximately 750*F (399*C).
This temperature 1s at least 200 to 400*F (93 to 204*C) cooler than the gases
Inside the section. Temperature profiles and residence times at this lower fir-
ing rate were now very close to an acceptable range. A summary of the data for
these tests is given in Table 1.
Phase II
Radial Burner. To improve the temperature/residence time of the flue gases in
the furnace, two new sections of furnace were added. In addition, five new
sampling ports and five Type B thermocouples were also Installed. To verify the
new temperature profile In the furnace an additional suction pyrometer test was
conducted.
47-5
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Again, an initial firing rate of 67,500 Btu/hr (19.8 kW) while burning propane
was tried. The results are plotted in Figure 6. As compared to conditions
under Phase I, the temperatures are lower and the residence times of the gases
Increased. Although 1n an acceptable range, it was felt that by reducing the
firing rate, the temperature window and residence time could be maximized for
the furnace configuration.
A series of tests were therefore conducted at a lower firing rate of 47,300 8tu/
hr (14 kW) [3.5 lb/hr (0.44 g/s) coal]. Suction pyrometer testing was performed
while burning propane at this firing rate and SR of 1.05, 1.15, and 1.25. The
results of these tests are presented in Figure 7 and Table 2. In addition dupli-
cate tests were performed at the same condition, SR of 1.25, on different days
(see Table 2). The results are within + 2 percent of each other for each port,
and most of the temperatures are less tftan a half a percent different. This
shows good reproduclbil1ty of results.
Suction pyrometer testing was also conducted while burning 3.5 lb/hr (0.44 g/s)
of Pittsburgh #8 coal. Again, the air stoichiometric ratios were 1.05, 1.15, and
1.25. The results are presented in Figure 8 and Table 3. The procedures de-
scribed in the previous section were modified because of plugging problems of the
pyrometer with fly ash. From the original suction pyrometer tests (see Appendix
3) 1t was determined that at least 15,000 lb/ft? hr (1,221 kg/m2s) [2.0 scftn (94
um3/s) measured at the dry gas meter] must be pulled over the thermocouple junc-
tion to be 1n the flat (equilibrium) portion of the curve. At these relatively
high volumes, the suction pyrometer would immediately plug with fly ash and/or
molten ash. To eliminate the plugging problem, an efficiency of the suction py-
rometer at a low flow rate was determined from the graphs 1n Appendix 3. From
these graphs, 1t was calculated that at 11,000 lb/ftz hr (895 kg/m2$) [1.5 scfm
(707 um3/s) flow on the dry gas meter] the pyrometer temperature was 98 percent
of the equilibrium temperature. For the data in Figure 8, sampling was conduct-
ed at a flow rate of 11,000 lb/ft2 hr (895 kg/m2$) [1.5 scfm (707 uoH/s)3 and
the resultant temperatures divided by 98 percent. At this lower flow rate plug-
ging was not a problem.
Finally a series of tests were conducted to determine what effect burner design
and the addition of sorbent injection air would have on the temperature versus
residence time profiles. All previous data have been reported using the radial
burner. Ourfng testing of the furnace 1t was determined that the axial burner
will be the burner of choice for SO2 reduction testing.
Axial Burner. Suction pyrometer tests were conducted with the axial burner and
compared to the radial burner. In addition, another series of tests were con-
ducted with the sorbent Injection probe being Inserted at a point approximately
32 inches (0.81 m) from the burner tip. Tests were conducted with each burner
with and without sorbent air being Injected at this point. Whenever sorbent air
was injected into the furnace, the tangential air to the burner was reduced by
the appropriate amount to keep the overall SR to 1.25. Results of the tests are
presented in Table 4 and Figure 9. As can be seen from this data, there 1s only
a slight difference in the observed temperatures for the two burners when all the
air is added at the burner (only about 5 percent difference measured at each
port). When sorbent air is added downstream of the burner, the observed tempera-
atures between the burners vary by about 10 percent. The effect of adding sorbent
air lowers the measured temperature profile for each burner design.
47-6
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The measured temperatures when adding sorbent air downstream of the burner are
anywhere from 5 to 10 percent lower than adding the air at the burner. The far-
ther away from the burner, the more uniform the temperatures become. The above
tests were conducted at an SR of 1.2S. An additional set of tests was conducted
at an SR of 1.05 using the axial burner both with and without sorbent injection
air. The results of these tests are plotted in Figure 10. As can be seen, at
this SR", adding sorbent Injection air at this point greatly reduces the peak tem-
peratures near the flame, but has little effect on the temperatures farther down
the furnace length. Temperature variations range from approximately 10 percent
nearest the burner to less than 5 percent at the lower ports. Finally, Figure
11 is a plot of the range of temperatures versus residence time observed while
firing propane with the axial burner. The hottest temperatures observed were
while operating at an SR of 1.05 with sorbent air Injected at the burner, while
the coolest were at an SR of 1.25 with downstream sorbent air injection. These
temperatures vary only from 13 to 6 percent; again, the temperatures converge as
the distance from the burner Increases.
CONCLUSIONS
From the data presented in the preceding sections, the following conclusions
can be made.
• The original length of the furnace (Phase I) was not adequate to pro-
vide for a wide enough range of temperature/residence times for flexi-
bility in testing limestone Injection.
• Increasing the furnace length and operating at a firing rate of 47,300
Btu/hr (14 kW) [3.5 lb/h (0.44 g/s) coal] gives adequate residence
times and temperature profiles for limestone Injection testing.
• Lowering the stoichiometric ratio (excess air) produced the expected
longer residence time. At lower air settings, the initial temperatures
were hotter, while the bottom ports showed temperatures cooler than at
a higher air setting. As can be seen from Figures 7 and 8, the temper-
ature variations for the three excess air settings were small. The
largest range of 200*F (93*C) occurred at the top port nearest the
burner. In fact, the average temperature variation for propane (ex-
cluding the top two ports) is 63*F (18#C) while the average for coal
1s only 70*F (21*C). Therefore the SR can be assumed to have little
effect on the temperature profile for this furnace when the entire vol-
ume of combustion air is mixed at the burner.
• The temperature profiles measured while burning coal and propane at
the same Btu firing rate and SR also fall 1n a narrow range. The tem-
peratures do not vary by more than 4 percent—except for one measure-
ment at an SR of 1.05 at the point nearest the burner.
• The temperature profiles observed between different burner designs
(axial vs. radial) were also very small, less than 5 percent, when
all air is mixed at the burner. Temperature variation between burners
was slightly higher when the sorbent air was added downstream of the
burner—with the radial burner's temperatures being 6 to 13 percent
cooler.
47-7
-------
REFERENCES
1. 3abcodc and Wilcox, 1973. Steam/Its Generation and Use.
2. Benedict, R. P., 1977. Fundamentals of Temperature. Pressure, and
Flow Measurements. John Wiley & Sons, Ne* York.
3. EPA, Standards of Performance for New Sources: Revision to Reference
Methods 1-8, Federal Register 42(160), 41776-41782, 1977.
47-8
-------
Type I
TtMonocmiplM
ItMfmocMipta I -
Thetmocoupl# 2 •
WwmiMaupIc 4 -
(A) Old Furnace
Confiyuiatioa
rud
\ /
¦iMMf
Thcfmocouples
w
nr
TX
w
•i*
ir
ir
«r
nr
Z3 iMftiftrtl
3
3 tMrbftri)
J hofitMl
(•) After Addition of
New Settwm
Ml
Figure 1. Diagram of UHB furnace showing location of
Type B thermcouples and sampling ports.
-------
Ceramic
Wm c Support
/
Thermocouple
i
Sample to
Dry G» Meter
1
Water
Outlet
D
\
Outer
Shield M,,eW
Sample
Inlet
r
Water
Inlet
Figure 2. Cross section of water cooled suction pyroneter.
-------
2
ui
I-
, 1 1 1 1 1—
5000 10000 15000 20000 25000 30000
MASS FLOW ACROSS THERMOCOUPLE JUNCTION, lb/ft1 hr
Figure 3. Effect of gas Mass velocity on pleasured temperature.
-------
3000-
2600-
5 2400-
Hi
t-
2000-
IB00-
1600-
1.0
oc
04
02
RESIDENCE TIME, mcm*
Figure 4. Teaperature us. rest deuce tiae under Huse I it a
propane firing rale of 67,500 Stu/br (5.0 lb/kr coal).
2700
2600
2600
2400
2300
tt.
Ml
5
P 2200
<
m
i
£ 2100
2000
taoo
1800
1700
& 26% Exw Am and New Bottom
SkUm ot funnel Added
O 2ltiicniAii
1 1 1 1 1 1 r~
02 0.4 0« 00 1.0 1.2 1.4
fttSIOENCE TIME. »«c—to
Figure S. Teaperature »». residence tlae under Flute I 4t a
propane firing rate of «.J00 Btu/hr JJ.S lb/hr coal).
-------
figure fc. leaperature vs. residence tine ill firing rile of
C/.SOO Btu/hr prnp-tne *nd SR of I.IS.
MM.
S
*
i
r
¦ *
i
• at
—r~
••
—r~
i*
~T~
I*
~T~
• •
li
It
~T~
)•
r
RESIDENCE TIME. Mcamto
figure 7. Temperature »s. residence ttae profiles at a firing rate
of 47,300 Btu/hr propane.
-------
A IHwmim
• h«mu«m
VI
I
IM-
3 tom-
<
e
m
m.
5
• A
• *
1M-
r
ii
T"
l«
-7~
It
—T"
—r
i*
t
i*
¦
ii
RESIDENCE TIME.
figure 0. le*per*tore n. res i dene a llat profile buriilftg J.S Vk'ht
coil |<1.300 Itu/hr).
tm -i
O if —
• • »m >
-------
!¦»»¦ w% H "Hiwt *»—»
O le*e*« •• *mw« ei
r**t H.WI >l>* pnni
UN
-^1
*
m
3
I-
<
2
J- .«•
a
o
o
—, 1 1 1 r~
•• *• ii
RESIOINCE HME.
figure- 18. Effect of adding tarkMt air doMStrtM of the
axial burner at an SO of 1.05.
vm
o
o w»*m ¦oOwfot—
ttvtfc •**•««
M i^Kta4 it lowt' pan
tm
c
3
5
s
i
* o
tIM
¦KM
~T~
II
T-
«•
li
RESIDENCE TIME, Mean*
Figure II. Tnferitwt range for axlil burner firing at a
rate of 47,100 Stu/hr of propane.
-------
Table 1
SUCTION PYROMETER DATA CONOUCTED IN THE LIMB FURNACE UNDER PHASE I
67,500 Btu/hr
SR* 1.10
10/19-10/24/83
67,500 Btu/hr
SR 1.10
11/1/83
47,300 Btu/hr
SR 1.25
11/8/83
01stance Fran
Burner
(Inches)
ST
Cumulative
Residence
Time
(sec.)
Tern.
(*F)
Cumulative
Residence
Time
(sec.)
ft?"
Cumulative
Residence
Time
(sec.)
17
3,060
0.167
2,908
0.174
2,604
0.268
29
2,880
0.288
2,713
0.300
2,374
0.468
43
2,660
0.438
2,565
0.456
2,264
0.711
78
2,250
0.854
2,127
1.00
1,497
1.398
47,300 Btu/hr
SR 1.2S
1/23/84
~~ Cumulative
Residence
Temp, Time
(*FI (sec.)
2,694 0.300
2,489 0.489
2,293 0.725
1,937 1.325
* SR « Stoichiometric ratio of conbustlon air to fuel
-------
Table 2
SUCTION PYROMETER TESTS BURNING PROPANE AT 47,300 BTU/H* USING THE RADIAL BURNER
SR of 1.1S
3/1/84
SR of 1.25
3/2/84
SR of 1.0S
3/5/64
SR of 1.25
3/6/84
Distance Fro*
Burner
(Inches)
ft"
emulative
Residence
T1«e
(sec.)
Tenp.
m
CiMulatlve
Residence
Tiae
(sec.)
Temp.
CD
Cumulative
Residence
Tiae
(sec.)
Tenp.
CF)
Cumulative
Residence
Time
(sec.)
17
2,574
0.29
2,503
0.277
2,709
0.303
2,538
0.273
29
2,336
0.505
2,370
0.477
2,510
0.524
2,404
0.470
41
2,264
0.732
2,251
0.686
2,376
0.758
2,287
0.676
57
2,104
1.048
2,080
0.980
2,137
1.091
2,089
0.967
66
1,982
1.236
1,994
1.193
2,036
1.291
2,006
1.140
80
1,849
1.543
1,861
1.476
1,850
1.620
1,864
1.421
116
1,500
2,423
1,566
2.276
1,535
2.565
1,564
2.218
136
1,397
2.97
1,435
2.768
1,373
3.156
1,464
2.706
* Equivalent to 3.5 Ib/h coal
-------
Table 3
SUCTION PYROMETER TESTS BURNING 3.5 LB/tt COAL* USING THE RADIAL BURNER
Distance Fro*
Burner
(Inches)
17
29
41
57
66
80
100
116
136
*177300 Btu/h
SR of 1.2S
3/16/84
ST
CiNulatlve
Residence
Tine
(sec.)
2,492
0.30
2,370
0.52
2,260
0,74
2,138
1.05
2,052
1.23
1,933
1.59
1,731
1.97
1,605
2.36
1,451
2.88
SR of 1.0S
3/19/84
Teap.
m
emulative
Residence
Tine
(sec.)
