United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
Research and Development
EPA-600/S7-81-039 Aug. 1981
Project Summary
Control of Utility Boiler and
Gas Turbine Pollutant
Emissions by Combustion
Modification—Phase II
E. H. Manny and A. R. Crawford
This report describes the status of
an EPA-sponsored field study of NO,
emissions from coal-fired utility
boilers. Previous reports (1, 2, 3.)
discussed the effectiveness of com-
bustion modification techniques to
significantly reduce NO, emissions.
The simultaneous investigation of side
effects (e.g., particulate emissions,
boiler slagging, boiler performance)
did not identify any significant
problems. However, one potential
side effect—fireside corrosion of the
boiler waterwalls— was only partially
studied. Fireside corrosion rates
obtained via probes (short-term ex-
posure) could not be correlated con-
clusively with actual furnace tube
wastage experience. Therefore, a
long-term corrosion test was undertaken
to obtain representative furnace tube
corrosion rate data. Also information
is included on a field test using addi-
tives to suppress slag formation in a
330-MW pulverized-coal-fired utility
boiler.
This Project Summary was devel-
oped by EPA's Industrial Environmen-
tal Research Laboratory, Research
Triangle Park. NC. to announce key
findings of the research project that is
fully documented in a separate report
of the same title (see Project Report
ordering information at back).
Introduction
Exxon Research and Engineering
Company (ER&E) under contract to EPA
has been conducting field studies since
1970 on combustion modification tech-
niques to control NO* and other pollutant
emissions from utility boilers. In early
studies significant reductions of N0«
were achieved in gas- and oil-fired
boilers under EPA contract CPA 70-90
(1) without optimizing the technology. In
a follow-up investigation, emphasis
shifted to the more difficult task of
controlling NO* emissions in pulverized-
coal-fired boilers and the assessment of
potential side effects. Twelve coal-fired
boilers were tested under EPA Contract
68-02-0227 (2) in cooperation with
boiler owner-operators and boiler
manufacturers. In this study reductions
in NO, emissions averaging 39 percent
(ranging from 12 to 59 percent) were
achieved with no apparent adverse side
effects. In addition to the optimization of
NO, emissions, the study included
particulate and unburned combustible
measurements, furnace corrosion rate
probing, determination of boiler effi-
ciency, and observations on changes in
boiler operability; e.g., slagging, fouling,
flame impingement, or instability.
In the current program, co-sponsored
by EPA (Contract 68-02-1415) and the
Electric Power Research Institute (EPRI
-------
Project No. 200), five coal-fired and two
mixed-fuel -fired (coal/oil, coal/gas)
boilers were tested in the Phase I
program (3). Four coal-fired boilers, two
gas turbines, and one oil-fired boiler
were tested in the Phase II program. The
scope of the program was broadened
under these contracts to explore the
effectiveness of equipment modifica-
tions designed for NO, control; e.g.,
boilers constructed with overfire air
ports and use of low-NO, improved-
burner designs. NO, emissions in the
coal-fired boilers tested were reduced
by 34 percent in the Phase I program
and by 38 percent in Phase II. Potentially
adverse combustion-modification side
effects (e.g., increased particulate mass
and reduced size distribution, poorer
boiler performance and operability,
increased furnace tube corrosion)
received increased emphasis and were
studied in more detail than in previous
studies. Since combustion modifications
for NO, control potentially may increase
slagging in boilers, as part of this
program tests were conducted with
promising results using additives to
suppress slag formation in a coal-fired
boiler.
Furnace tube corrosion, which may
be aggravated by low-NO, operation, is
a potential major side effect. Data
developed in past programs with cor-
rosion probes, however, could not be
conclusively related to actual furnace
tube corrosion. The importance of this
problem dictated a major effort to spe-
cifically address this question. An ex-
tensive long-term corrosion study was
undertaken to obtain corrosion rates on
actual furnace tubes.
