United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
*
Research and Development
EPA-600/S7-81-078 Mar. 1983
Project Summary
Continuous Emission
Monitoring at the Georgetown
University Fluidized-Bed Boiler
Charles W. Young, Edward F. Peduto, Peter H. Anderson, and Paul F. Fennelly
The report gives results of a con-
tinuous emission monitoring program
for SO2. NO«, and paniculate matter at
Georgetown University's 100,000 Ib
steam/hr fluidized-bed boiler, to
assess emissions control performance.
Because the system was still in an
extended shakedown phase, several
key operating conditions (e.g., level of
excess air, percent flyash recycle)
were not operating in the intended
design range. Consequently, an in-
depth engineering analysis was neces-
sary to interpret the emission data. On
a daily average basis desulfurization
was > 75% on all 24 days of record, >
85% on 12 days, and > 90% on 8 days.
Although NO, emission rates were
higher than 301 ng/J approximately
half the time, they were shown to
correlate with the flue gas 02 levels,
typically in the off-spec range of 10-
12%. Average particulate emission
rates for the 2 days of record were
36.5 and 24.3 ng/J. Implementation
of recommendations resulting from
the program are in most cases complete
or in progress, and are leading to
improved emission performance.
This Project Summary was developed
by EPA's Industrial Environmental
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
The objective of this study is to
describe the emissions control per-
formance for SO2, NOx, and particulate
matter for the Georgetown University
fluidized-bed boiler (FBB), with emphasis
on the relation of emission rates to
boiler operating variables. This report is
a preliminary assessment of the George-
town FBB performance, and is based on
measurements made during August
and September 1980. A follow-up
program was conducted in February and
March 1982, results of which will also
be published. Fluidized-bed combustion
(FBC) of coal is a promising technology
for low SO2and NO*coal-fired industrial
steam generation. The 100,000 Ib
(45,450 kg) steam/hr demonstration
FBB at Georgetown University in the
District of Columbia is the largest
operational application of atmospheric
FBC of coal using a limestone bed for
SO2 capture. Because FBC technology
has the potential to become an econom-
ically and environmentally competitive
technology for coal-fired industrial
steam generation, the emissions control
performance of the Georgetown FBB is
of significant interest to potential users
of FBC as well as to research and
development officials of the U.S. EPA.
Although much emission data exist
for FBC technology, they result mostly
from short-term testing on bench and
pilot-scale units. Because the George-
town FBB is a fully operational unit in
the same capacity range as many
industrial steam generators, it offers
one of the first opportunities to obtain
long-term emission control data for a
coal-fired FBB. Additionally, long-term
continuous emission monitoring data
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on the order of 1 month for S02 and NOX
are necessary to build a data base that
adequately describes the generic emis-
sion performance capabilities for FBC
industrial steam generation. This type of
data base is important to EPA in the
development of New Source Performance
Standards for industrial boilers. Due to
the lack of full-scale operating units, the
present data base for FBC technology is
insufficient to support the current round
of industrial boiler standards develop-
ment by identifying FBC as an alternative
coal-fired steam generation technology.
The evaluation program at the George-
town FBB is designed to provide the type
of continuous emission monitoring data
utilized in standards development.
Furthermore, the results of this moni-
toring program have been compared
with three emission levels that have
been proposed as being representative
of stringent, intermediate, and moderate
levels of control for SOa, NOX, and
particulate emissions for coal-fired
industrial boilers.1
The continuous emission monitoring
(CEM) program at the Georgetown FBB
was conducted from August 19,1980 to
September 18, 1980. During this
period, 23 days of continuous S02
emission data and 24 days of continuous
NOX emission data were obtained.
Additionally, particulate emissions
were measured at the stack in triplicate
sets on 2 days during the test program.
The test program was designed to
concurrently measure a number of
boiler operating variables (e.g., percent
flue gas Oz, calcium to sulfur molar feed
ratio, bed temperature, and gas-phase
residence time). The discussion of
emission results focuses on relationships
between these operating variables and
emission rates. This analysis is an
important part of the study because the
boiler did not always operate according
to design conditions and, therefore,
performance was not necessarily typical
of that expected in the future at
Georgetown, or in general commercial
applications of FBC.
The Georgetown FBB burns coal of
low to medium sulfur content and has a
rated capacity of 100,000 Ib/hr steam.