2,457
0.35
2,420
0.60
2,302
0.86
2,139
1.22
2,030
1.43
1,877
1.78
1,648
2.32
1,474
2.80
1,363
3.44
SR of 1.15
3/20/84
Temp.
(•f)
Cunulatlve
Residence
Tine
(sec.)
2,563
0.31
2,390
0.54
2,221
0.78
2,087
1.12
1,966
1.32
1,858
1.65
1,646
2.15
1,476
2.59
1,376
3.18
-------
Table 4
SUCTION PYROMETER TESTS COMPARING BURNER DESIGN AND THE EFFECT
OF ADDING SORBENT INJECTION AIR DOWNSTREAM OF BURNER
Radial Burner, 7/5/84
Sorbent Air Sorbent Air
Axial Burner, 7/3/84
Sorbent Air Sorbent Air
•t Burner
Downs treaM of Burner
Downstream of Burner
at Burner
Distance
Fro®
Burner
(Inches)
Temp.
m
Cumulative
Residence
Tlae
(sec.)
ST
emulative
Residence
Time
(sec.)
13-
Cumulative
Residence
Time
(sec.)
temp.
CF)
Cumulative
Residence
Time
(sec.)
29
2,404
0.470
2,400
0.448
2,515
0.471
41
2,287
0.676
2,103
0.662
2,160
0.763
2,402
0.669
57
2,069
0.967
1,955
0.946
2,037
1.065
2,230
0.947
66
2,006
1.140
1,882
1.128
1,951
1.242
2,098
1.113
80
1,864
1.421
1,780
1.423
1,820
1.530
1,961
1.423
100
-
-
1,635
1.869
1,662
1.969
1,741
1.841
116
1,564
2.218
1,480
2.219
1,488
2.349
1,565
2.206
136
1,464
2.706
1,352
2.727
1,395
2.857
1,425
2.653
Quench Rate
» 467*F/sec
Quench Rate
- 492#F/sec
Quench Rate
= 4171/sec
Quench Rate
= 533'F/sec
All data for an SR of 1.25, and firing propane at 47,250 Btu/hr
-------
APPENDIX A
SAMPLE CALCULATIONS
1.. The following calculations are for the data collected on January 23, 1984,
while performing suction pyrometer testing on the LIMB furnace.
DATA
Propane flow rate - 0.36 cfta 9 0.5 ps1
Tangential air flow - 4.5 cfm 8 45 ps1
Pilot air flow - 50.0 cfh 0 15 ps1
COa - 10.64%
0? - 4.325S (concentrations are measured on a dry basis)
CO - 0
Using radial burner
A. Computing actual scfm of propane burned
Actual scfm
of propane • 0.868 x rotometer x pressure * 0.024
burned setting correction
. /l4.7 + 0.5 + 0.(
\J 1777—
(0.868 x 0.36) x , /14.7 + 0.5 + 0.024
0.34 scfm
8tu/hr * 0.34 scf x 2322 Btu x 60 m1n. • 47.368 8tu/hr
ITn. sc? Rr—
B. Total volume of air metered Into burner
Tangential a1r • rotometer setting x pressure correction
, /14.7 + 45
- 4.5 xV —nrr-
« 9.0 scfta
Pilot air » rotometer x pressure x hr
setting correction 5Qmln.
\/4.7 + 15
(V—[T7T-
1
50 cfh xV [TT~ x SB"
« 1.18 scfm
Total air
Tangential ¦ 9.00
Pilot « 1.18
16.18 scfm
02 - 0.21 x 10.18 » 2.14 scfm
N2 • 0.79 x 10.18 * 8.04 scfm
47-20
-------
Excess air calculations
Theoretical air required • 23.82 cubic feet air x actual scfm
at OS excess cubic feet of propane propane burned
» 23.82 x 0.34 « 8.1 scfm of air
Excess Air from Rotometers Excess Air from Monitors
Rotometers • 10.18 scfm 0? ¦ 4.375S
Theoretical ¦ 8.1 scfta C&2 * 10.64*
1 Excess ¦ 10.18 » 1.257
air 8.1
• 25.71
Theoretical O2 * 8.1 x 0.21 » 1.7
at 0% EA
02 metered in * 2.14 scfm
theoretical » 1.7
excess 02 • u.44 scfm
Total Volume of Flue Products
C02 ¦ 3.0 ft3
ftJ of propane burned
% Excess air • 23.6%
h2o
4.0 ft3
ft-* of propane burned
Total Volume of Flue Gases
CO2 " 3.0 x 0.34 * 1.02
H26 * 4.0 x 0.34 • 1.36
N2 * (from B) ¦ 8.04
Excess O2 • (from C) ¦ 0.44
10.86
47-21
-------
Residence Time
Area of furnace « *r2
¦ ir (3/12)2
» 0.196 ft2
1. Residence time from burner to Port 1, T * 2694*F
and L » 17 inches or 1.4-2 ft
Velocity ¦ total scfm x temperature x 1 x m1n
correction area 60 sec
- 10.79 x 2694 + 460 x 1 x 1 ¦ 5.46 ft/s
70 ~ 450 OT SET
Residence time * 1.42 ft x 1 « 0.26 sec
5.45 ftysec
2. Residence time from Port 1 (T » 2694*F) to Port 2 (T « 2489*
Average T between ports ¦ 2592-F
Distance ¦ 12 Inches or 1 ft
Velocity « 10.79 x 2592 + 460 x 1 x 1 • 5.28 ft/sec
70 + 450 7095" OT
Residence time « 1 ft x 1 ¦ 0.189 sec
5.28 ft/sec
3. Residence time from Port 2 (T * 2489#F) to Port 3 (2293*F5
Average T » 2391
Olstance » 14 inches or 1.17 ft
Velocity » 10.79 x 2391 + 460 x 1 x 1 « 4.94 ft/sec
70 ~ 450 Of
Residence time ¦ 1.17 ft x 1 ¦ 0.237 sec
4.94 ft/sec
4. Residence time from Port 3 (2293*F) to Port 4 (1937)
Average T ¦ 2115
Distance • 35 Inches or 2.92 ft
Velocity « 10.79 x 2115 + 460 x 1 x 1 » 4.46 ft/sec
70 ~ 450 09S TO
Residence time ¦ 2.92 ft x 1 « 0.655 sec
4.46 ft/sec
47-22
-------
APPENDIX B
SUCTION PYROMETER CURVES OF TEMPERATURE VERSUS MASS FLOW RATE
The following figures are the temperature versus mass flow rate curves de-
veloped for the suction pyrometer used In testing the LIMB furnace. Curves
were developed at each sampling port. All tests were conducted at the fol-
lowing conditions:
Firing Rate ¦ 67,500 Btu/hr propane
Excess A1r » 105
Inner diameter of the shield ¦ 1/2-Inch
Outer diameter of the sheath * 3/8-Inch
The following conversion was used to convert the scfra measured at the dry
gas meter to units of lb/hr ftz of mass flow over the thermocouple
junction:
scfm at * moles x Tb x m1n x 1
dry gas meter scf mole "RF* area between inner
and outer ceramics
l 0 fm x mol es x 29 1 b x 60 m1n * 1
38/scf mole hr {0.15 in* - 0.11 Ml ft?
Win?
1 scfm at
dry gas meter ¦ 7,598 lb/ft? hr
47-23
-------
3200
T" 3015
3100
O 10/71
O 10/24
# 11/1 (ln«j)»iion Add*d)
2 2800
<
S 2700
S 2600
T- 2430'P
I
lA Pin*» T rrwiturt
-!-T« 2402 *?
(Insulation Add*01
2300
4000
12000
18000 20000 24000 28000 32000
aooo
MASS HOW. lb ff hr
Figure 8-1. Results of tests at Port Mo. 1—17 inches from burner.
T-2880 F
(No Imulwon)
2800
| 2500
Rtn*i Temperature
2300
2200
12000 16000 20000 24000
MASS PLOW, lb H* hr
4000
8000
32000
28000
Figure B-2. Results of tests at Port No. 2—29 Inches from burner.
47-24
-------
2800
T* 2660 "F
(No Invitation)
2600
3300
•& Ptn«4 Ttmpcratur*
12000 16000 20000 24000 28000 33000 36000
MASS PLOW, tb ff hr
8000
4000
Figure B-3. Results of tests at Port Mo. 3—43 Inches from burner.
2300
2300
it
9
2000
I m»
ut
1800
Tamotratur*
T- 1667*P
1600
38000 33000
8000
4000
MASS FLOW, lb If Hr
Figure 3-4. Penults of tests at Port No. 4—73 Inches from burner.
47-25
-------
(Unpresented Paper)
SURFACE CHARACTERIZATION AND MICROANALYSIS OF SORBENTS
AND ASH/SORBENT MIXTURES
Robert S. Dahlin
Southern Research Institute
2000 Ninth Avenue South
Birmingham, AL 35255-5305
and
David A. Klrchgessner
Industrial Environmental Research Laboratory
US Environmental Protection Agency
Research Triangle Park, NC 27711
ABSTRACT
This paper presents a survey of techniques for the surface characterization and
microanalysis of particulate samples related to EPA's Limestone Injection Multistage
Burner (LIMB) program. The following techniques are discussed: scanning electron
microscopy (SEM), carbon replica transmission electron microscopy (TEM), thin sec-
tion TEM, energy dispersive X-ray (EDX) analysis, electron microprobe analysis
(EMA), electron spectroscopy for chemical analysis (ESCA), and Auger electron spec-
troscopy (AES). Example applications of these techniques to various LIMB samples
are presented, and the limitations of the techniques are discussed.
SEM was found to be particularly useful in elucidating the surface morphology of
calcines and sulfated calcines. In several photomicrographs, the pore openings In
the calcines appeared to be slit-like and the calcination appeared to be direction-
ally controlled. Carbon replica TEM was found to be tedious and unwarranted in view
of the success with SEM. Thin section TEM may be useful In elucidating Internal
particle structure if a nondestructive sectioning technique can be developed.
EDX in conjunction with SEM was found to be quite useful 1n Investigating the rela-
tive abundance of various elements In different samples as well as the distribution
of a given element within a field of particles. The electron microprobe was useful
for studying variations 1n elemental intensities 1n the top 4-5 um of a 20-um region
of a sample. Due to poor spatial resolution, ESCA was found to be unsuitable for
heterogeneous particulate mixtures. Elemental depth profiles in Individual parti-
cles can be determined by AES coupled with ion milling. The results, however are
very sensitive to particle charging effects and particle topography.
48-1
-------
SURFACE CHARACTERIZATION AND MICROANALYSIS OF SORBENTS
AND ASH/S0R8E.NT MIXTURES
INTRODUCTION
Program Needs
The developmental stage of EPA's LIMB (Limestone Injection Multistage Burner) pro-
gram includes the need for a variety of analytical techniques applicable to the
process inputs and products. While methods for bul'< quantitative elemental analy-
sis, mineral identification, and gross physical characterization are generally
availadle and appear to be appropriate for LIMB materials, the applicability of
microanalytical techniques to the assessment of particle composition and structure
is far less certain. Particles in the micron size range and structures in the sub-
micron range are frequently of interest. The three LIMB process considerations
which provided the principal foci for this survey of analytical techniques are:
a) high surface area sorbents; b) ash/sorbent interaction products; and c) sulfation
products.
Recently, it has been recognized that the LIMB process may be made more efficient by
injecting precaldned sorbents downstream from the coal burner. This is 1n sharp
contrast to the original concept of the process which involved the Injection of
limestone through the burner. These externally produced sorbents may consist of
calcines, hydrates, pressure hydrates, or chemically enhanced forms of these mate-
rials. The kinetic information presently available on the sulfation stage of the
process suggests that these materials should have high surface areas to enhance
sulfur capture (1). It suggests further that this surface area, to the extent that
it is concentrated in the Internal porosity of the sorbent particles, must be dis-
tributed among the coarser pore sizes to retard blockage by reaction products.
The nitrogen adsorption technique employed 1n BET (Brunauer, Emmett, and Teller)
analysis can determine surface area directly while multipoint BET analysis will
permit the derivation of pore volume and rad11. Similarly, mercury porosimetry
analysis will measure pore volume directly, with surface area and pore size being
derived values. The accuracy of these derivations rely on a set of assumptions, one
of which is that the pores involved are cylindrical 1n shape. To investigate the
validity of this assumption and the resulting analyses, It is desirable to identify
a technique by which the pores of sorbent particles can be directly observed.
The second recent development which has provided incentive for this study is the
realization that certain elemental and/or mineralogic components of the mineral
matter contained in the coal fuel can either enhance or retard the ability of
sorbents to capture sulfur during the combustion process. Different types of
sorbents appear to be affected to varying degrees by this interaction. Principal
mechanisms hypothesized for the interaction include vaporization/condensation and
collision/adhesion. Although speculation and theory have been marshalled by
proponents of both views, no compelling empirical evidence has been put forth.
Since the interaction phenomenon can determine the efficacy of the LIMB process, the
mechanism and components involved must be identified. At least three different
48-2
-------
types of microanalytical procedures appear to be applicable to this area: 1) one
which will allow visualization of the structure and relative proportions of differ-
ent types of particles; 2) one which will permit whole particle elemental analysis;
and 3) one designed for depth-profile or cross-sectional elemental analysis of
individual particles.
The third area to derive a potential benefit from this survey is the study of sul-
fated products from the LIMB process. Efforts are currently being directed toward
the development of models to simulate the mechanism of sulfation. Interpretation of
experimental evidence supporting this model development suggests that the sulfation
reaction is controlled by diffusion of S02 through the product layer created on the
sorbent (2). Presently, however, not all aspects of the various models are in
agreement, nor are results from furnace experiments always adequately predicted by
the models. To assist 1n the resolution of these disparities, 1t seems reasonable
to employ visualization techniques to determine if closure or restriction of pores
by product layers is actually occurring. A similar purpose might be achieved by
measuring elemental depth profiles or cross sections of Individual sulfated sorbent
particles.