Test Program Update
Details of test program designs,
gaseous sampling and analysis, partic-
ulate, SO,, corrosion rate, and boiler
performance measurements and calcu-
lations have been covered in prior
reports (1, 2, 3, 4). This report updates
work performed under EPA Contract 68-
02-1415 and Electric Power Research
Institute Project No. 200. Field tests
conducted under this program were
carried out in Phases I and II. Phase II,
covered by this report, updates the
program covering field tests on four
coal-fired and one oil-fired boiler with
special emphasis on the long-term
corrosion test conducted on Gulf Power
Company's Crist Station boiler No. 7.
Nitrogen Oxide Emissions
Field tests conducted in the Phase I
program are summarized in Table 1 for
record and comparison purposes. In-
cluded in the table are details concerning
the boiler manufacturer, the type of
firing, kind of fuel burned, number of
burners, test variables, number of tests
run, and emission data for baseline and
optimum low NO, operation on each
boiler tested. Table 1 shows that un-
controlled (baseline) emissions ranged
from 341 to 1383 ppm with only four out
of the seven boilers tested meeting the
New Source Performance Standard
(NSPS) of 0.7 Ib N0,/106 Btu. Three of
these, Barry No. 2, Navajo No. 2, and
Comanche No. 1 were equipped with
overfire air ports; the fourth, Gaston No.
1, had been retrofitted with B&W's
dual-register low-NO, burners. Note
that application of combustion modifi-
cation techniques successfully reduced
emissions below the revised NSPS of
0.6 Ib NOx/108 Btu in all cases but two
(Mercer No. 1 and Widows Creek No. 5),
and even Widows Creek No. 5 could
meet the original standard. NO, reduc-
tions ranged from 22 to 45 percent,
averaging 34 percent commensurate
with reductions achieved in prior pro-
grams (1, 2).
Results of Phase-ll field tests are
given in Table 2. Table 2 shows that
baseline emissions in the four coal-fired
boilers tested, ranging from 533 to 827
ppm, did not meet the original NSPS of
0.7 Ib N0,/106 Btu. Under low NO,
firing conditions, however, two coal-
fired boilers (Cooper No. 2 and
Comanche No. 2) met the new NSPS of
0.6 Ib N0,/106 Btu. There is little doubt,
however, that Mill Creek No. 1 boiler
could have met both NSPS requirements,
but low NO, firing was not applied to the
unit during the additive tests due to a
lack of time. Average NO, reductions
were 38 percent in the coal-fired boilers
tested, ranging from 22 to 62 percent.
This is consistent with NO, reductions
achieved in Phase I and earlier programs
(1,2,3).
Emissions reductions obtained in
boilers representative of the utility
boiler population and in various current
design configurations complying with
recent low-NO, requirements or guar-
antees have been discussed and pub-
lished elsewhere (1, 2, 3, 4). NO, emis-
sion reduction and optimization achieved
on the boiler No 7 at Gulf Power Com-
pany's Crist Station, which was selected
for long-term corrosion testing, is
presented here to illustrate slight]
different applications of combustidj
techniques.
Crist Station Boiler No. 7 is a hori
zontally opposed fired, dry-bottorr
single-furnace Foster Wheeler boile
rated at 500 MW capacity. This unit wa
selected for testing because it is a large
pulverized-coal-burning unit of moder
design capable of operation wit
burners out of service for staged com
bustion. It also appeared to have th
necessary operating flexibility an
management support so that it was
good candidate for the Phase IV, long
term corrosion test program. Th
furnace is 52 ft 5 in. wide and 40 ft deef
Six pulverizers feed 24 burners arrange
in three rows of four burners each in th
front and rear walls of the furnace.
