United States
Environmental Protection
Industrial Environmental Research
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).
  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

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
             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
Georgetown FBB Continuous Emission Monitoring







0-100 ppm

0-100 ppm

0-1000 ppm



0-1OOO ppm

0-1000 ppm

0-10OO ppm



"Nondispersive infrared.

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
  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.

  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


 £  90

 i  85

 |   80

           • Day 240 hrs 10-20
           ° Day 255 hrs 1-24
           * Day 256 hr 15 — Day 257 hr 14
                            Ca/S Molar Feed Ratio

Figure 1.     SOz emissions as a function of calcium to sulfur molar feed ratio.


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-
  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
  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
  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
 "§   0.5
                                                      * •
          .. *»*4* * ••
         7*   •••*• •
I *•

                                                                  200   *
Figure 2.
    6       7       8       9       10
             Flue Gas Oxygen, percent

A/0, emissions as a function of flue gas oxygen.

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.

  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.

 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
 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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