Limestone is added to the bed for SO2
control, and fabric filters are used for
final particulate control. FBC provides
inherent control of NO* emissions
through low combustion temperature,
approximately 843°C (1550°F), which
practically eliminates thermal NOX
formation and provides a favorable
atmosphere for chemical reduction of
fuel-derived NOX. Operation of the
Georgetown FBB is one of the most
successful and largest applications of
FBC of coal in the U.S. The facility has
demonstrated reliability in following
steam demand for University heating
and air conditioning. The boiler performed
two continuous runs of about 15 days
each during the preliminary monitoring
program in August and September
1980. Soon after completing the moni-
toring program, a continuous run of
about 30 days was achieved.
Monitoring Program
The CEM system used for this program
was the on-site system installed and
operated by the Georgetown University
Physics Department. This is an extractive
system that continuously analyzes flue
gas emissions to the atmosphere. Flue
gas is extracted through a sintered
probe filter and is transported to an
instrument shelter, through heat-traced
Teflon tubing. Inside the instrument
shelter, the sample stream passes
through a pump and is then split into
two streams: one passes through a
combined dilution/conditioner system;
the other passes through a condensation
system. Table 1 lists the instrument type
and the mode of sample conditioning
required for each gas species analyzed.
SOz and NOXsample streams are diluted
with air by a factor of 10 to 1. Dilution
reduces the moisture level of the
sample stream by a factor of 10 and
provides a constant sample matrix (i.e.,
constant Oz and C02 concentration) that
simplifies data interpretation in the S02
analyzer and eliminates possible fluo-
rescence quenching. The CEM system
monitors levels of CO, COz, and 02
directly without sample dilution. These
sample streams are conditioned by
filtering particulate through a coarse
probe filter and backup fiber filters.
Moisture is removed by a condenser
coil. Calibration gases are injected at
the probe interface connections through
a motorized three-way ball valve. This
injection point allows calibration gases
to flow through the entire CEM system
(except for the probe and stack filter).
Calibration gas can also be injected
directly into the analyzer; but this was
not done during the test program.
Individual strip chart recorders provided
a permanent copy of continuous emis-
sions of SOz, NO* CO, Oz, and CO2. The
Oz measurement was used to compute
diluent volume and emission rates, as
opposed to COz, to avoid error introduced
by COz production during limestone
calcination.
Before initiation of data collection, the
continuous monitoring system was
subjected to the performance tests in
the October 10,1979, Federal Register.2
These tests, a proposed revision to
Appendix B of 40 CFR Part 60, were
conducted since the emission data are
to be used in building a data base that
would eventually support proposed new
source performance standards. Future
monitoring requirements specified
under any new emission regulations
would also probably incorporate use of
these monitoring requirements. The
performance specifications quantify
short- and long-term drifts, system
hysteresis (calibration error), total
system response time, and accuracy of
the system relative to the applicable
reference method. EPA Reference
Methods 3, 6, 7, and 10 are the
applicable reference methods for Oz,
SOz, NOx, and CO that were used during
the relative accuracy tests. The relative
accuracy portion of the performance
tests was repeated during data collection
to check the continued accuracy of the
system and to provide additional data
calibration. In general, the monitoring
Table 1. Gas Analyzers for
System
Georgetown FBB Continuous Emission Monitoring
Species
analyzed
SOz
/VO,
CO
COZ
Oz
Monitor
type
Pulsed
fluorescent
Chemi-
luminescent
NDIR*
NDIR*
Electro-
chemical
Conditioning
principle
Filtration/
dilution
Filtration/
dilution
Filtration/
condensation
Filtration/
condensation
Filtration/
condensation
Instrument
range
0-100 ppm
0-100 ppm
0-1000 ppm
0-20%
0-25%
Measuring
range
0-1OOO ppm
0-1000 ppm
0-10OO ppm
0-20%
O-25%
"Nondispersive infrared.
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system performed adequately. Because
of potential problems with condensate
in the sample line and subsequent
intermittent reduction in flow to the
instruments from plugged capillaries,
daily multiple-span calibration checks
were made, as well as daily purging of
condensate traps and replacement of
secondary particulate filters. Passing
the calibration gases through the entire
system ensured quality control on data
validity.