The operating variables found to hav
a statistically significant influence oi
NO, emission levels were load, exces
air level, and firing patterns. Figure
indicates the most important relation
ships found in analyzing the test data
The numbers in the symbols indicati
the run numbers, while the symbol
indicate the various firing patterns tested
The lines in Figure 1 are least-square!
linear-regression lines for ppm NO
vs.% oxygen calculated for each firirv
pattern. *
The strong influence of excess ai
level on NO, emission levels for all firing
patterns is indicated by the steep slope!
of the lines in Figure 1. Very closi
agreement was found in the calculate<
regression coefficients (change in ppn
NO, for a 1 percent change in oxygen
for the various firing patterns; i.e., 69
80, 81, 59, and 76 for firing patterns Si
S2, S3, S6, and S7, respectively. Sine*
excess air levels could be reduced by ai
much as 5 percent from normal t<
achieve low excess air operation, with
out violating the 200 ppm CO maximun
emission Jevel guideline or increasing
stack plume opacity, this represents ar
important operating variable for NO
emission control. Thus, under full loac
baseline operation (480-510 MW) NO
emissions were reduced by 16 percen
by changing from a baseline operatior
(4 percent 02) of 827 ppm NO, to 69<
ppm NO, under low excess air (2.1
percent O2) operation.
Reducing load by 62 percent from th<
480 to 510 MW range to 190 MW unde
normal excess air firing operatior
lowered NO, emissions by about 3"
percent. Staged firing generally resultec
in reduced loads as well as reduced NO
-------
Jablo 1 . Summary of Coal- and Mixed-Fuel-Fired Boilers Tested During Phase 1
Boiler Operator
Tennessee Valley
Authority
Southern Electric
Generating Company
Alabama Power Company
Potomac Electric
Power Company
Salt River Pro/act
Public Service Company
of Colorado
Public Service Electric
and Gas Company
Average of Coal Fired Boilers
Station and
Boiler No.
Widows Creek - 5
f.C. Gaston - 1
Barry - 2
Morgantown - 1
Navaio - 2
Comanche - t
Mercer - 1
Boiler
Mir. (a)
B&W
BSW
CE
CE
CE
CE
FW
Type of
Firing/hi
aw
HO (el
T(fl
T
Tffl
Till
FWfgl
Fuel(cl
Burned
C
C
CG
CO
C
C
C
MCR
/MWel
125
270
130
575
800
350
270
No of
Burners
16
18
16
40
56
20
24
Test
Variables
4
5
6
5
4
4
4
Ho. of
Test
Runs
3t/dl
37(d>
38
27
36(dl
30
-
-
20
24
Test
Variables
4
3
Ic)
5
2
2
4
No. of
Test
Runs
101
IcXd)
18
24
16
13
(cl
158
(cXdl
92
NO, Emissions
Baseline
ppm (lb/10* Btul
""557(0.761
726 (1.OOI
311 (0.401
212 (0.291
382 (0.45)
533 (0 711
827 (1 1)
661 (0.881
Low NO,
ppm (Ib/ 10s Btul
M433 (0.59)
278 (0.381
211 (0.271
34(0044)
40 (0.0481
M
570(0.76)
427(0.58)
% N0,(gl
Reduction
22
62
32
84
90
31
38
(al SAW - Babcock and Wilcox. GE - General Electric, Combustion engineering. FW - Foster Wheeler
(bl FW - Front Wall. HO - Horiiontally Opposed. T - Tangential
(cl Paniculate tests performed on these boilers
(d) Corrosion probe tests performed on this boiler
(el Overfire air ports
(fl Water in/action
(gl % NO, reduction of full or near full load
(hi PPM NO, -3%O*dry basis
(il Additive test at baseline conditions only
emission levels. Separating the effect of
staged firing on NO, emission levels
from the load effect indicated the follow-
ing. Staged firing operation, Sz, top
burners fired lean (by reduced coal flow
to top row of burners) and normal
excess air (4 percent 02) resulted in a 12
percent reduction in NO, emissions
(827 ppm to 728 ppm) with about 5
percent due to load reduction (496 to
451 MW average) and'the remaining 7
percent due to staged firing. Staged
firing operation, 83, (1 top mill on air
only) resulted in a 39 percent reduction
in NO, emissions (to 509 ppm from 827
ppm) with about 12 percent due to load
reduction and 27 percent due to staged
firing. Finally, S8, staged firing with both
top mills on air only, produced a 72
percent NO, emission reduction with
about 32 percent due to reduced load
(230 MW vs. 495 MW). Part of the load
reduction experienced during the test
period, however, was due to abnormal
operating difficulties such as partial air
heater plugging.