Study Objectives and Scope
The objective was to identify a set of microanalytical techniques which, when
employed within the framework of a well-designed sampling and experimental plan,
would be appropriate for application to the materials involved in the three process
areas described above. In and of itself the study was not designed to resolve these
problems.
Specifically, the survey was to identify: 1) visualization techniques capable of
accurately portraying particle morphology and structures down to the submicron size
range; 2) methods of elemental identification and quantification in whole particles
down to a few microns in size; 3) methods of quantifying elemental content in depth
profiles or cross sections of particles down to a few microns 1n size; and 4) the
sample preparation techniques accompanying these analylcal methods appropriate for
application to LIMB-related materials. Excluded from the survey were bulk elemental
quantification analyses, mineral Identification methods, and techniques for gross
physical characterization. Also excluded were surface area, pore volume, and pore
size analyses. The available BET and mercury poroslmetry techniques are believed to
have been adequately tested for accuracy and precision through the analysis of stan-
dards, and intralaboratory and inter!aboratory comparisons.
VISUALIZATION TECHNIQUES
Scanning Electron Microscopy
Scanning electron microscopy (SEM) may be used to study the size, shape, and surface
morphology of LIMB-related samples. The size and shape of the particles can gener-
ally be studied using any production-grade SEM that is in good operating condition.
However, a research-grade SEM that 1s capable of high resolution (-30 A}* 1s
required for study of some of the intricate surface features of LIMB particles.
Soth types of SEM's have been used in this study. The production-grade Instrument
was an ETEC Autoscan automatic scanning electron microscope. The manufacturer's
maximum resolution is about 200 A, which limits the maximum useful magnification to
about 20,000X when a good specimen 1s imaged. The research-grade Instrument used in
*10,000 A > 1 um.
48-3
-------
this study was a Camscan Series 4 SEM. This instrument has a maximum resolution of
about 30 which limits the maximum useful magnification to approximately
120.000X.
For morphological studies of the particulate surface, exposure of the sample to the
atmosphere must be minimized. The surface morphology of LIMB sorbent particles can
be drastically altered by the pickup of H20 and C0? from ambient air. These effects
have been'strongly suspected during recent examinations of hydrated lime particles
and calcines produced therefrom.
A variety of techniques may be employed to prepare particulate samples for SEM exam-
ination (3). The prime considerations are: (a) to make the particles electrically
conductive so that particle charging effects will not interfere with the examina-
tion; and (b) to avoid obscuring any of the surface details of the particles. Of
course, the latter consideration is important only when the objective is to study
the detailed surface morphology as opposed to the general size and shape of the
particles. In order to make the particles conductive, they may be pressed Into a
metal foil or coated with a thin layer of carbon or a metal (e.g., gold, platinum/
paladium, or silver). For high-resolution work, a thin (<20 A) gold coating has
been found to yield good results. The use of gold can be a problem, however, 1f the
sample that is being Imaged is to be simultaneously analyzed by an energy dispersive
X-ray (EDX) attachment on the SEM. Gold interferes with sulfur 1n the EDX spectrum.
Therefore, a gold coating should not be used when planning to analyze sulfated
sorbent samples by EDX. A silver coating was used for most of the EDX work
performed in this study.
In this study, the SEM was used to examine a number of different UMB-related sam-
ples Including:
(1) 3-5-cm hand samples of raw limestone rocks,
(2) limestone powders produced by crushing and pulverizing the rock,
(3) specific size fractions of powders produced in (2), above,
(4) calcines produced from the powders by heating in a controlled labora-
tory environment,
(5) a calcine produced by Injection of a pulverized limestone into the
burner of a natural-gas-fired furnace,
(6) a sulfated calcine produced under the same conditions as (5), above,
except that the natural gas was doped with S02,
(7) an ash/sulfated calcine mixture produced under the same conditions as
(5), above, except that the fuel was a medium (2%) sulfur coal
instead of S02-doped gas,
(3) a hydrated lime—Ca(0H)2—produced from one of the limestones in (2),
above,
(9) a calcine and a sulfated calcine produced from the hydrated lime by
downstream Injection into a natural-gas-fired combustor with and
without S02 doping,
(10) an ash/sulfated calcine mixture produced by downstream injection of
the hydrated lime while firing the same coal used in (7), above, and
(11) reagent-grade calcite calcined und'er laboratory-scale conditions.
48-4
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Samples (l)-(4) and (8)-(ll), above, were examined on the Camscan research-grade
SEM, while Samples (5)-(7), above, were examined on the ETEC production-grade SEM.
The same two limestones were used as the source materials for samples (l)-(4),
above. The compositions of these two limestones are summarized in Table 1. The
Longview limestone was supplied by Southern Industries, Inc., from their quarry
located .in Saginaw, Alabama, just south of Birmingham. The Maysville limestone was
supplied by Dravo Lime Company from their quan-y in Maysville, Kentucky, just south
of Cincinnati, Ohio. A hand specimen of the Longview stone is gray-white in color,
while the Maysville stone is pale-tan-to-buff colored with 0.8- to 3-mm thick bands
of widely spaced dark brown material. Petrographic examinations show that the grain
sizes range from 100 to 830 um 1n the Longview stone, while most of the Maysville
stone consists of microcrystalline calclte with an average grain size of 3 um. The
Maysville stone also contains sparfte grains (-20 um mean size) as well as dolomite
rhombs (-50 um mean size). A significant number of fossil fragments were found in
the Maysville stone; whereas, the Longview stone was free of fossil fragments. The
chemical analyses given in Table 1 show that the Maysville stone is significantly
higher in dolomite content than the Longview stone. This was also indicated by
X-ray diffraction analyses that showed only a trace (<3X) of dolomite in the
Longview stone and a minor amount (3-10%) in the Maysville stone.
The two limestones described above were of interest in this study because calcines
prepared from the same size fractions of the two crushed limestones under the same
conditions had markedly different BET surface areas. For example, a 63- to 38-um
size fraction of the crushed Longview limestone yielded a calcine with a BET surface
area of 51.2 m2/g, while the same size fraction of the crushed Maysville stone
yielded a calcine with a BET surface area of 39.8 m*/g. These calcines were pre-
pared by heating the limestone powder at 750°C for 30 m1n. The powder was dispersed
on quartz wool and heated over flowing nitrogen. The raw stones, their powders, and
their calcines were examined by SEM in an effort to identify any differences that
mi3ht help explain the difference 1n BET surface areas. Photomicrographs of these
materials are shown in Figures 1-6. Due to space limitations, only one of the size
fractions (53-33 um) of the crushed material is shown here, together with the corre-
sponding calcine produced from the powder.
Figures 1 and 4 show that both the Longview and Maysville stone chips have a rough
surface texture with many small (<10 um) fragments adhering to the surface. An
apparent grain boundary may be seen in the 2000X photograph of the Longview stone.
The crushed powders, shown 1n Figures 2 and 5, consist of numerous particles that
appear to be too large (>88 um) along one axis, but about the right size (63-88 um)
along the other axis. This suggests that the particles were aligned with their
major axes perpendicular to the sieve when the size cut was prepared. The net
effect 1s particles that are larger than expected 1n one direction. The photomicro-
graphs of the calcines produced from these powders (Figures 3 and 6) reveal the
apparent production of cracks and fissures 1n the particle surface. Some of these
cracks and fissures appear to be as large as 1 um. However, there may be many other
such features that are too small to see at this magnification. Given the very large
specific surface areas of the calcines (51.2 m2/g for the Longview and 39.8 mJ/g for
the Maysville), it is clear that these materials must have considerable Internal
porosity that is accessible from the particle exterior. This is confirmed qualita-
tively 1n Figures 3 and 6. The purpose of Figures 1-6 is simply to illustrate the
types of results that can be obtained by SEM. No serious attempt has been made to
relate these results to any physical or chemical characteristics of the materials.
The photomicrographs discussed above were taken at relatively low magnifications
(100X and 2000X). Such low magnifications are often adequate for studying the size
and shape of particles or their general surface features; however, much higher
magnifications are required to elucidate some of the intricacies in the surface
48-5
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morphology of calcines. This is Illustrated in Figure 7 which shows two SEM photo-
micrographs of a calcine produced by heating reagent-grade calcite at 725°C for
30 min. The calcite particles were dispersed on quartz wool and heated over flowing
nitrogen. This produced a calcine with a BET surface area of 27.6 m2/g. The SEM
photomicrographs of this material shown in Figure 7 reveal a surface morphology that
is similar to that of ground beef. The surface is covered with creases or crevices
that appear to be the openings of slits which penetrate below the particle surface.
There is also an indication that the calcination is controlled directionally by twin
planes within the crystal structure.
Figure 3 shows two other SEM photomicrographs of the same material shown in
Figure 7. These two additional photographs are shown to illustrate the directional
nature of the calcination process that 1s suggested by the surface morphology. They
also tend to accentuate the fissure-lilce nature of the pore structure.
The SEM was also used to examine particles of hydrated lime—Ca(0H)2—and the
various calcination and sulfation products of this material. The following samples
were examined:
(1) Commercial hydrated lime—Ca( OH) 2—made from the Longvlew limestone
described previously.
(2) Calcine—CaO—produced by injecting the above Into a natural-gas-
fired furnace at about 1200°C with no S02 present.
(3) Sulfated calcine—CaSO^/CaO—produced by injecting the hydrated lime
at the same location but with the natural gas doped with 2190 ppm of
S02.
(4) Sulfated calc1ne/ash mixture produced by injecting the hydrated Hme
at the same location but with Indiana 2% sulfur coal being fired.
SEM photomicrographs of these materials are shown in Figures 9-12. A comparison of
Figures 9 and 10 reveals a pronounced change in the surface morphology due to cal-
cination. Numerous openings are evident on the calcine surface which were not pres-
ent in the raw material. In the 38.000X photograph of the calcine, there appear to
be "holes" that are on the order of 400-1000 A 1n size. Slits as small as 200 A in
width can also be resolved. The sulfated calcine particles shown tn Figure 11
appear to be quite similar to the calcine particles before sulfation. In the fly
ash/sulfated calcine mixture, some fly ash particles can be seen that appear to be
coated with smaller sorbent or ash fragments as evident at 40.000X in Figure 12.
Transmission Electron Microscopy
The transmission electron microscope (TEM) may also be used to study the surface
morphology of particles using a process called carbon replication (4). The proce-
dure for preparing a carbon replica may be outlined as follows: (a) the particles
in the sample are dusted onto a copper TEM grid that has been coated with a sticky,
plastic-like Formvar film; (b) the particles are coated with a thin film of carbon
in an evaporative coater; (c) the carbon coating 1s "shadowed" by deposition of a
heavy metal (e.g., platinum/paladlum) at an angle of about 10°; (d) the Formvar is
dissolved and carried away by partially immersing the TEM grid 1n a shallow pool of
chloroform; (e) the particles are dissolved and carried away by partially immersing
the TEM grid in a shallow pool of dilute hydrochloric acid. This procedure leaves
behind a thin carbon shell that is a precise replica of the original particle sur-
face. The shadowing effect of the heavy metal emphasizes the surface features.
Thus, the shadowed replica provides a "relief map" of the particle surface. While
48-6
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the use of carbon replica TEM offers the potential for detailed studies of surface
morphology, practical problems make it difficult to consistently produce reliable
carbon replicas. It was often difficult or impossible to completely dissolve the
particles under the carbon coating. If the particles were completely dissolved, the
carbon replica would frequently collapse because it was either too thin or because
it spanned an unsupported area that was too large. With considerable care, however,
it was found that good carbon replicas could be produced. Two such replicas are
shown in Figure 13. These are replicas of calcine particles produced by heating
reagent-grade calcite at 850°C for 30 min. The calcite particles were dispersed on
quartz wool and heated in a static air environment. The calcine had a BET surface
area of 18.7 m2/g. The replicas of this material reveal numerous structural
features on the particle surface that may account for some of the measured surface
area, although the apparent porosity shown by the SEM photos is not clearly distin-
guishable.
The TEM may also be used to examine the internal structure of particles using a
procedure called "thin sectioning" (5). A thin section of a particle may be pre-
pared by the following procedure: (a) the particles are suspended 1n a liquid epoxy
resin that contains a hardening accelerator; (b) the epoxy is allowed to harden and
encase the particles; and (c) a microtome is used to prepare a thin section of the
hardened epoxy. A thin section prepared in this manner will contain numerous thin
sections of particles trapped within the hardened epoxy. The particle thin sections
may represent wily the tip of some particles and the center of other particles,
depending on where the microtome happens to penetrate each individual particle. A
particle thin section that represents a region near the center of the particle
should contain a cross section of the structure inside the particle. In viewing
such a thin section under the TEH, the solid areas appear black and the open areas
associated with internal porosity or "pores" appear white. Thus, it is possible to
obtain a cross-sectional view of the internal structure of the particl'e. Photo-
micrographs of these cross sections can, 1n principal, be used to gain qualitative
information concerning the nature of the internal porosity, the relative amount of
porosity, and the size of the pores. The thin sectioning procedure was attempted
with a calcine produced by injecting Vicron limestone (>97% calcium carbonate)
through the burner of a pilot-scale gas-f1red combustor. Numerous attempts with
various epoxy resins proved fruitless because the microtome could not be forced
through the calcine particles without shattering them into many small fragments.
