United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
*
Research and Development
EPA-600/S7-82-064 Mar. 1983
Project Summary
Shell N0x/S02 Flue Gas
Treatment Process:
Independent Evaluation
J. M. Burke
Nitrogen oxide (NOx) emissions from
stationary sources may be reduced by
80-90 percent by applying selective
catalytic reduction (SCR) of NOX with
ammonia. To further develop this
technology, EPA sponsored pilot scale
tests of two SCR processes treating
flue gas slipstreams from coal-fired
boilers. One of the processes tested
was the Shell Flue Gas Treatment
(SFGT) process which also removes
SOz. An independent evaluation of the
SFGT pilot plant tests shows that the
process can simultaneously reduce
NOx and SOz emissions by 90 percent
even though this was not demonstrated
during the pilot plant test program.
The process design tested appeared
well suited to coal-fired application,
and the reactor processed flue gas for
2000 hours without any signs of
plugging. An energy analysis indicates
that the SFGT process energy require-
ments equal 5 percent of the boiler's
capacity. Process costs were estimated
based on the pilot plant test results.
Estimated capital investment and an-
nual revenue requirements for the
SFGT process are $168/kW and 9.60
mills/kWh, respectively, significantly
higher than previous estimates for the
process using the same process design.
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
Selective catalytic reduction (SCR) of
nitrogen oxides (NOX) with ammonia (N Ha)
can reduce NOX emissions by 80 percent
or more. As such, SCR is ah effective
process for controlling stationary source
NOX emissions. For a utility application of
SCR, a catalytic reactor is between the
economizer and air preheater sections of
the boiler, where the flue gas temperature
is 300-400°C (570-750°F), optimum for
the catalytic activity. NH3, injected into
the flue gas upstream of the catalyst,
reacts with NOX on the catalyst surface to
form elemental nitrogen and water.
Most SCR processes were developed
and are being operated commercially in
Japan, primarily on gas- and oil-fired
sources. However, in the U.S., SCR sys-
tems are now being installed on a limited
basis. The most notable application is a
demonstration system being constructed
to treat half of the flue gas from Southern
California Edison's 215 MWe Huntington
Beach Unit No. 2 (an oil-fired boiler).
Operation of this system is expected to
establish SCR as a commercially available
technology for oil- and gas-fired sources in
the U.S.
In Japan, development efforts are cur-
rently aimed at applying SCR to coal-fired
sources. To date, most of the SCR process
vendors in Japan have operated pilot units
on slipstreams from coal-fired boilers. In
addition, four full-scale SCR systems now
treat flue gas from coal-fired boilers;
another eight are scheduled to start up in
1982 and 1983. These development
efforts are rapidly establishing SCR as
commercially available technology for
controlling NOX emissions from coal-fired
sources in Japan.
The transfer of SCR technology from
Japan to the U.S. for coal-fired applica-
tions is a potentially significant problem.
Since most coal-fired boilers in the U.S.
-------
operate ESPs downstream of the air pre-
heater, a typical SCR application would
expose the catalyst in the reactor to the fu II
paniculate concentration from the boiler.
Although, in tests in Japan, the catalyst
exposed to high particulate concentra-
tions experienced no adverse effects, the
differences in the composition of particu-
lates from U.S. and Japanese coals could
impact SCR operation.
To further develop SCR technology and
to determine how differences between
Japanese and U.S. coal/particulate proper-
ties impact the performance of SCR pro-
cesses, EPA has sponsored pilot scale
(0.5 MW equivalent) tests of two SCR
systems: Hitachi Zosen (HZ) process and
the Shell Flue Gas Treatment (SFGT) pro-
cess; the latter can also remove SOa from
the flue gas. In both cases, the pilot plants
processed a flue gas slipstream from a
coal-fired boiler. Contractors responsible
for the design and operation of these pilot
plants were Chemico Air Pollution Control
Corporation (North American licensee for
the HZ process) and the Process Division
of UOP (licensing agent of the SFGT
process). These contractors were also
responsible for collecting, evaluating, and
reporting the test data.
The primary objectives of the pilot plant
test programs sponsored by EPA were:
(1) to demonstrate the ability of the pro-
cesses to achieve a 90 percent reduction
in NOx emissions and, for the SFGT pro-
cess, a simultaneous 90 percent reduc-
tion in S02 emissions; and (2) to deter-
mine the impacts of catalyst performance
which result from processing flue gas
from a coal-fired utility boiler.