Flue gas particulate concentrations
were determined atthestackduringtwo
test periods using EPA Reference
Method 5. During each test period,
three replicates were performed, each
set constituting one test run. Each
replicate test was conducted by travers-
ing through the existing ports on the
third stack sampling level, a location
conforming to the sampling location
criteria specified in EPA Method 5.
Twelve traverse points were sampled
for 5 minutes each, for a total sampling
time of 1 hour replicate test.
Coal samples were collected at the
spreader stokers for subsequent deter-
mination of ultimate and proximate
analysis. Limestone samples were
collected at the weigh belt feeders to
each bed for subsequent analysis of Ca
content. In addition to several daily
composite samples of each material,
hourly coal samples were taken for 7
days, and hourly limestone samples
were collected for 2 days.
Coal sulfur concentration and heating
value were used to compute boiler inlet
SOa loading in ng/J. This was used in
conjunction with flue gas SOa to
compute SOa reduction efficiency. Coal
sulfur concentration was also used with
limestone calcium concentration to
compute Ca/S molar feed ratios for
comparison with SO2 emission rates
and desulfurization efficiency.
A computerized data reduction system
was used to process the continuous
monitoring test data. Process operating
data, other than coal and limestone feed
rates, were taken from operator log
books and keypunched onto computer
cards. All emission rate and coal and
limestone feed rate strip chart data
were digitized to determine 15-minute
increments. These 15-minute averages
were used to calculate hourly and 24-
hour average emission rates.
Results
Because the system is in an extended
shakedown phase, several FBB operating
conditions affecting emission control
performance were outside intended
boiler design ranges during the con-
tinuous monitoring program. These
conditions and the associated design
values are:
• High excess flue 02: 10-12%
versus a 5% design.
• High limestone feed rates: Ca/S
ratios of 5-10 versus a 3 design.
• Ineffective fly ash reinjection.
• Torn and blinded fabric filter bags.
Analyzed either singly or in combina-
tion, these factors adversely impacted
emission control performance SOa,
NOx, and particulates, in terms of
emission reduction capability and/or
emission control cost effectiveness.
SOa Emissions
SOa removal efficiency was high,
averaging more than 85% (more than
90% about a third of the time). Except for
a few excursions on an hourly basis,
outlet SOa was usually significantly less
than 301 ng/J (0.7 lb/106 Btu), averaging
161 ng/J (0.37 lb/106 Btu},considering
all hourly average emission rate results.
Although SOa capture efficiency was
high and outlet SOa emissions were
low, limestone feed rates were high and
calcium utilization was low. Limestone
feed to the boiler was controlled
manually by the operator during the
program for two reasons: (1) the level of
one of the two beds in the FFB could not
be maintained without feeding limestone
in excess of that required for emission
control (it was later determined that high
particle elutriation was occurring in the
FBB because of injection of overfire air
near the top of the bed); and (2) because
of a problem with the feedback signal from
the in-bed SOa monitor, the boiler
operators adjusted the limestone feed
rate manually and on the basis of the
flue gas SOa level (this signal was
intermittently disrupted by the calibration
procedures and occasional monitor
maintenance). Also contributing to
higher-than-required Ca/S ratios was
that the coal sulfur content was found to
be 1.5-2.0%, which was lower than
expected. This was not apparent until
after completion of on-site activities
since results of the analysis of coal
samples taken during the program were
not immediately available. Because
limestone is fed on a mass basis relative
to coal (about 1:3), Ca/S ratios would be
abnormally high even in the absence of
atypical conditions already noted.
Overall, the Ca/S molar feed ratios
were found to be about 5-10, in contrast
to the design ratio of 3.
Figure 1 shows SO2 removal efficiency
as a function of Ca/S molar feed ratio
for 48 hourly average values for 3 days
during the continuous monitoring
program. These data are shown because
they represent days and hours for which
there are analyses of coal sulfur content
and heating value, and limestone
100
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• Day 240 hrs 10-20
° Day 255 hrs 1-24
* Day 256 hr 15 — Day 257 hr 14
Stringent
Intermediate
Moderate
8
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Ca/S Molar Feed Ratio
Figure 1. SOz emissions as a function of calcium to sulfur molar feed ratio.
3
10
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calcium concentration. This information
was used to calculate inlet and outlet
SOa, S02 control efficiency, and Ca/S
molar feed ratios. The S02 removal
efficiencies shown illustrate the expected
trend of increased removal efficiencies
at higher Ca/S ratios. Note: this effect
levels off at Ca/S ratios of about 5-6 and
S02 removal efficiencies of about 90-
95%.