The resulting fragmentation 1s illustrated in Figure 14. These fragments represent
the remains of part of a calcine particle that was estimated to be roughly 10-20 um
in size originally. It is apparent that the thin section TEM procedure can be use-
ful only if a nondestructive method can be devised for preparing the thin sections.
This may be possible by cutting thicker sections and then milling them down using an
ion beam.
MEASUREMENT TECHNIQUES
Energy Dispersive X-Ray (EDX) Analysis
Energy dispersive X-ray (EDX) analysis (6) can be used in conjunction with SEM to
study the chemical composition of a small area (roughly 1 um x 1 um) within a field
of particles. A beam of electrons is focused on the area of Interest and this pro-
duces a spectrum of X-rays which are analyzed with respect to their intensities and
wavelengths. The results are displayed as a spectrum of relative intensity, which
is indirectly related to elemental concentration, as a function of the energy (keV)
associated with the X-ray emissions from a given element. Thus, the location of a
given peak in the spectrum identifies the element, and the peak height, after
correction for that element, determines its relative abundance In the area analyzed.
Figure 15 shows an example of two EDX spectra obtained on different areas of a fly
ash/sulfated calcine mixture. Spectrum 28 suggests that the -7-um sphere in the top
48-7
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canter is a fly ash particle, while Spectrum 29 shows that the mass in the lower
left corner is mostly sorbent material. This illustrates how EDX can be used with
SEM to identify various particle types and investigate their relative compositions.
EDX can also be used to "map out" the areas in which a given element is concentrated
within a given field of view, In this mode of operation, a microcomputer averages
the "signals" received from various portions of the field of view over a period of
time, and then displays the time-averaged result as a "dot map" of intensity as a
function of location for a given element. This allows the operator to spot regions
in which an element of interest is concentrated. The result of this procedure is
illustrated in Figure 16, which shows the "dot maps" obtained for calcium, sulfur,
and aluminum in a fly ash/sulfated calcine mixture. In this case, these maps show
that the irregular particles in the lower portion of the SEM photo are sorbent
particles while the smooth, spherical particles are fly ash.
Electron Microprobe Analysis
In electron microprobe analysis (EMA) a small area of the field of view is bombarded
with a focused beam of electrons that is about 1 um in diameter. This causes the
sample area being analyzed to emit X-rays that are analyzed in terms of their
diffraction by a known crystal lattice in the detector. The emitted X-rays emanate
from as deep as 4-5 um beneath the surface being analyzed (7). Therefore, the
result is an average composition for the top 4-5 um of the analysis area. The
electron microprobe is normally used in a scanning mode to traverse across an area,
or a single particle, of interest at a programmed rate. A microcomputer is used to
convert the signal from the X-ray crystal analyzer and the programmed scan rate into
a relative intensity profile across the area analyzed. The emitted X-ray signal for
a selected element is monitored during a scan or traverse, and the scan is then
repeated successively for every other element of interest. This results in a saHes
of elemental profiles of the form illustrated in Figure 17. These profiles were
obtained by scanning across a 30-um area of sulfated sorbent material in a fly ash/
sulfated calcine mixture. These profiles suggest more-or-less uniform sulfation
across this particular reckon of the sulfated sorbent material. This apparent uni-
formity may be partially due to the effect of averaging over the top 4-5 um of the
area analyzed.
The results depicted in Figure 17 were obtained on a sample that had been Imbedded
in an epoxy resin. The hardened epoxy was metallographically polished to eliminate
topographical effects in the EMA. The polishing may, however, tend to "smear out"
the material and make it appear more uniform than it actually Is. This could
explain the apparent uniformity illustrated in Figure 17.
Electron Spectroscopy for Chemical Analysis (ESCA)
In the ESCA technique (8) a sample is pressed into a metal foil (e.g., indium) and
irradiated with soft (1.25-1.49 keV) X-rays. Photoelectrons ejected from the core
levels of surface molecules (top 10 4) are analyzed with respect to their kinetic
energy. The binding energy associated with the photoelectron peak is determined
from the X-ray excitation energy, with the binding energy of the core level photo-
electron being characteristic of the atom from which it originated. Chemical bond-
ing information can be deduced by noting the precise positions and shapes of the
ESCA peaks. The technique can be also used in conjunction with ion milling to
obtain depth profile analyses.
The ESCA method typically analyzes an area of approximately 0.5 x 0.5 mn so that its
single-particle capability is limited to material of this size or larger. Alterna-
tively, the technique will provide an.average surface analysis of many smaller
particles when that type of information is satisfactory; although, in light of the
48-8
-------
purposes stated earlier in this paper, the lack of spatial resolution must be
regarded as a shortcoming.
Auger Electron Spectroscopy (AES)
For the .purpose of AES analysis (9), the sample is pressed into a metal (e.g.,
indium) foil and excited by a focused electron beam. A core level electron is
ejected and replaced by an outer shell electron leaving the atom in an excited
state. This excess energy is released by the ejection of a third electron called an
Auger electron, which has an escape depth of about 10 A. The characteristic kinetic
energy of the Auger electrons is then analyzed to determine the relative Intensities
of the elements present. The analysis area for this technique is on the order of
1 um2 so it 1s suitable for single particle analysis of the small particles of
interest in this study. AES, like ESCA, can be used 1n conjunction with ion milling
to provide analyses at varying depths.
Table 2 shows the results of AES analyses performed in conjunction with argon Ion
milling for two samples believed to contain ash/sorbent interaction products and
sulfated sorbent particles. Sample 0280-105 was produced by the burner injection of
Vicron limestone sorbent while firing a 2% sulfur Indiana coal. Sample 0494-2 was
produced by burner Injection of Vicron limestone sorbent and kaolin while firing
with H2S-doped natural gas. Both analyses were produced on single particles approx-
imately 10 urn in size. While sample 0494-2 shows no significant elemental changes
down to 700 A, sample 0280-105 appears to show an increase 1n aluminum and a
decrease in calcium content with depth down to 900 A. For particles in the 10-um
range, analysis depths of 900 A still represent only the outer skin of the material.
Further Billling would be required to determine 1f a true layered structure were
present in the particle. These results do Indicate, however, the potential applica-
bility of this technique to ash/sorbent interaction products.
CONCLUSIONS AMD RECOMMENDATIONS
The results of this study have shown how selected visualization techniques (SEM and
TEM) and selected measurement techniques (EDX, EMA, ESCA, and AES) can be applied to
the characterization of LIMB-related samples. The SEM 1s particularly useful in
elucidating the surface morphology of calcines and sulfated calcines. Surface fea-
tures as small as 100 A 1n size can be studied under a research-grade SEM. This was
confirmed by high-resolution SEM photomicrographs of laboratory calcines that
revealed slits on the order of this size. Information about the directional nature
of the calcination process can also be Inferred from SEM photomicrographs* The use
of carbon replication TEM does not seem warranted 1n view of the good results
obtainable by SEM and the problems associated with the preparation of carbon repli-
cas. Thin section TEM may be a useful method for studying the internal structure of
calcines and sulfated calcines if a nondestructive technique can be developed for
the preparation of the thin sections. Ion milling may be one possible method of
preparing the thin sections.
Energy dispersive X-ray (EDX) analysis may be employed in conjunction with SEM to
chemically characterize particles or groups of particles observed under the SEM.
The relative abundance of various elements in different samples may be estimated by
comparison of the relative corrected peak heights, and the distribution of a given
element within a field of particles can be determined from "dot maps" prepared by
computerized analysis of the EDX signals. This technique 1s quite useful and easy
to use. Electron mlcroprobe analysis (EMA) can be used to study variations in ele-
mental intensities across a region of a sample. However, it should be noted that
the EMA results represent an average of the top 4-5 um of the sample, so EMA is not
48-9
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appropriate for analysis of very small particles (<20 um). Also, a metallographi-
cally polished section must be used to eliminate topographical effects, and the
polishing can smear out the various chemical components near the polished surface.
Electron spectroscopy for chemical analysis (ESCA) is not appropriate for heteroge-
neous mixtures of fine particles (<500 um) due to the poor spatial resolution. Even
with a chemically homogeneous mixture of different particle sizes, it may be diffi-
cult to interpret the results of ESCA when employed with ion milling for depth pro-
filing. For example, an etch depth of 1000 A would result in an analysis of the
center of a 0.2-um particle and only the top 0.5% of a 20-uffl particle. Thus, the
result may represent a gross average of large particle surface compositions and
small particle bulk compositions. Therefore, depth profiling must be done by the
combination of Auger electron spectroscopy (AES) and ion milling, or by the direct
method of secondary ion mass spectrometry (SIMS). The latter technique was not
addressed in this study but appears to be a more straightforward method for depth
profile analysis since the sputtered ions of the sample are analyzed directly during
the milling process (10). Since AES 1s highly sensitive to particle charging
effects and surface topography 1t is believed that SIMS analysis of individual
particles may offer a better method of determining the depth of sulfur penetration
into sulfated sorbent materials. It may also be useful in studies of ash/sorbent
interaction products.
Some future effort will be directed toward the application of SEM, SEM/EDX, thin
section TEM, and SIMS to the characterization of LIMB particulates. If possible,
the SEM and thin-section TEM results will be related to conventional pore sizing by
mercury intrusion or inert gas adsorption. It may be useful to relate the individ-
ual particle analyses obtained by SIMS to the analyses of larger areas by EDX and to
bulk analyses that are obtainable by a variety of well-established techniques.
ACKNOWLEDGMENTS
The SEM work described in this paper was performed by Margaret Nasta and William
Pingatare of Mellon Institute and Lloyd Carlson of Southern Research Institute. The
carbon replication and thin section TEM work was performed by Rodger Cooney of
Southern Research Institute with the assistance of Frank Denys of the University of
Alabama in Birmingham. The electron mlcroprobe analyses were done by James Johnson
of the Georgia Tech Engineering Experiment Station, and the ESCA and Auger analyses
were performed by Warren Moberly of Surface Science Laboratories, Inc. The labora-
tory calcines examined 1n this study were prepared by Connie Turlington of Northrop
Services, Inc., who was also responsible for the BET surface area measurements.
Merrill Jackson of the Technical Support Office of EPA's IERL-RTP provided
assistance in coordinating the various experimental elements of this study, and
Edward Oismukes of Southern Research Institute offered many helpful comments and
suggestions. This work was funded by the U.S. Environmental Protection Agency under
Contract No. 68-02-3696 and Cooperative Agreement No. CR810012.
REFERENCES
1. R. H. Borgwardt and K. R. Bruce, "Effect of Specific Surface Area on the Reac-
tivity of CaO with S02," EPA/IERL-RTP paper, Research Triangle Park, NC, 1984.
2. R. H. Borgwardt, N. F. Roache, and K. R. Bruce, "Surface Area of Calcium Oxide
and Kinetics of Calcium Sulfide Formation," Environ. Prog.. 3, 129 (1984).
3. P. 3. OeNee, "Collecting, Handling, and Mounting of Particles for SEM," in
Proceedings of the 11th Annual Scanning- Electron Microscopy Symposium, SEM,
Inc., Chicago, IL, 1973, p. 479.
48-10
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4. 0. Kaye, Techniques for Electron Microscopy. 2nd ed., S. A. Davis Co.,
Philadelphia, PA, 1967, Chap. 5, caroon Replication.
5. C. J. Dawes, Biological Techniques for Transmission and Scanning Electron
Microscopy, ladd Research industries, Inc., 1980, Chap. 7, Preparation of Thin
Sections.
5. N. C. Barbl, M. A. Giles, and D. P. Skinner, "Estimating Elemental Concentra-
tions in Small Particles Using X-Ray Analysis 1n the Electron Microscope", in
Proceedings of the 11th Annual Scanning Electron Microscopy Symposium, SEM,
Inc., Chicago, IL, 1978, p. 193.
7. D. R. Beaman and J. A. Isasi, "Electron Beam Microanalysis," ASTM Spec. Tech.
Publ. 506, American Society for Testing and Materials, Philadelphia, PA, 1972.
3. P. K. Ghosh, Introduction to Photoelectron Spectroscopy. Wlley-Intersclence,
New York, NY, L983.
9. J. C. Riviere, "Auger Electron Spectroscopy," Contemo. Phys.. ^4, 513 (1973).
10. N. H. Turner and R. J. Colton, "Surface Analysis: X-Ray Photoelectron Spec-
troscopy, Auger Electron Spectroscopy, and Secondary Ion Mass Spectrometry,"
Anal. Chem.. 54, 293R (1982).
48-11
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Figure 1. SEM photomicrographs of Longview stone chip at 100X and 2000X.
Figure Z SSM photomicrographs of crushed Longview powder (63-58 \tm cut)
at 1QQX and 2000X.
Figure 3. SEM photomicrographs of caicina produced from the above powder
at 100X and 2000X.
4 8.-12
mt-m
-------
Figure 4. SEM photomicrographs of Maysvifle stone chip at 100X and 2000X.
Figure 5. SEM photomicrographs of crushed Maysvi/le powder (63-88 ftm cut)
at 100X and 2000X.
%
*•
*
V
• •
'
v
_ t
> *
%- ¦* % *
6
Figure 6. SEM photomicrographs of calcine produced from the above powder
at 100X and 2000X.
48-13
»•
W
Kll-113
-------
IMI'U!
Figure 7. High-resolution S£M photos showing calcine surface morphology.
48-14-.
-------
1111-114
Figure 8. SEM photomicrographs showing the directional nature of the calcination
process and the fissure-like pore structure.