The combined effect of low excess air
and staged firing operation resulted in
further NO, emissions reductions, as
would be expected. Thus, the ppm NO,
levels (and percent NO, reduction from
the 827 ppm measured under baseline
operation) were 451 (-31 percent), 400
-------
900-
SOO-
700
600-
o
500 -
400-
300-
200
S \-Norma I Firing
(480-510 MW)
Sz-Top Burners Lean
(430-470 MW)
S,-7 400 MW
Top Mill on Air
(390-420 MW)
87-2 Center Mills
on Air Only-J90 MW
Se-2 Top Mills
4567
A verage % Oxygen Measured in Flue Gas
Figure 1. PPM /VO« vs. % oxygen in Hue gas [Crist No. 7 Unit].
(-52 percent) and 244 (-70 percent) for
S2, 83, and Se staged firing patterns,
respectively. These results indicate that
this boiler has an excellent N0> reduc-
tion capability through modified com-
bustion operation.
Particulate Emissions and
Boiler Performance
Low-NOx combustion modification
techniques, especially staging the firing
pattern in combination with low excess
air firing, result in less intense com-
bustion conditions than conventional
firing methods. A tendency toward
increased burnout problems, therefore,
may occur which, potentially, could
increase paniculate mass loading as a
consequence of increased carbon in the
fly ash. In addition, these effects could
also result in changes in particle size
distribution. Changes in particulate
mass loading and particle size distribu-
tion could adversely affect collection
efficiency in electrostatic precipitators
or in other collection devices, while an
increase in unburned combustibles
could have a corresponding adverse
effect on boiler efficiency. A further
potential adverse side effect of low N0«
operation could be a change in fly ash
resistivity which might have a similar
adverse effect on precipitator collection
efficiency. Measurements of resistivity,
however, were beyond the scope of this
program.
Low-NOx combustion modification
effects on dust loading were investigated
using an EPA method 5 type sampling
train incorporating a Brink cascade
impactor for particle size distribution.
Total mass loading and particle size
distribution were measured under
baseline and optimized low-NOx oper-
ating conditions upstream of the elec-
trostatic precipitators. In the latter
phase of the contract, dust loading was
measured with EPA's Source Assess-
ment Sampling System (SASS) train.
SASS train samples from East
Kentucky Power Cooperative, Inc. and
Public Service of Colorado power plants
were analyzed for metals, PNA's, and
anions. The analytical results showed
that the low NOX operating conditions at
the Colorado plant did not significantly
reduce all metallic emissions.
PNA concentrations were all below
the requested 2 (ig/m3 levels. However,
low amounts of PNA's were present
(0.1 -0.8 /ug/m3) on the particulate
samples from the Kentucky plant. Poor
PNA extractability precluded accurate
analysis of the 10/Lim cyclone samples.
At the P.S. Company of Colorado plant,
lower anion concentrations were ob-
tained from particulate samples while
higher values were detected on the
condensate samples for the low-NO* op-
eration than during baseline operation.
Particulate emissions and particle
size distribution for boilers tested in the
Phase II program are summarized in
Tables 3, 4, and 5. Comparing partic-
ulate mass loading data in Table 3 for
baseline against low NO, operation,
shows that mass emissions under low-
NO, firing conditions, for the tests in the
Phase II program, are essentially the
same as for baseline operation, requiring
little or no change in electrostatic
precipitator collection efficiency. Tables
4 and 5 show that low-NOx operation
has very little, if any, effect on particle
size distribution. Aside from potential
changes in resistivity, therefore, these
data indicate, as in Phase I and prior
programs, that there are no significant
differences in particulate mass loading
or particle size distribution under now
N0« combustion conditions.