Comparing the S02 removal efficien-
cies to the various emission control
levels described in reference 1 shows
that the moderate control level of 75%
removal was attained for all but one
hourly average shown. Also, the inter-
mediate and stringent levels were
supported consistently for Ca/S ratios
greater than 5. Note: even under the
adverse reinjection condition and
decreased gas phase residence time, a
moderate SC<2 emission standard of
75% removal could have been achieved
with a much lower limestone consump-
tion rate.
NOx Emissions
NOx emission rates were higher than
expected primarily because of high
levels of excess 02. Ineffective fly ash
reinjection may have also decreased
NOx control. During the 30-day CEM
program, flue gas 02 was 7-12%, as
opposed to a 5% design value. Because
of problems with the in-bed 02 monitor,
automatic control of combustion airwas
not used. Combustion air, controlled
manually by the operator, was held high
to avoid forming reducing zones in the
bed with attendant water-tube corrosion
problems. Two other sources of air
introduced to the FBB further complicated
the control of combustion air. Overfire
air could be injected in only two discrete
volumetric rates, and air introduced
through the eductors used to recirculate
flyash was not easily controlled or
measured.
The lower operating temperatures of
815-870°C used in FBC suppress
formation of thermal N0>. It is generally
considered that nearly all NOX from FBC
is derived from oxidation of fuel nitrogen.
It is also postulated that carbon char,
volatile fuel nitrogen species, CO, and
other reducing species play a role in the
chemical reduction of NO to molecular
N2. It is therefore not surprising that, at
very high excess O2 levels, these
reduction mechanisms would be sup-
pressed and NO emissions would
increase.3
The relationship between NOX emis-
sions and excess air, indicated by
percent 02 in the flue gas, is shown in
Figure 2. Examination of over 400 hours
of record when flue gas 02 was less
than 12% indicates that a moderate
control NOx level of 301 ng/J (0.7
lb/106 Btu) would be supported about
half the time. Hourly average emissions
less than the stringent level of 215 ng/J
(0.5 lb/106 Btu) were recorded for 27
hours when flue gas 02 was 5-9%.
However, higher NOx emissions were
also recorded at these 02 levels; the
maximum was 335 ng/J (0.78 lb/106
Btu) at 9% 02.
Although flue gas O2 correlated
strongly with N0« emissions, the
variation in the data in Figure 2 shows
that other variables were also affecting
NOx emissions. To examine the relation
of NOx emissions to other process
variables, a multiple linear regression
analysis was conducted. The resultant
relationship is expressed by:
NOx (ng/J) = 31 O2-202 TR-66 F + 138
where Oa is % flue gas oxygen, TR is the
average gas residence time (in seconds)
in the bed, and F represents the fly ash
reinjection system being on or off; F = 1
is "on" and F=0 is "off."
The multiple correlation coefficient
"r" for the equation was 0.83. The
regression line in Figure 2 shows the
relation between NOX and flue gas O2 for
an average gas residence time of 0.38
seconds and F=1 (i.e., fly ash reinjection
"on"). The standard error of the
estimate for this equation is 35.7 ng/J,
indicating that a 95% confidence
interval for the regression line at
average conditions observed during the
monitoring program would result in a
range for NOK of ± 70 ng/J. As actual
conditions (specifically 02 level) varied
from the average level observed, this
range increased.
It should be pointed out that the O2
levels observed indicate an amount of
excess air significantly above what is
considered good practice for efficient
operation of industrial boilers. As some
of the problems with in-bed 02 monitor-
ing and flyash reinjection are resolved,
the Georgetown FBB should run at
1.0
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0.8
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0.4
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450
400
350
300
250
200 *
750
7OO
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Figure 2.
6 7 8 9 10
Flue Gas Oxygen, percent
A/0, emissions as a function of flue gas oxygen.
77
12
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excess air levels closer to design, and
the N0« emissions should drop to a level
that is generally considered more
representative of FBC. For example, this
analysis indicates that, even at an 02
concentration of 9.8% (still high), a
moderate control level of 301 ng/J
would be supported on the average.
Similarly, the intermediate NOX level of
258 ng/J could be achieved at a level of
8.4% Oz, and the stringent NO* level of
215 ng/J at 7.1 %O2.