48-15
-------
mi-ui
Figure 9. SSM photomicrographs ofhydratad lima partic/as produced from Longviaw limastona.
48-16:
-------
Figura 10. SEM photomicrographs of calcine particias produced from hydratad lima.
48-17
-------
19.700X
laoofh
I0II-UT
Figure 11. SEM photomicrographs of sulfated calcine particles produced from hydrate.
48-18
-------
Figure 12. SBM photomicrographs of sulfated calcine particles in combination with fly
ash from a medium-sulfur coal.
48-19
-------
a. Produced by heating reagent-grada calcita for 30 minutat
at 850 °C in static air anvironmant.
Figure 13. Carbon replica of calcined timastone particle^.
48-20
-------
1.
1 itIB
2S.OOOX
>Ni4>l
Figun 14. Thin station containing fngmants of caicintdVicron panic)* takan
from SRI combustor.
48-21
-------
Itii-iil
Figure 15. EDX spectra obtained on two different areas of a fly ash/sulfated calcine mixture.
48-22
-------
....flMoH-
• • 3B-? IBM IB4 :
d m iS u (
1H QJimtKIRF:
ltlt-14
Figura 16. SDX maps of calcium, sulfur, and aluminum in a fly ash/sulfatad ca/cina mixtura.
48-23
-------
CALCIUM
PULLSCALS¦
50,000 cauno/mtn
SULFUR
FULL SCALS -
10,000 counts/mm
IRON
FULL SCALS "
5,000 counts/mitt
SILICON
PULL SCALS-
8,000 ownti/min
ALUMINUM
FULL SCALS»
8,000 eountt/min
12 1« 24 30
0ISTANCS. ami
9. Natural gat doped with 2270 ppm SO 2; capture « 22%
Figure 17. Electron microprobe scans across a sulfated calcine panic!e produced by
burner injection of Vicron limestone in a pilot-scale combustor.
48-24
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Table 1
LIMESTONES EXAMINED SY SEM
Name
Longview
MaysviHe
Supplier
Southern Industries
Dravo Lime Co
Quarry Location
Saqlnaw. AL
MavsvUle. KY
% Loss on ignition
43.4
43.5
% CaC03
96.6
91.4
% MgCOj
1.9
5.8
% S10,
% A1203
0.54
1.5
0.68
0.68
S FtjOj
% K,0
0.17
0.21
0.03
0.11
% so3
0.15
0.22
Table 2
DEPTH PROFILES DETERMINED Br
AES WITH ION MILLING
Etch Depth
(A) % SI * A1 % 0 % Ca IS
02B0-105 Ash/sorbent mixture
0 4.3 ST 3? %7 5.4
300 5.2 10 33 34 9.7
900 3.1 13 37 35 5.5
0494-2 Kaolin/sorbent mixture
0 373 5TT 37 & 1.6
25 4.0 7.2 36 45 1.6
100 3.5 8.2 39 48 1.9
700 3.3 6.6 36 53 0.9
48-25
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APPENDIX A
LIST OF ATTENDEES
1ST JOINT SYMPOSIUM ON DRY S02 AND
SIMULTANEOUS S02/N0X CONTROL TECHNOLOGIES
SAN DIEGO, CALIFORNIA, NOVEMBER 13-16, 1984
David U. Abltn
FMC Corp.
1501 Woodfleld Road
Suite 300 East
Schaumburg, IL 50195
Irans Allan
Prov. Geld. Electr. Montsch
P.O. Box 9039
6800 EZ Arhhem
THE NETHERLANDS
(312) 843-1700
085-772211
Jerry W. Aekarnan
Babcock I Wilcox
1562 Beeson
Alliance, OH 44601
(216) 821-9110
Rul Afonso
Dynatech RAD Co.
99 Erie Street
Cambridge, MA 02146
(617) 868-8050
Helen Ahlbom
Swedish Science Office
10880 W11shire Boulevard, #914
Los Angeles, CA 90024
(213) 475-0589
Stefan Aftran
Flafct AB
Flakt AB, P.O. Box
S-35187 Vaxjo, SWEDEN
0470-87276
Gary D. Aho
Cliffs Engineering, Inc.
818 Taughenbaugh Blvd.
Rifle, CO 81650
(303) 625-2445
Per Alvfors
The Royal Institute of Technology
Department of Chemical Engineering
S-100 44 Stockholm
SWEDEN
(46) 87877000
Roger Argus
GA Technologies, Inc.
P.O. Box 85608
San Diego, CA 92138
(619) 455-2785
V1ren S. Bekhshf
U.S. Gypsum
700 N. Highway 45
Ubertyvllle, IL 60048
(312) 362-9797
Ronald F, Balfng-ft
City of Los Angeles
Department of Hater and Power
P.O. Box 111, Room 931
Los Angeles, CA 90051
(213) 481-5382
H. A. Bambrough
Department of Environment
351 Blvd St. Joseph
13 m Stage
Hull, Quebec, CANADA
(819) 997-1220
A-l
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David F. Bartlett
Ladenburg, Thalmann & Co., Inc.
540 Madison Avenue
New York, NY 10022
(212) 940-0115
0. S. Satchelor
Kerr-McGee Chemical Corporation
Kerr-McGee Center, MT-1604
Oklahoma City, OX 73125
(405) 270-3371
Roger Baumberger
Ladenburg, Thalmann i Co., Inc.
540 Madison Avenue
New York, NY 10022
(212) 940-0115
Joseph I. Seals
Wallace S Tleman/Pennwal
2001 Midwest Road #210
Oak Brook, IL 60521
(312) 620-3320
Steven Becker
Southwestern Public Service
P.O. Box 1261
Amarillo, TX 79170
(806) 378-2441
Rod 3e1ttel
Southern Research Institute
P.O. 8ox 55305
Birmingham, AL 35255-5305
(205) 323-6592
John C. Bennett
Ontario Hydro
700 University Avenue
Toronto, Ontario
CANADA M5G 1X6
(416) 592-5244
Mogens Berg
Elkraft Power Co., Ltd.
Lautruphoj 5
2750 Ballerup
OENMARK
Edward L. Bledell
MlkroPul Corporation
10 Chatham Road
Summit, NJ 07901
(201) 273-6360
Arthur A. Bon1
Physical Sciences Inc.
Research Park, P.O. Box 3100
Andover, MA 01810
(6171 475-9030
David Bordson
Minnesota Pollution Control Agency
1935 West County Road, 3-2
Rosevllle, MN 55113
(612) 296-7780
Robert H. Borgwardt
US EPA, IERL/RTP
MD-4
Research Triangle Park, NC 27711
Steven Bortz
International Flame Research Foundation
P.O. Box 10000, 81dg 3G-25
1970 CA Ijmuiden
THE NETHERLANDS
02510-94901
Kerry 8owers
Southern Company Services
P.O. Box 2625
300 Shades Creek Parkway
Birmingham, AL 35202
Arthur S. 3owes, Jr.
Industrial Resources, Inc.
Ill W. Monroe Street
Chicago, IL 60603
(312) 346-9126
A-2
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Donald E. 8oyd
Flakt, Inc.
P.O. Box 87
Knoxvllle, TH 37901
(6X5) 693-7550
Kevin Bruce
Acurex Corporation
P.O. Box 13109
Chapel H111. NC 27709
(919) 549-8915
Russell 8oyd
Envirosphere Co.
145 Technology Park
Norcross, GA 30092
(404) 449-6639
Howard A. Boyer
Allied Corp.
P.O. Box 1087R
Morrlstown, NJ 07960
(201) 455-4684
Bruce Bralne
ICF, Inc.
1850 K Street
Washington, DC 20006
(202) 862-1100
Bernard P. Breen
Energy Systems Associates
2512 Chambers Road, Suite 101
Tustln, CA 92680
(714) 730-5990
Gerald E. Bresowar
Combustion Engineering, Inc.
P.O. Box 43030
Birmingham, AL 35243
(205) 967-9100
Joseph G. Brlsch
Rockwell 11me Company
4223 Rockwood Road
Manitowoc, WI 54220
(414) 682-7771
Ted Bma
US EPA, IERL/RTP
Research Triangle Park, NC 27711
C. PhlUpp Brundrett
W. R. Grace
Davison Chemical Division
P.O. Box 2117
Baltimore, MO 21203
(301) 659-9192
Kevin R. Bryson
Stone & Webster Engineering Corp
3 Executive Campus
Cherry Hill, MO 08036
(609) 482-3677
Eugene A. Bums
S-Cubed
P.O. Box 1620
La Jolla, CA 92038
(619) 453-0060
R. Lee Byers
Alcoa
425 6th Avenue
Pittsburgh, PA 15219
(412) 553-2094
Edward Callahan
Environmental Protection Agency
401 M Street SW
Washington, DC 20460
(202) 382-4179
Bob Candelarla
Navajo Generating Station
Salt River Project
P.O. Box w
Page, AZ 86040
(602) 645-8811
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John Cardosa, Jr.
Tenn-luttrell Lime Company
P.O. Box 69
Luttrell, TN 37779
1-800-951-9652
Charles S. Chang
Los Angeles Dept. of Water and Power
P.O. 8ox 111
Los Angeles, CA 900S1
(213) 481-5699
John Chang
Acurex Corporation
W1ng S Operations
Highway 54 i Alexander
Research Triangle Park, NC 27711
(919) 549-8915
Ted S.-G. Chang
Lawrence Berkeley Lab
Building 70, Room 110A
Berkeley, CA 94720
(415) 486-5125
Edward L. Chapman
FMC Corporation
1501 Woodfleld Road
Suite 300 East
Schaumburg, IL 60195
(312) 843-1700
Jeff Chappell
US EPA
IERL/RTP (MO-63)
Research Triangle Park, NC 27711
(919) 541-3738
S. L. Chen
EER
18 Mason
Irvine, CA 92714
Frank Chlarotto
Ontario Hydro
595 Bay Street
Toronto, Ontario
M5G 2C2 Loc A8G3 CANAOA
(416) 592-4645
Joseph K. Chou
Texas A4M University
Department of Mechanical Engineering
College Station, TX 77843
(709) 845-4787
M. Yaqub Chughtal
L2C Stelnmueller
5270 Gummersbach 1
WEST GERMANY
Ed Clchanowlcz
EPRI
3412 H111view Avenue
Palo Alto, CA 94303
(415) 855-2374
Leo G. Cirotskl
Kerr McGee Chemical Corp.
P.O. Box 367
Trona, CA 93562
(619) 372-4311
Jams M. Clark
Joy Manufacturing Company
Western Precipitation 01vision
P.O. Box 2744, Terminal Annex
Los Angeles, CA 90051
(818) 240-2300
Kevin Cleary
California A1r Resources Board
1102 Q Street
Sacramento, CA 95814
(916) 322-8269
(714) 859-8851
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Jerald A. Cole
EER Corp.
18 Mason
Irvine. CA 92718
(714) 859-8851
Bob Collette
Combustion Engineering, Inc.
1000 Prospect HI11 Road
Windsor, CT 06095-0500
(203) 285-5687
D. G. Colley
Western Research
1313 - 44 Avenue, N.E.
Calgary, Alberta
CANADA T2E 6L5
(403) 276-8806
John L. Crawley
Genstar 11me Company
901 Mariner's Island Boulevard
Suite 425
San Mateo, CA 94404
(415) 571-5463
William R. Cress
Allegheny Power Service Corp.
800 Cabin HI11 Drive
Greensburg, PA 15601
(412) 838-6721
E. P. Crockett
American Petroleum Institute
1220 L. Street N.w.
Washington, DC 20005
(202) 682-8318
Charles S. Cook
General Electric Environmental
Services, Inc.
200 N. Seventh Street
Lebanon, PA 17042
(717) 274-7275
J. M. Corcoran
Tenneco Minerals Company
P.O. Box 1167
Green River, WY 82935
(307) 875-6500
Maxwell E. Cox
Kerr-McGee Chemical Corp.
Kerr-McGee Center
Oklahoma City, OK 73125
(405) 270-3373
A. 8. (Chick) Craig
US EPA, IERL/RTP
Research Triangle Park, NC 27711
Robert S. Dahlln
Southern Research Institute
P.O. Box 55305
Birmingham, Al 35255
(205) 323-6592
Richard P. Qawklns
Fluor Engineers, Inc.
333 Michel son Drive
Irvine, CA 92730
(714) 553-5187
R. Dean Delleney
Radian Corporation
Box 19948
Austin, TX 78766
(512) 454-4797
David DeLutfa
Massachusetts Institute of Technology
Room 66-053
Cambridge, MA 02139
(617) 253-6533
A-S
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Coslmo DeMasI
Tucson Electric Power
Box 711
Tucson, AZ 85702
(602) 745-3391
Tom P. Dor eta k
Department of Energy
Sox 880
Morgantown, WY 26505
(304) 291-4643
~111p P. Deshpande
Alberta Power Ltd.