Increases in percent carbon on par-
ticulate are noted for Iow-N0x firing
conditions in Table 3 which do not seem
to have a corresponding direct effect on
mass emissions. Furthermore, the ex-
pected decrease in boiler efficiency
(Table 6) not only failed to materialize,
but (for the low-NOx conditions effi-
ciency), if anything, is even greater by a
small margin, indicating that low-NO,
firing has only insignificant effects on
boiler performance.
-------
Table 3. Particulate Emission Test Results
Emissions
Utility
East Kentucky
Power Cooperative, Inc.. Cooper
Station. Boiler No. 2
Public Service Electric A Gas
Company
Sawaren Station Boiler No. 5
Gulf Power Company. Crist
Station, Boiler No. ?
Data
3/9/77
3/11/77
3/26/77
3/28/77
9/17/76
9/17/76
6/20/78
6/21/78
6/22/78
6/23/78
Test
No.
41 '
43
59
60
4D
6C
160
161
152
163
Firing
Condition
Base*
Base'
Low NO,'
Low NO,'
Base"
Low NO,"
Base-
Low NO,'
Base'
Low NO,'
Load.
MW
178
155
123
123
288
280
436
432
417
434
mg/rr?
1.06
0.72
0.78
0.87
0.0059
0.0063
0.686
0.874
0.864
0.909
gr/scf
4.6S
3.12
341
3.82
0.026
0.0274
3.00
3.82
3.78
3.97
Ib/irf
ng/J Btu
3280 7.63
2361 5.49
2520 5.86
3/30 7.28
17.2 0.04
17.2 0.04
2301 5.35
1926 4.48
2881 6.70
2468 5.74
Req. EH.
To Meet
0. 1 It/
10* Btu
98.7
98.2
98.3
98.7
-
98.1
97.8
98. S
98.3
%
Carbon
On
Paniculate
1.48
094
1 81
1.87
-
2.98
0.87
1.71
Coal
Ash
Wt %
1278
1248
11.30
10.47
-
12.45
16.48
14.32
HHV. Wet,
Cel/gBtu/lb
11.742
12.217
12.312
12.291
~
11.263
10.782
11.033
'Pulverized coal tiring.
"Oil firing.
Table 4.
Particle Size Distribution, Wt% East Kentucky Power Cooperative
Cooper Station - Boiler No. 2 Pulverized Coal Firing
Baseline Firing
Low NO* Firing
Size
Range, um
>2.5
2.5
1.5
1.0
0.5
<0.5
Test No.
41
98.86
2.04
0.50
0.41
0.63
0.36
Test No.
43
92.68
3.71
1.24
0.95
1.13
0.62
Average
95.8
2.9
0.9
0.7
0.9
0.5
Test No.
59
95.65
3.28
0.78
0.61
1.04
0.67
Test No.
60
91.75
5.34
1.32
1.07
1.65
1.11
Average
93.7
4.3
1.1
0.8
1.4
0.9
Tables.
Particle Size Distribution, Wt% Gulf Power Company Crist Station -
Boiler No. 7 Pulverized Coal Firing
Baseline Firing
Low NO* Firing
Size
Range, urn
>2.5
2.5
1.5
1.0
0.5
<0.5
Test No.
150
93.10
2.15
0.90
0.83
1.24
1.80
Test No.
152
94.00
3.48
0.72
0.84
1.20
0.72
Average
93.6
2.8
0.8
0.8
1.2
1.3
Test No.
151
92.50
3.15
1.12
0.83
1.16
1.24
Test No.