Particulate Emissions
During the first fewdays on site, there
was noticeable puffing from the stack at
regular intervals, indicating leakage in a
compartment of the baghouse. To locate
leaking bags, a hot slump procedure
was undertaken on August 19, 21, and
22 to gain access to the baghouse
through the compartment lids. The FBB
was shut down for short periods (0.5-2
hours) by shutting off the induced- and
forced-draft fans and the coal and
limestone feed. Each period, several (5-
10) bags were replaced. This reduced,
but never completely eliminated, the
puffing. Three EPA Method 5 particulate
measurements were conducted on
August 23, as part of the performance
specification tests. The resulting emis-
sions rates were 24.6, 37.8, and 47.0
ng/J (0.0572, 0.0879, and 0.109
lb/106 Btu), or an average of 36.5 ng/J
(0.0848 lb/106 Btu). This performance
is consistent with the optional inter-
mediate particulate control level of 43
ng/J (0.1 lb/106 Btu).
The FBB was shut down over the
Labor Day weekend to clear clogging of
the bed spent solids drain standpipe,
remove some refractory lining, and
reinspect the baghouse. Three days of
downtime allowed the baghouse to cool
so that operators could enter and
inspect bags and seals at the bottom of
the unit. As a result of this inspection,
some additional bags were replaced.
Overall baghouse performance im-
proved after this inspection, shown by
the results of Method 5 testing on
September 13. The three measurement
results were 19.6, 20.9, and 32.3 ng/J
(0.0456, 0.0487, and 0.0751 lb/106
Btu), or an average of 24.3 ng/J (0.0565
lb/106 Btu).
As with S02 and NOX emissions,
atypical operating conditions may have
adversely affected particulate control
performance; e.g., high excess air, high
limestone feed rates, ineffective flyash
reinjection, and torn or blinded fabric
filters could all be expected to decrease
the control efficiency for particulate
emissions. Better identification and
resolution of these problems should
improve particulate emissions control.
Summary
Continuous emission monitoring at
the Georgetown FBB shows that this
coal-fired steam generation system can
meet stringent S02 and NOX emission
control levels, although several atypical
operating conditions during the test
program hindered continuous achieve-
ment of optimal control. SC>2 control
performance was adversely affected by
bed height maintenance problems, lack
of a reliable in-bed S02feedback signal
for automatic control of limestone feed,
and ineffective fly ash reinjection. NQ2
emissions were generally higher than
expected for typical applications in the
future due to high excess air operation,
shorter-than-design gas residence
time, and ineffective fly ash reinjection.
Baghouse performance suffered due to
torn bags, bag blinding, and inefficient
multicyclone performance. Although
uncertain, high baghouse inlet loadings
may have caused the tearing bags
and/or bag blinding. Modification to the
FBB (e.g., improving automatic control
by using feedback signals from 02 and
SOz monitors, rebuilding the reinjection
system, and improving the baghouse) is
planned and, in some cases, already in
progress. These changes should further
improve control.
A further monitoring program was
conducted in February and March 1982.
A report of the results of the follow-up
program will also be published.
References
1. Young, C.W., et al.. Technology
Assessment Report for Industrial
Boiler Applications: Fluidized-bed
Combustion, EPA-600/7-79-178e
(NTIS PB 80-178288), November
1979.
2. U.S. Environmental Protection Agen-
cy, Federal Register, Vol. 44, No.
197, pp. 58602-58636, Wednesday,
October 10, 1979.
3. Beer, J. M., et al., /VOX Emissions
from Fluid/zed Coal Combustion.
Draft Final Report for EPA Grant No.
R804978, Massachusetts Institute
of Technology, 1980.
Charles W. Young. Edward F. Peduto, Peter H. Anderson, and Paul F. Fennellyare
with GCA/Technology Division. Bedford, MA 01730.
John O. Milliken is the EPA Project Officer (see below).
The complete report, entitled "Continuous Emission Monitoring at the George-
town UniversityFluidized-BedBoiler,"(OrderNo. PB83-151837;Cost:$16.00,
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
U. S. GOVERNMENT PRINTING OFFICE: 1983/659-095/1921
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Post3ge and
United States Center for Environmental Research pees pg^
Environmental Protection Information Environmental
Agency Cincinnati OH 45268 Protection
Agency
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