10035 - 105th Street
Edmonton, Alberta, T5J 2V6
CANAOA
(403) 420-7177
Prakash H. Dhargalkar
Research-Cottrell
P.O. Box 1500
Somerville. NJ 08876
(201) 685-4295
James C. Dlckerman
Radian Corporation
P.O. Box 13000
3200 Progress Center
Research Triangle Park, NC 27709
(919) 541-9100
Lawrence W. Dickson
Atomic Energy of Canada Limited
Whlteshell Nuclear Research
Establishment
Plnawa, Manitoba
CANAOA ROE 1L0
(204) 753-2311
Richard Olffenbach
Department of Energy
P.O. Box 10940
Pittsburgh, PA 15236
(412) 675-6090
E. B. Olsmukes
Southern Research Institute
P.O. Box 55305
Birmingham, AL 35223
Thomas E. Dowdy
University of Tennessee Spaa Institute
Tullahoma, TN 37388
(615) 455-0631
Dennis Drehmel
US EPA
IERL/RTP (M0-62)
Research Triangle Park, NC 27711
F. Carter Dreves
Wheelabrator A1r Pollution Control
600 Grant Street
P1ttsburgh, PA 15219
(412) 288-7325
Charles J. Drummond
Department of Energy
PETC
P.O. Box 10940
Pittsburgh, PA 15236
(412) 675-6011
Ronald G. Ouffy
Peabody Process Systems
201 Merrlt 7
P.O. Box 6037
Norwalk, CT 06852
(203) 846-1600
Sat1 sh K. Ouggal
Coming Glass Works
Main Plant 8-5
Corning, NY 14831
(607) 974-7177
(205) 323-6592
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Richard Dye
Department of Energy
FE-13, Forrestal
Washington, DC 20585
(202) 252-5499
David Eskinazi
EPRI
3412 Hill view Avenue
Palo Alto, CA 94303
(415) 855-2918
F. A. (Roy) Dyer
Church i Dwight Co., Inc.
20 Kingsbrldge Road
Piscataway, NJ 08854
(201) 885-1220
Jtclc Everett
Rust Internatlonal Corp.
P.O. Box 101
Birmingham, Al 35201
(205) 254-4452
Gene H. Dyer
Bechtel Group, Inc.
50 Seale Street
San Francisco, CA 94106
(415) 768-7007
Walter F. Farmayan
Shell Development Co.
P.O. Box 1280
Houston, TX 77001
(713) 493-8491
Owen Dykema
Rockwell International
8900 DeSoto Avenue
Canoga Park, CA 91304
(818) 700-4007
Donald Ehreth
US EPA
Office of Research and Development
401 M Street, SW
Washington, DC 20460
Glenn C. England
EER Corporation
18 Mason
Irvine, CA 92714
(714) 859-8851
Michael Esche
Saarberg-Holter Umwelttechnik GmbH
Ha fens tr. 6
D-6600 Saarbrucken
WEST GERMANY
6B1-32105
William W. Farmer
Georgia Power Company
P.O. Box 4545
333 Building, 18th Floor
Atlanta, GA 30302
(404) 526-7194
Bruce Firth
Signal U0P Research Center
50 U0P Plaza
Des Plaines, IL 60016
(312) 391-3239
Gerard Flamint
Ctrchar
BP no 2
60550 Vemeufl-en-Halatte
FRANCE
(33) 4-455-35-00, x572
Tim Flora
Ohio Edison
Gorge Plant
715 E. Cuyahoga Falls Avenue
Akron, OH 44310
(216) 384-5063
A-7
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Russell C. Forsythe
Oravo Technology
3600 Neville Road
Pittsburgh, PA 1S22S
(412) 777.-5553
Maria Gardlng
The Royal Institute of Technology
Department of Chemleal Engineering
S-100 44 Stockholm
SWEDEN
(46) 87877000
Grant 3. Frame
Flakt Canada Ltd
Sox 5060, Stn F
Ottawa, Ontario
CANAOA
David Gass
Saskatchewan Power Corp.
2025 Victoria Avenue
Reglna, CANAOA S4P 0S1
(513) 226-3300
(306) 566-3076
David Fronhelser
Bradley Pulverizer Co.
P.O. 8ox 1318
Allentown, PA 18105
(215) 434-5191
Carl A. Gilbert
Oravo Lime Company
3600 Neville Road
Pittsburgh, PA 15225
(412) 777-5559
Oavld Saige
Burns & McDonnell
P.O. Box 173
Kansas City, MO 64141
(816) 333-4375
Lee K. Gilmer
Texaco USA
P.O. 8ox 1608
Port Arthur, TX 77641
(409) 989-6364
David Gallaspy
Southern Co. Services, Inc.
Research and Development Dept.
P.O. Box 2625
800 Shades Creek Parkway
Birmingham, AL 35202
Dan Y. Giovanni
Electric Power Technologies, Inc.
Box 5560
Berkeley, CA 94705
(415) 653-6422
Ignatius J. Gallo
Texasgulf Chemicals Co.
P.O. Box 30321
Raleigh, NC 27612
(919) 829-2810
Robert J. Gleason
Research-Cottrel1, Inc.
P.O. Box 1500
Somervllle, NO 08876
(201) 685-4956
John Ganley
GA Technologies, Inc.
P.O. Box 85608
San Diego, CA 92138
(619) 455-2517
M. Rao Godlnenl
Combustion Engineering
1000 Prospect H111 Road
Windsor, CT 06095
(203) 688-1911
A-8
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Robert F. Goecker
Marcona Ocean Industries, Ltd.
700 W. HUlsboro, Suild 3, Suite 205
Deerfleld Beach, Fl 3441-1898
(305) 429-0600
Gary J. Goetz
Combustion Engineering, Inc.
1000 Prospect Hill Road
Windsor, CT 06095-0500
Oean Golden
EPRI
3412 Hill view Avenue
Palo Alto, CA 94303
(415) 85S-251S
J. R. Gonterman
Owens/Coming Flberglas
Technical Center
Granville, OH 43023
(614) 587-7533
A. J. Gra&s
Esmll International 8.V.
DE Boelelann 7
P.O. Box 1178
1008 AA Amsterdam
HOLLANO
020-5411054
George P. Green
Public Service Co. of Colorado
550 - 15th Street
Denver, CO 80202
(303) 571-7021
Jack Greene
US EPA
IERl/RTP
Research Triangle Park, NC 27711
Ted Guth
U1trasystems
16795 Von Karman
Irvine, CA 92714
(714) 863-7000
Kenneth E. Hablger
Black ft Veatch Engineers-Architects
P.O. Box 8405
Kansas City, MO 64114
(913) 967-2990
John W. Hagley
Pennsylvania Power ft Light Co.
Two K. ninth Street
Allentown, PA 18101
(215) 770-5159
J1m Hall
EnvlroCarr
100 GalH Drive
Novato, CA 94947
(415) 883*3594
David Ham
Physical Sciences, Inc.
P.O. Box 3100
Andover, MT 01810
(617) 475-9030
Fenton Hanchett
Allied Corporation
P.O. Box 1053R
Morrlstown, NJ 07960
(201) 455-3820
Scott M. Harklns
Research Triangle Institute
P.O. Box 12194
Research Triangle Park, NC 27711
(919) 541-5937
A-9
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John 3. L. Harkness
Argonne National laboratory
EES 01 vision
Building 362
Argonne, IL 50439
{312} 972-7636
Harry A. Harris
Ash Grove Cement Co.
640 Southwest Boulevard
Kansas City, KS 66103
(913) 722-5998
Seyed N. Hashemi
Potomac Electric Power Co.
1900 Pennsylvania Avenue, NW
Washington, DC 20068
(202) 331-6280
John L. Has!beck
HOXSO Corporation
2625 H. C. Mathis Drive
Paducah, KY 42001
(502) 444-6474
Robert H. Hass
Union 011 Company of California
Science and Technology Division
376 South Valencia Avenue
Brea, CA 92621
(714) 528-7201
Thorns J. Hassell
DuPont Company
Engineering Dept 13370
Wilmington, OE 19898
(302) 366-4343
John B. Hattrup
Baltimore Gas & Electric
P.O. Box 1475
Baltimore, MO 21203
(301) 234-6427
Klaus R. G. Hein
Rhelni sch-Vlestfali sches
Elefctrizitatswerk
Kruppstr. 5
4300 Essen 1
WEST GERMANY
02271/584-2234
Paul 0. Hemphill
Dresser Industries, Inc.
Environmental Products Division
601 Jefferson
Houston, TX 77002
(713) 750-3736
Robert V. Hendricks
US EPA
IERL/RTP (MO—63 J
Research Triangle Parle, NC 27711
Bruce Henschel
US EPA
IERL/RTP
Research Triangle Park, HC 27711
Robert A. Hentges
Procter i Gamble Co.
6105 Center H111 Road
Cincinnati, OH 45224
(513) 659-5787
Robert A. Herrick
Owens Coming Fiberglas
Flberglas Tower-FF/7
Toledo, OH 43659
(419) 248-7126
Robert L. Hershey
Science Management Corporation
2101 L Street NH( Suite 903
Washington, DC 20037
(202) 293-5700
A-10
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Barry R. H1 ckenbottotn
NEESA
Code IIBP
Port Hueneme, CA 93043
(805) 982-3245
Janes 0. Hlckerson
Department of Energy
P.O. Box 10940
Pittsburgh, PA 15236
(412) 675-5721
Jay J. Hill
Ashland 011, Inc.
P.O. Box 391
Ashland, Kr 41114
(505) 329-4389
Qavld C. Hoffraan
Chemical Lime, Inc.
6000 western Place, Suit* 439
Fort Worth, TX 76107
(817) 732-8164
John B. HolHster, Jr.
The Cleveland-Cliffs Iron Company
14th Floor Huntington Building
Cleveland, OH 44115-1448
(216) 241-2356
Richard Hooper
EPRI
Arapahoe Test Facility
P.O. Box 10577
University Park Station
Denver, CO B0210
Anthony J. Host
San 01ego Gas & Electric
P.O. Sox 1831
San Diego, CA 92112
(619) 696-2984
Walter Hufaner
Studsvlk Energlteknlk A3
S—fill 82
Nykoplng
SWEDEN
(45) 155-800-00
Thomas B. Hurst
Babcock & Wilcox
20 S. Van Buren Avenue
Barberton, OH 44203
Merrill Jackson
US EPA, IERL/RTP
Research Triangle Park, NC 27711
Kurt Jakobson
US EPA
Hall Code RD-681
Washington, DC 20460
(202) 382-4969
ten Jensen
GA Technologies, Inc.
P.O. Box 65608
San Olego, CA 92038
(619) 455-2517
Torgny Johansson
Flakt Industr! AB
S-351 87 Yaxjo
SWEDEN
0470-87710
Carlton A. Johnson
Peabody Process Systems, Inc.
45 Church Street
Stamford, CT 06906
(203) 327-7000
Howard J. Johnson
US EPA
P.O. Sox 1049
Colunbus, OH 43216-1049
1614) 466-6115
A-ll
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Dale 8. Jones
BTll Services
424 N. Lake Avenue, Suite 200h
Pasadena, CA 91101
(318) 796-2265
Martin A. Jones
Cliffs Engineering, Inc.
818 Taugenbaugh Blvd.
Rifle, CO 81650
(303) 625-2445
Richard J. Jordan
Cooper Eng1ne«rs, Inc.
1301 Canal Boulevard
Richmond, CA 94801
(415) 235-2360
Peter Judersleben
Research-Cottrell
P.O. 8ox 1500
Somervllle, htJ 08876
(201) 685-4979
Robert A. Kaiser
Ohio Edison Company
76 South Main Street
Akron, OH 44308
(216) 384-5770
Anda Kalvlns
Ontario Hydro
800 Kipling Avenue
Toronto, Ontario M8Z 5S4
CANADA
(416) 231-4111
George C. Kane
Natrona Resources, Inc.
1600 Broadway, Suite 1450
Oenver, CO 80202
(303) 839-1600
Norman Kaplan
US EPA
IERL/RTP (MO-63)
Research Triangle Park, NC 27711
Stev« M. Katzberger
Sargent & Lundy
55 E. Monroe
Chicago, II 60603
(312) 269-6672
Bob Keeth
Steams Catalytic Corporation
P.O. Box 5888
Oenver, CO 80217
(303) 692-3179
John Kelly
Acurex Corporation
P.O. Box 7555
555 Clyd« Avenue
Mountain View, CA 94039
(415) 964-3200
Stephen E. Kerho
KVB, Inc.
18006 Skypark Boulevard
Irvine, CA 92714
(714) 250-6200
Ernest E. Kern
Houston Lighting & Power
P.O. Box 1700
Houston. TX 77001
(713) 481-7608
James D. Kllgroe
US EPA
IERL/RTP
Research Triangle Park, NC 27711
Lawrence P. King
Babcock i Wilcox
1562 Beeson Street
Alliance, OH 44601
(216) 821-9110
A-12
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David A. Klrchgessner
US EPA
IERl/RTP (MD-4)
Research Triangle Park, NC 27711
Mogens Kfrkegaard
RISOE National Laboratory
Box 49
4000 Roskllde
DENMARK
J. Kissing
Stork Boilers
7550 G8 Hengelo
THE NETHERLANDS
074-454321
J. H. Klelnau
Keeler/Dorr-OHver Boiler Company
P.O. Box 548
wmiamsport, PA 17703
(717) 327-3166
Jonas KUngspor
Battel1e Columbus Laboratories
505 King Avenue
Columbus» OH 43201
(614) 424-4655
Thorns E. Kobett
AMCA E4C
P.O. Box 1281
Houston, TX 77251-1281
(713) 596-1758
Bernard J. Koch
CONOCO Coal Research Division
4000 Brownsville Road
Library, PA 15129
(412) 854-6612
Don Koeberleln
California A1r Resources Board
1102 Q Street
Sacramento, CA 95814
(916) 322-3988
Robert Koucky
Combustion Engineering, Inc.
1000 Prospect H111 Road
Windsor, CT 06095-0500
(203) 688-1911, x3139
Karl Kozak
Combustion Engineering
2421 W. Hillcrest Drive
Newbury Park, CA 91320-2299
(805) 498-6771
John Kramllch
EER Corporation
18 Mason
Irvine, CA 92718
(714) 859-8851
Calvin Ku
ONR-MO
P.O. Box 1368
Jefferson City, MO
(314) 751-4827.