153
89.80
3.68
1.94
1.43
1.84
1.33
Average
91.2
3.4
1.5
1.1
1.5
1.3
Anti-Slagging Additive Tests
Low-No, combustion modifications,
especially staged firing in combination
with low excess air operation, can result
in lower net reducing atmospheres in
the bottom of the furnace, often accom-
panied by higher temperatures. Under
reducing atmosphere, coal ash fusion
temperatures generally are about 200°F
lower than for oxidizing conditions. This
fact, coupled with higher furnace tem-
peratures, can affect the character of
the slag formation, making them more
fluid and sticky with potentially greater
slagging difficulties. For boilers operating
near incipient slagging conditions, the
application of NO, reduction techniques
could increase slagging.
Part of the Phase II program was
devoted to investigating ways to control
increased slagging if this problem
occurred when applying NO, control
modifications. The potential use of
additives gave promise of being the
most cost effective solution to control or
ameliorate slagging conditions in coal-
fired boilers. Accordingly, arrangements
were ma*de with Basic Chemicals and
the Louisville Gas and Electric Company
Table 6. Summary of Boiler Performance Calculations
East Kentucky
Power Cooperative
Inc. Cooper
Station
Gulf Power
Company,
Crist Station
Boiler
No.
2
2
2
2
7
7
7
Firing
Mode
Baseline
Baseline
Low NO*
Low NO*
Low NO*
Baseline
Low NO*
Test
No.
41
43
59
60
151
152
153
Load
MW
178
155
123
123
432
417
430
Coal
NO* Emissions, Ash, %
% (3% Oa) (Wet
Oa
4.2
5.4
5.0
6.6
3.1
5.5
1.9
PPM
612
574
381
490
508
848
456
lb/10° Btu
0.82
0.77
0.51
0.65
0.68
1.13
0.61
ng/J Basis)
351 12.37
329 12.76
218 11.30
281 10.41
291 12.45
486 16.48
261 14.32
% Carbon
on
Paniculate
1.48
0.94
1.81
1.87
2.98
0.87
1.71
Boiler
Efficiency, %
89.82
90.12
90.44
90.36
88.92
88.86
89.27
-------
to conduct cooperative tests on LG&E's
Mill Creek Station boiler No. 1. Rated
output of boiler No. 1 is 325 MW, but
LG&E had arbitrarily derated the unit to
300 MW in order to keep slagging
conditions within manageable bounds.
Eight tests were run in June 1979:
four without additive injection to develop
"baseline" operating information, and
four while injecting Basic Chemicals
UltraMag additive, an ultra fine «2fjm)
dispersion of MgO in heating oil.
Additive was injected at three different
rates at each of the four corners of the
furnace at two different slag blower
elevations immediately above the top
burners. Boiler loads of 325-330 MW
were maintained during the tests,
sufficient to promote slagging. The
effectiveness of the additive was judged
by the length of time that the load could
be maintained at this level before
operating parameters became critical
forcing a cutback in load.
Results of the anti-slagging additive
trials are summarized in Table 7. Table 7
shows that tests 200, 201, and 203
(baseline - no additive) achieved 12
hours operation at full load, rated
conditions (325-330 MW) before
superheat and reheat steam temper-
atures bordered on uncontrollability.
Note test 202 (no additive), however,
where the boiler was slagged to the
point of being out of control in 4-1/2
hours, a very short period. The reasons
for this drastic performance were not
readily apparent but may possibly be
attributed to the fact that furnace
cleanup prior to the test may not have
been as effective as before or that a
change to a higher slagging coal may
have occurred for that day.
In tests 204 and 205 additive was
injected continuously at the rate of 15
gph. Table 7 shows that full load
capability of the boiler could be
maintained under these conditions for
15 and 17 hours, respectively, or 3 and 5
hours longer than without additive
injection. These results testify to the
technical feasibility and effectiveness of
the use of additives at low injection
rates with pulverized-coal firing. Other
potential benefits, which were beyond
the scope of these investigations, may
also accrue from additive usage; e.g.,
easier cleanup of the boiler during
nightly reduced-load periods; e.g., it
may not be necessary to reduce load as
much and the clean-up period may
possibly be shortened to achieve the
same degree of cleanliness. Load-
carrying capabilities, which are of
Table?. Summary of Anti-Slagging Additive Test Results
Test
No.
200
201
Hours @
Full Load Oa, NOxppm Test
Date Time (325-330 MW) % (3% Oa) Condition
6/11/79 07:27
13:53
16:16
19:27
6/13/79 10:00
11:06
15:36
22:00
Start
End
Start
End
r_ 5.0 584
* 5.3 599
„ 4.7 512
1£ 5.2 566
Baseline
(No Additive)
Baseline
(No Additive)
202 6/14/79 10:00 Start
13:18 \ 4.5 5.0 557 Baseline
*14:30 End > (No Additive)
16:15 LoadCut \
Back
203 6/18/79 07:00 Start \ Baseline
08:16 I 4.8 448 (No Additive)
13:45 } 12 4.8 479
15.58 \ 4.9 517
19:00 End )
204 6/20/79 07:10 Start \ Additive
09:26 I 4.5 447 (15 gph)
13:35 > 15 4.6 473
16:00 \ 4.6 572
22:20 End )
205 6/21/79 08:15 Start \ Additive
09:38 ( 5.3 514 (15 gph)
13:00 > 17 5.3 534
15:35 \ 5.7 581
01:15 End /
206 6/25/79 09:00 Start I ,, _ _ Additive
21:00 End ) (7.5 gph}
207 09:30 Start \ IA _ _ Additive
23:10 End ) '* (15 gph
Slugs)
* Superheat/reheat sprays max. @ 14:30.
special importance in tight load-
demand situations, therefore could be
improved.
Tests 206 and 207 were run in an
attempt to optimize the additive injection
rate and to test the effectiveness of
other injection methods. Neither result,
however, was quite as effective as
injecting the additive continuously at 15
gph.
These tests indicate that anti-slagging
additives may be effective in controlling
or ameliorating slagging problems in
pulverized-coal-fired utility boilers,
especially when low-NO» combustion
modifications may be employed. The
degree of slag reduction.the benefits of
increased load-carrying capability, the
optimum rate, and the most effective
injection method, however, need to be
defined in more extensive testing to
shed more light on the economics and
technical feasibility of additive usage for
this purpose.
Corrosion Probe Investigations
Corrosion probes with exposed
coupons provide a relatively simple,
quick, and economical means for de-
termining corrosion rates. Even though
corrosion rate data developed in these
and previous programs could not readily
be related to actual furnace tube ex-
perience, relative comparisons could be
made. This type of measurement was
continued in the long-term corrosion
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investigations with the objective of
eventual correlation with rates devel-
oped by ultrasonic measurement of
actual furnace tubes and from exposure
of furnace tube test panels.
Corrosion probe testing on Gulf Power
Company's Crist Station boiler No. 7
was amplified extensively in order to
obtain more data and information on the
effect of corrosion with time. Conditions
of exposure were maintained the same
as in prior testing, simulating actual
furnace tube environment. However,
coupon exposure was varied from 30 to
1000 hours under both baseline and
low-NOx conditions to determine initial,
intermediate, and longer term corrosion
effects. In previous tests, coupons were
normally exposed for 300 hours. In
addition, special ports were installed in
the furnace for the installation of the
probes in the most desirable areas. Two
of these ports were in the middle of the
sidewalls, the burner zone (elevation
129.8 ft), in the most corrosion-prone
area; two others were in the middle of
the sidewalls, but in the upper furnace
area (elevation 157.8 ft), outside of the
expected corrosion area, in order to
provide control data.