David G. Lachapelle
US EPA, IERL/RTP
MD-63
Research Triangle Park, NC
E. C. Landham, Jr.
Southern Research Institute
P.O. Box 10155
University Park Station
Denver, CO 80210
(303) 922-9764
Anita 0. Lang
Babeock i Wilcox
1562 Beeson Street
Alliance, OH 44601
(216) 821-9110
A—13
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Larry L. Larsen
Energy Technology Consultants
2091 Business Center Drive, #100
Irvine, CA 92715
(714) 833-2526
A1 LaRue
Babcock 1 Wilcox
20 South Van Buren
Barberton, OH 44203
(216) 860-1493
Norbert G. Lassahn, Jr.
Baltimore Gas & Electric Co.
P.O. Box 1475
Baltimore, M0 21203
(301) 787-5377
B. A. Laszke
PEI Associates, Inc.
11499 Chester Road
Cincinnati, OH 45246
(513) 782-4700
Pete Lawson
Ontario Hydro
700 University Avenue
Toronto, Ontario
CANADA M5G 1X6
(416) 465-2925
Yves Lecompte
Volcano Inc.
4300 Beaudry Avenue
St-Hyac1nthe. Quebec
CANAOA
(514) 774-5326
George C. Lee
Bechtel Group, Inc.
50 Beale Street
San Francisco, CA 94105
(415) 768-4802
Donald E. Lentzen
Research Triangle Institute
P.O. Box 12194
Research Triangle Park, NC 27709
(919) 541-6738
Arthur Levy
Battelle Columbus Laboratories
505 King Avenue
Columbus, OH 43201
(614) 424-4827
C. J. Lewis
National Lime Association
Environmental Services
P.O. Box 15453
Lakewood, CO 80215
(303) 237-2948
Frank Y. Llao
Mobil Research £ Development
P.O. Box 1026
Princeton, NO 08540
(609) 737-4955
Eric Llndgren
The University of Utah
310 Park Building
Salt Lake City, UT 84112
E1ner D. Llndqulst
CUffs Engineering, Inc.
818 Taughenbaugh Blvd.
Rifle, CO 81650
(303) 625-2445
Jan Llndqulst
Swedish Power Assn. Dev. Foundation
(VAST)
Box 1704
S-111 87 Stockholm
SWEDEN
08242390 or 087900350
A-14
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Robert A. Llsauskas
Riley Stoker Corp.
Riley Research Center
45 McKeon Road
Worcester, MA 01610
(517) 792-4802
Jeffrey Lorraln
Acurex Corporation
P.O. Box 13109
Chapel Hill, NC 27709
(919) 549-8915
Thomas A. Lott
Pacific Gas i Electric Co.
3400 Crow Canyon Road
San Ramon, CA 94583
(415) 820-2000
Gerald Marlngo
Babcock i Wilcox
20 South Van 8uren
Barberton, OH 44203
(216) 860-6321
Greg Markowskl
Consulting Aerosol Scientist
2009 N. Madison Avenue
Altaden, CA 91001
(818) 798-5546
John J. Marshall
Riley Stoker Corp.
Riley Research Center
45 McKeon Road
Worcester, MA 01610
(617) 792-4826
Richard Madenburg
Morrlson-Knudsen Co., Inc.
P.O. Box 7808
Boise, ID 83729
(208) 386-5069
Gary Maier
Florida Power & Light Co.
P.O. Box 14000
Juno Beach, FL 33408
(305) 863-3608
Ghassem Manavlzadeh
Research-Cottrel1
P.O. Box 1500
Somervllle, NJ 08876
(201) 685-4165
M. N. Mansour
MTCI
1000 S. Grand Avenue
Santa Ana, CA 92705
(714) 835-6660
G. Blair Martin
US EPA
IERL/RTP (MD-4)
Research Triangle Park, NC 27711
S. Matsushita
NGK-Locke, Inc.
767 Third Avenue
New York City, NY 10803
(212) 758-6020
John Maulbetsch
EPRI
3412 H111 view Avenue
Palo Alto, CA 94303
(415) 855-2438
Mike Maxwell
US EPA, IERL/RTP
Research Triangle Park, NC 27711
James J. McCauley
Public Service Electric i Gas Co.
P.O. Box 570, M.C. ISA
Newark, NJ 07101
(201) 430-7360
A-15
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Michael McElroy
EPRI
3412 Hill view Avenue
Palo Alto. CA 94303
(415) 8SS-2471
Denis A. Menegaz
M. w. Kellogg
3 Greenway Plaza
Houston, TX 77046
(713) 960-2500
Doug Merrill
Church i Dwlght Co., Inc.
20 Klngsbrfdge Road
Plscataway, NO 08854
(201) 385-1220
Romuald Michalak
Englehard
70 Wood Avenue South
Iselin, NO 08830
(201) 321-5342
I. John Mlnnick
Industrial Research Consultant
Box 271
Plymouth Meeting, PA 19462-0271
(215) 687-1167
Ralph K. Mongeon
Riley Stoker Corp.
9 Neponset Street
Worcester, MA 01606
(617) 792-4811
Max A. Moore
KYB, Inc.
18006 Skypark Boulevard
Irvine, CA 92714
(714) 250-6200
Michael G. Moore
US EPA
Office of Research & Development
Office of Research Program Management
401 M Street, S.W.
Washington, DC 20460
(202) 382-7468
Thomas Morasky
EPRI
3412 Hi11 view Avenue
Palo Alto, CA 94303
(415) 855-2468
Terrf E. Moreland
Illinois Dept. of Energy &
Natural Res.
325 West Adams Street, Room 300
Springfield, IL 62706
(217) 735-3870
Robert M. Morford
Joy Manufacturing Company
Western Precipitation Division
P.O. Box 2744, Terminal Annex
Los Angeles, CA 90051
(818) 240-2300
AT W. Mueller
Church i Owight Co., Inc.
20 K1ngsbr1dge Road
Plscataway, MO 08854
(201) 885-1220
P. H. Mulcahy
Kennedy Van Saun Corp.
800 Menlo Avenue, Suite 121
Menlo Park, CA 94025
(415) 325-4462
J. F. Murphy
Kaiser Aluminum & Chemical
P.O. Box 877
6177 Sunol Boulevard
Pleasanton, CA 94566
(415) 462-1122
A—16
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John Mustonen
Stone 4 Webster Engineering Corp.
P.O. Box 2325
Boston, MA 02107
Larry Muzlo
Fossil Energy Research Corp.
29541 Vista Plaza
Laguna Nlguel, CA 92677
Lewis G. Neal
NOXSO Corporation
2625 H. C. Mathls Orlve
Paducah, KY 42001
(502) 444-6474
R.* Douglas Neeley
Tennessee Valley Authority
214 SPB
Knoxvllle, TN 37902
(615) 632-6644
J. A. NelH
United States Gypsum Co.
101 S. Wacker Orlve
Chicago, IL 60606
(312) 321-5727
Harvey M. Mess
U.S. Department of Energy
Grand Forks Project Office
Box 7206, University Station
Grand Forks, NO 58202
(701) 795-8135
Joseph T. Newman
Bechtel Group, Inc.
50 Beale Street (50/15/C30)
San Francisco, CA 94105
(415) 768-1943
Gerald Newton
The University of Utah
301 Park Building
Salt Lake City, UT 84112
Per Nielsen
Danish Boiler Owners Association
Tlabsase Mollevej #15
Copenhagen
DENMARK
2860 SOE BORG
Linda G. N1man
Pacific Power
920 SW 6th Avenue
Portland, OR 97204
(503) 243-3021
Paul S. Nolan
Babcock i Wilcox
20 South Van Buren
Barberton, OH 44203
(216) 860-1074
8111 NuHck
Nurlck i Associates, Inc.
23276 South Polnte Drive, #206
Laguna Hills. CA 92714
(714) 855-1375
Gary Ochs
York Research Consultants
938 Quail Street
Denver, CO 80215
(303) 233-1513
George Offen
Acurex Corporation
555 Clyde Avenue
Mountain View, CA 94039
(415) 964-3200
Masakl Okada
Mitsubishi Heavy Industries
R4D Department
Shlba 5-34-6 Mlnatoku
Sh1n-Tamach1 Bid
Tokyo
JAPAN
03-455-5711
A-17
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Leff Olausson
Swedish State Power Board
S-16287 Vaellingby
SWEDEN
08-7395403
Michael Perlswe-ig
Department of Energy
FE-23
Washington, DC 20545
(301) 353-4399
Gregory Ondlch
US EPA
(RO 531)
401 M Street SVJ
Washington, DC 20460
(202) 382*2583
Ronald G. Ostendorf
Procter i Gamble Co.
7162 Reading Road
Cincinnati, OH 45222
(513) 763-4457
Ronald L. Ostop
Colorado Springs Department of
Utilities
P.O. Sox 5019
Colorado Springs, CO 80947
(303) 536-5533
Oelbert Ottmers, Jr.
Radian Corporation
P.O. Box 9948
8501 Mo-Pac Boulevard
Austin, TX 78766
(512) 454-4797
Peter Overdlck
Group Lholst-Oumont
Avenue Rogler, 21
8-4000 Liege
BELGIUM
(41) 52 20 25
Roy Payne
Energy i Environmental Research Corp.
18 Mason
Irvine, CA 92718
Oavld W. Pershing
Un1verslty of Utah
Department of Chemical Engineering
310 Park Building
Salt Lake City, UT 84112
Gale Peters
Consultant
2036 Broadway
Grand Junction, CO 81503
(303) 241-1649
Vincent Petti
Wheelabrator-Frye Inc.
600 Grant Street
Pittsburgh, PA 15219
(412) 288^7323
Henry A. Pfeffer
FMC Corporation
Sox 8
Princeton, NJ 08540
(609) 452-2300
George P1nhe1ro
Research-Cottrell, Inc.
P.O. Box 1500
Somervllle, NJ 08876
(201) 685-4109
Walter Plulle
EPRI
3412 H1l1v1ew Avenue
Palo Alto, CA 94303
(415) 855-2470
A-18
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Bob Plains Irwin A. Raben
Marblehead Lime IAR Technology, Inc.
2057E 10140 So. 130 Sandrfngham South
Sandy, UT 84090 Moraga, CA 94556
(801) 943-0461 (415) 376-3951
William Podorztr
Stauffer Chemical Co.
1391 S. 49th Street
Richmond, CA 94804
(415) 231-1280
Franz Pohl
Southern Research Institute
P.O. Box 55305
Birmingham, AL 35255-5305
(205) 323-6592
John T. Porter, II
GA Technologies, Inc.
P.O. Box 85608
San 01ego, CA 92138
(619) 455-4312
Thomas L. Potter
National Urn Associates
3601 H. Fairfax Drive
Arlington, YA 22201
(703) 243-5463
John M. Pr&tadas
Gas Research Institute
8600 W. Bryn Mawr
Chicago, IL 60631
(312) 399-8301
Hans Pynenburg
P.G.E.M.
Utrechtseske 85
Arnhem
Samuel L. Rakes
us EPA
IERL/RTP (MD-4)
Research Triangle Park, NC 27711
Richard Rath
Texasgulf Chemicals Co.
P.O. Box 30321
Raleigh, NC 27622-0321
(919) 829-2862
Christopher C. Rayner
Raymond Kaiser Engineering
P.O. Box 23210
Oakland. CA 94623
(415) 268-6243
Bruce Renrlck
National Crushed Stone Assoc.
1415 Elliot Place, NW
Washington, DC 20007
(202) 342-1100
Stan L. Reynolds
S-Cubed
3398 Camel Mountain Road
Sen Diego, CA 92121-1095
(619) 453-0060
Richard Rhudy
EPRI
3412 H111 view Avenue
Palo Alto, CA 94303
(415) 855-2421
(31) 085-772211
A-19
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Dominic Rigano
Exxon Research & Engineering
ISO Park Avenue
FTorham Park, NJ Q7869
(201) 765-1057
Randall E. Rush
Southern Company Services, Inc.
P.O. Box 2625
Birmingham, AL 35213
(205) 870-6320
Ron Rogers
Flakt, Inc.
Box 37
Xnoxvllle, TN 37901
(515) 693-75550
N. C. Sanrfsft
Stall Development Co.
P.O. 3ox 1380
Houston, TX 77001
(713) 493-7944
Richard Rolfe
C. F. Brown
1000 S. Fremont
Alhambra, CA 91802
Myrrl Santy
TRW
1 Spark Park. Bldg 01, Rm 2040
Redondo Beach, CA 90278
(318) 300-3971
(213) 536-4104
Vincent Roman
KY8, Inc.
18006 Skypark Boulevard
Irvine, CA 92714
(714) 250-62S3
James S. Sarapata
Church & Dwlght Co., Inc.
20 K1ngsbr1dge Road
Plscataway, NJ 08854
(201) 885-1220
Edward C. Rosar Loma E. Sawyers
Industrial Resources, Inc. Babcock 5 Wilcox
300 Union Boulevard, Suite 520 1562 Beeson Street
Lakewood, CO 80228 Alliance, OH 44601
(303) 986-4507 (216)*821-9110
Erik Rosenberg
Elkraft Power Co., Ltd.