A comparison of corrosion rate data
developed using boiler No. 7 is best
illustrated in Figure 2, showing a plot of
corrosion rate vs. exposure time for
probes exposed to both baseline and
low-NOx firing conditions. Figure 2
shows that coupon corrosion rates
decrease with exposure time asymoti-
cally up to a 1000-hour exposure. Initial
corrosion rates developed at 24 to 30
hours exposure are high with consider-
able scatter in the data. At 250 to 300
hours exposure, corrosion rates are
much lower and more consistent in
range. Above 450 to BOO hours exposure,
corrosion rates level out to an average
rate of 10 to 12 mils/year with very little
scatter in the range of the data. These
rates, however, are still much higher
than the 1 to 3 mil/year wastage expected
in actual-furnace wall tubes.
These corrosion probe investigations
indicate that:
• There are no major differences in
corrosion rates for probes exposed
to low-NO, vs. baseline firing con-
ditions, especially for exposure
exceeding 450 hours.
• Corrosion rates developed via cor-
rosion probes decrease with expo-
sure time through TOOO hours
approaching an asymtote above
450 hours exposure.
140
120
100
tf 80
I
° 40
20
Legend
a Low /VOx
o Base Data
0 100 200 300 400 500 600 700 800 900 1000
Exposure Time, Hours
Figure 2. Comparison of corrosion rates Gulf Power Company, Crist
Station, Boiler No. 7, pulverized coal firing.
• Corrosion probes exposed for short
terms (up to 30 hours) within the
burner areas in the furnace side-
walls experience significantly
greater corrosion rates than probes
exposed outside the burner levels
under low-NOx firing conditions. A
similar trend is indicated for base-
line operating conditions, but more
data is needed to reach firm con-
clusions.
• Probes exposed for periods of 300
to 1000 hours experienced no
significant differences in corrosion
rates due to furnace location
(burner vs. nonburner area) or
furnace operating mode (baseline
vs. low-NO, firing).
• Effective correlation of actual long-
term furnace tube corrosion rates
requires corrosion probe exposure
of a minimum of 450 hours.
References
1. Bartok, W., Crawford, A.R., and
Piegari, G.J., "Systematic Field
Study of NO, Control Methods for
Utility Boilers," Esso Research and
Engineering Company Report GRU.
4G.NO. 71 (EPA No. APTD 1163,
NTIS No. PB 210739), December
1971.
2. Crawford, A.R., Manny, E.H., and
Bartok, W., "Field Testing: Application
of Combustion Modifications to Con-
trol NOx Emissions from Utility
Boilers," Exxon Research and
Engineering Company (EPA-600/2-
74-066, NTIS No. PB 237344), June
1974.
3. Crawford, A.R., Manny, E.H., and
Bartok, W., "Control of Utility Boiler
and Gas Turbine Pollutant Emissions
by Combustion Modifications -Phase
I," Exxon Research and Engineering
Company (EPA-600/7-78-036a,
NTIS No. PB 281078), March 1978.
4. Manny, E.H., Crawford, A.R., and
Bartok, W., "Field Testing of Utility
Boilers and Gas Turbines for Emission
Reduction," in Proceedings of the
Third Stationary Source Combustion
Symposium; Volume I. Utility, Indus-
trial, Commercial, and Residential
Systems, EPA-600/7-79-050a (NTIS
No. PB 292539), February 1979,
pages 157-198.
« U& aOVERNMCNT PMNTMO OFFICE 1«1 -757-012/7293
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£. H. Manny and A. R. Crawford are with Exxon Research and Engineering
Company, P.O. Box 101. Florham Park, NJ 07932.
Robert E. Hall is the EPA Project Officer (see below).
The complete report, entitled "Control of Utility Boiler and Gas Turbine Pollutant
Emissions by Combustion Modification-Phase II," (Order No. PB81-222 267;
Cost: $15.50, subject to change) will be available only from:
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at:
Industrial Environmental Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
United States
Environmental Protection
Agency
Center for Environmental Research
Information
Cincinnati OH 45268
Postage and
Fees Paid
Environmental
Protection
Agency
EPA 335
Official Business
Penalty for Private Use $300
PS
PS 00003M T£
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