Lautruphoj 5
2750 Sallerup
DENMARK
Harvey S. Rosenberg
Battelle-Columbus
505 King Avenue
Columbus, OH 43201
(614) 424-5010
Wolfgang Schemenau
Brown, Boverf 1 CIE, AG
(SK/OV)
6800 Mannheim
P.O. Box 351
Bundesrepubllk Deutschland
WEST GERMANY
0621-381-2734
Edmund S. Schlndler
Foster Wheeler Energy Corp.
1 Peach Tree Hill Road
Livingston, NJ 07039
(201) 533-2707
A-20
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James H. Schmidt
Colorado Utility Electric
P.O. Box 1149
Montrose, CO 81402
(303) 249-4501
Joseph J. Schrfeber, Jr.
Baltimore Gas i Electric Co.
One Center Plaza, 5th Floor
120 W. Fayette Street
Baltimore, MO 21201
(301) 234-6341
David A. Schulz
US EPA
Region V
230 S. Dearborn
Chicago, 1L 60604
(312) 886-6816
Manfred Schutz
Saarberg-Holter Unwelttechnlk GmbH
Hafenstrabe 6
0-6600 Saarbrucken 2
WEST GERMANY
F. Schwarzkopf
Kennedy Van Saun Corp.
Box 500
Danville, PA 17821
(717) 275-3050
Paul C. Scott
U.S. Department of Energy
FE-14
Washington, DC 20545
(301) 353-3906
Randy Seeker
Energy & Environmental Research Corp
18 Mason
Irvine, CA 92718
"Edwin H. Seldler
Pennsylvania Power i Light Co.
Two North Ninth Street
Allentown, PA 18101
(215) 770-4787
Helmunt Sendner
Technlscher Verlag Resch
Irnrtnfrled Str. 20-22
8032 Grefelflng
WEST GERMANY
(089) 855001
Richard Semirler
Southwestern Public Service
P.O. Box 1261
Amarnio. TX 79170
(806) 378-2185
Ray J. Shaffery
Church i Dwlght Co., Inc.
20 K1ng$br1dge Road
Plscataway, NJ 08854
(201) 885-1220
Navln D. Shah
Consultant
142 Sundance Count
Grand Junction, CO 81503
(303) 243-1503
Yel-Shong Shleh
Conversion Systems, Inc.
115 Gibraltar Road
Horsham, PA 19044
-------
G. H. Shroff
Bechtel Power Corp.
1574Q Shady Grove Road
Galthersburg, MO 20878
(301) 258-3145
Geoffrey 0. Si 1 cox
EER Corporation
18 Mason
Irvine, CA 92714
(714) 355-2918
Glrard A. Simons
Physical Sciences, Inc.
P.O. Box 3100
Andover, MA 01810
(617) 475-9030
Uday Singh
Arizona Public Service Co,
Station 5760
P.O. Box 21666
Phoenix, AZ 85036
(602) 271-7984
Archie V. Slack
Consultant
Wilson Lake Shores
Sheffield. AL 35660
(205) 383-1627
David M. Slaughter
University of Utah
Department of Chemical Engineering
306Z Mechanical Engineering Building
Salt Lake City, UT 84112
(801) 359-3422
A. G. SUger
The M. W. Kellogg Co.
Three Greenway Plaza
Houston, TX 77046
(713) 960-2625
David E* Smith
FMC Corporation
2000 Market Street
Philadelphia, PA 19103
(215) 299-6000
David W. Smith
Saskatchewan Power Corp.
2025 Victoria Avenue
Reglna, Saskatchewan
CANADA S4P 051
(306) 566-2290
Eual Randall Smith
Tennessee Valley Authority
100 IBM-C
Chattanooga, TN 37401
(615) 751-4457
Lowell L. Smith
Energy Technology Consultants
2091 Business Center Drive #100
Irvine, CA 9271S
(714) 833-2523
Roger R. Smith
Sargent & Lundy
55 E. Monroe
Chicago, IL 60603
(312) 269-6913
Walt Smith
Plains Electric GUT Coop.
P.O. Box 6551
Albuquerque, NM 87197
(505) 884-1881
Curtis M. Snow
Environmental Elements Corporation
P.O. Box 13X8
Baltimore, MO 21203
(301) 368-7381
A-22
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Eddie A. Snow
Southwestern Public Service
P.O. Box 1261
Ajnarillo, TX 79170
Jeffrey W. Stallings
SRI Internat1 one!
333 Ravenswood Avenue
Menlo Park, CA 94025
(806) 378-2434
(415) 859-3077
Gerry Snow
Acurex Corporation
P.O. Box 13109
Chapel Hill, NC 27709
(919) 549-8915
Michael J. H. Snow
MIT
Room 66-021
77 Massachusetts Avenue
Cambridge, MA 02146
(617) 253-7982 or 253-6557
Albert Solbes
TRW Energy Development Group
127-1360, One Space Park
Redondo Beach, CA 90278
(213) 517-7343
Tim W. Sonnlchsen
J. H. Jansen Co.
18016 140th NE
Woodinvnie, MA 98072
(206) 485-8440
Herbert W. Spencer
Joy Manufacturing
P.O. Box 2744 TA
Los Angeles, CA 90051
(818) 240-2300, x426
Donald Squires
DEQE/DAQC
One Winter Street
Boston, MA 02105
(617) 292-5618
Robert M. Statnlck
CONOCO
Coal Research Division
4000 Brownsville Road
Library. PA 15129
Gemot Staudlnger
Technical University of Graz
Inffeldgasse 25
A-8010 Graz
AUSTRIA
George C. Stegmann
Con Edison of New York
4 Irving Place
New York, MY 10003
(212) 460-2754
Meyer Steinberg
Brookhaven National Laboratory
Upton, HY 11973
(516) 427-0750
Jay L. Stern
Joy Manufacturing Co.
4565 Colorado Boulevard
Los Angeles, CA 90039
(818) 240-2300
Richard Stern
US EPA
IERL/RTP (MO-63)
Research Triangle Park, NC 27711
Nicholas J. Stevens
Research-Cottrell
P.O. Box 1500
Somrville, NO 08876
(201) 685-4887
A-23
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Pat Stone
Signal Research
50 UOP Plaza
Oes Places, IL 60143
(312) 391-3510
H. S. Tang
Shell Development Co.
P.O. Box 1380
Houston, TX 77001
(713) 493-8113
Donald H. Stowe, Jr.
Oravo Lime Company
3600 Neville Road
Pittsburgh, PA 1S22S
(412) 777-5574
Donald P. Te-fxelra
Pacific Gas t Electric Co.
3400 Crow Canyon Road
San Ramon, CA 94583
(415) 820-2000
J. P. Strakey
U.S. Oepartaent of Energy
PETC
P.O. Sox 10940
Pittsburgh PA 15236
(412) 675-6125 or 5705
Jams R. Strom
Gulf RIO
P.O. Sox 2038
• Pittsburgh, PA 15230
(412) 665-5628
Rod Thacker
Tenneco Minerals Co.
3707 FM 1960 M. Suite 420
Houston, TX 77068
(713) 580-0847
Jack T. Thompson
Tennessee Valley Authority
705 Edney 8u1lding
Chattanooga, TN 37401
(615) 751-2774
Peter Stromberg
Euroc Research AB
Gle Romers Vag 12
S-22363 Lund
SWEDEN
046-168593
Gunnar Svedberg
The Royal Institute of Technology
Oepartaent of Chemical Engineering
S-100 44 Stockholm
SWEDEN
(46) 87878727
Thomas Szymanskl
Norton Company
P.O. Sox 350
Akron, OH 44309
Jeffery L. Thompson
Oravo Lime Company
3600 Neville Road
Pittsburg, PA 15225
(412) 777-5571
Richard E. Thompson
Fossil Energy Research Corp.
29541 Vista Plaza Drive
Laguna Miguel, CA 92677
(714) 556-2800
James T1ce
Pennsylvania Electric Co.
1001 Broad Street
Johnstown, PA 15907
(216) 673-5860
A-24
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Kimishiro Tokuda
Mitsubishi Heavy Industries, Ltd.
Nagasaki Technical Institute
5-717-1, Fukahori-Machl
Nagasaki 851-03
JAPAN
(0958) 71-5111 x3354
Victor Tollesan
Ohio Edison Co.
76 So. Main Street
Akron, OH 44308
(216) 384-5747
Harry Tossalnt
Stork Boilers
P.O. Box 20
7550 SB Hengelo
THE NETHERLANDS
074-454321
Peter A. Trout
U.S. Gypsum Co.
101 So. Wacker Drive
Chicago, IL 60606
(312) 321-5725
Shao-E Tung
91 Blake Road
Brook!ine, MA 02146
(617) 731-5490
Em111o Hidalgo Uribe
Comislon Federal de Electr1c1dal
R1o M1ss1s1p1 70-10* p1so
Mexico D.F. Z.P.S.
55371-33 x2023
Mohammad Vakili
Wisconsin Power * Light Co.
222 W. Washington Avenue
Madison, WI 53701
(606) 831-5609
Henk A. VanOostveen
Ministry Environmental Management
P.O. Box 450
2260 MB Leldschendam
THE NETHERLANDS
70209367
Alan E. Van T11
Signal UOP Research Center
50 UOP Plaza
Des Plalnes, IL 60143
(312) 391-3149
Joel Vatsky
Foster Wheeler Energy Corp.
9 Peach Tree H111 Road
Livingston, NJ 07039
(201) 533-2105
Charlie F. Vaughn
Nevada Power Co.
P.O. Box 230
Las Vegas, NV 89151
(702) 367-5656
Gary R. Veerkamp
Pacific Gas i Electric Co
77 Beale Street, Room 2533
San Francisco, CA 94106
(415) 781-4211
Patricia A. Vopelak
Illinois Power Company
500 S. 27th Street
Decatur, IL 62525
(217) 424-6835
Bill Wahl
Research-Cottrell
23642 Calabasas Road, #106
Calabasas, CA 91302
(818) 716-1606
A-25
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Dan Walker
Genstar L1me Company
P.O. Sox 127, BMI Complex
Henderson, NV 890X5
(702) 565-8991
Stephen R. Wilson
Joy Manufacturing Co.
4565 Colorado Blvd.
Los Angeles, CA 90039
(818) 240-2300
Larry Ward
Saskatchewan Power Corp.
2025 Victoria Avenue
Reglna, Saskatchewan
CANADA S4P 051
R. David WlnsMp
Combustion Engineering - Canada
99 Bank Street
Ottawa, Ontario
CAMAQA KIP 6C5
(306) 566-2995
(613) 560-4400
William A. Warfe
Energy, Mines i Resources
580 Booth Street
Ottawa, Ontario
CANADA K1A 0E4
(613) 995-1118
Gregory F. Weber
UNO Energy Research Center
15 North 23rd Street
Grand Forks, NO 58201
(701) 777-5222
Alexander Weir, Jr.
Southern California Edison Co.
P.O. Box 800
Rosemead, CA 91770
(818) 572-2785
Jerry L. Williams
Tampa Electric Co.
P.O. Box 111
Tampa, Ft. 33601
(813) 228-4837
John E. Williams
U.S. Department of Energy
Pittsburgh Energy Technology Center
P.O. Box 10940
Pittsburgh, PA 15236
(412) 675-5727
Carole A. Wolff
Illinois Pollution Control Board
309 W. Washington
Chicago, IL 60606
(312) 793-3620
Evan Wong
California A1r Resources Board
1102 Q Street
Sacramento, CA 95814
(916) 323-6988
John L. Wood
Central and South West Services
P.O. Box 660164
Dallas, TX 75266-0164
(214) 754-1380
R. Martin Wright
FMG Corporation
2000 Market Street
Philadelphia, PA 19103
(215) 299-6000
Philip E. Wubboldlng
Public Service Co. of Indiana
1000 E. Main Street
Plainfleld, IN 46168
(317) 838-1153
A-26
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Robert J. Yang
KYB, Inc.
18006 Skyp&rk Boulevard
Irvine, CA 92714
(714) 250-6268
Paul Yoslck
Flakt, Inc.
P.O. Box 87
Knoxvllle, TN 37901
(615) 693-7550
Frank T. Yannett
Research-Cottrell Inc.
P.O. Box 1500
Somervflle, NJ 08876
(201) 685-4790
Shul-Chow Yung
Air Pollution Technology,
5191 Santa Fe Street
San Diego, CA 92109
(619) 272-0050
A-27
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TECHNICAL REPORT OATA
(Picas* rtad tmunu titmt on tMt mm* In fort eomplttint)
1.R8P0RTN0. 3.
EPA- 600/9- 85-0 20b
X RECIPIENT'S ACeiSSIOWNO.
4. titui ANosurriTui Proceedings: First Joint Symposium on
Dry SO2 and Simultaneous S02/NOx Control Technol-
ogies; volume 2. Power Plant Integration. Econo-
mics, -and Full-scale Experience
S. RSraRT OATS
July 1985
S. PtRPORMING ORGANIZATION COOS
7. AUTHOR
P. Jeff Chappell. Compiler
6. PtRPORMING OROANIZATION RSPORT NO.
a. psrpormino organization nami and aoorsss
A cur ex Corporation
955 Clyde Avenue
Mountain View, California 94039
10. PROGRAM f LSmJnT UQ.
CONTRACT/GRANT NO.
68-02-3993, Task 1
12. SPONSomtNa agsncv nams and aoorsss
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711
13. TYP* OR RSPORT ANO PCRIOO COVSRSO
Proceedings; 10/84-4/85
14. SPONSORING AOSNCV COOS
EPA/600/13
li. «uw.«m«nta.,v notm aeerl project officer is P. Jeff Chappell. Mail Drop 63. 919/
541-3738. Volume 1 is fundamental research and process development.
1* amtkact
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