In conjunction with the pilot plant test
program, EPA contracted with Radian
Corporation to prepare an independent
evaluation of the processes tested based
on the pilot plant results. This document
summarizes the results of the indepen-
dent evaluation of the SFGT process. It
includes a discussion of the results of
tests conducted by both UOP and Radian
and the results of Radian's independent
evaluation of the SFGT process. A separate
report covering the detailed results of the
pilot plant test program has been prepared
by UOP.
Program Objectives and
Approach
The independent evaluation of the SFGT
pilot plant test program conducted by
Radian Corporation had three major objec-
tives: (1) to provide independent valida-
tion of the process measurements made
by UOP; (2) to quantify any changes in
the emission rates of secondary pollutants
across the pilot plant reactor; and (3) to
complete a technical and economic evalu-
ation of the SFGT process including identi-
fication of areas which require further
development or investigation.
To validate the measurements made by
UOP, a quality assurance program was
implemented. This program used EPA
reference methods and other standard
measurement techniques to make inde-
pendent audits of critical process parame-
ters such as flue gas flowrate, and NHa
injection rate. In conjunction with the
quality assurance program, the continu-
ous NOX and SO2 monitors were sub-
jected to certification tests designed to
determine the monitors' ability to make
accurate repeatable measurements. These
certification tests included measurement
of the continuous monitors' relative accu-
racy, drift calibration error, and response
time.
Concurrent with the quality assurance
program, a stack sampling program was
conducted to measure changes in second-
ary process emissions across the SCR
reactor. This approach required simul-
taneous sampling of the reactor inlet and
outlet for the species of interest The
samples were then analyzed, and differ-
ences between inlet and outlet concen-
trations determined.
Based on the results of the quality
assurance program, the stack sampling
program, and the test data collected by
UOP, an evaluation of the SFGT process
was completed by Radian. This evaluation
consisted of: (1) analyzing and reducing
the test data to a form that could be used to
predict process performance for a speci-
fied set of operating conditions; (2) using
the reduced test data and the results of the
stack sampling program, completing ma-
terial and energy balance calculations for a
500 MWe coal-fired application of the
SFGT process (the basis for these calcula-
tions was identical to that used by TVA
in developing cost estimates for the SFGT
process, presented in "Preliminary Eco-
nomic Analysis of NOX Flue Gas Treat-
ment Processes," EPA-600/7-80-021);
(3) using the results of the material and
energy balance calculations to develop a
modified estimate of total capital invest-
ment and annual revenue requirements
for a 500 MW coal-fired application of the
SFGT process; and (4) reviewing the test
data and identifying areas requiring further
investigation/quantification.
Results
Several areas which influence the tech-
nical and economic feasibility of the SFGT
process were examined as part of this
study:
Pilot plant test results.
Results of Radian's independent
tests.
Results of a 500 MW conceptual
design of the SFGT process.
Material balance calculations for a
500 MW SFGT process application.
Energy balance calculations for a
500 MWSFGT process application.
Estimated capital investment and
annual revenue requirements for a
500 MW SFGT process application.
Pilot Plant Test Results
The test program at the SFGT pilot plant
initiated in October 1979, was completed
in October 1 980. During this period, the
pilot plant processed a flue gas slipstream
from between the economizer and the air
preheater of the coal-fired unit No. 2 at
Tampa Electric Company's Big Bend Sta-
tion. Normal flue gas flowrate to the pilot
unit was 1600 NmVhr (1000 scf m), and
flue gas was processed for about 2000
hours during the program.
The pilot plant test program involved
examining three charges of acceptor ma-
terial (the material which both catalyzes
the NOX reduction reactions and removes
S02 from the flue gas) under a variety of
test conditions, including tests for simul-
taneous reduction of NOX and SOa emis-
sions and tests for removal of only NOX or
S02. In general, these tests were divided
into two categories: optimization tests
and demonstration (or long-term) tests.
The objective of the optimization tests was
to identify operating conditions which
would reduce both NOX and SO2 emis-
sions by 90 percent at a minimum total
cost for operating the process. The major
objective of the demonstration tests was
to document the ability of the process to
achieve a 90 percent reduction in NOX and
S02 emissions for 90 days.
The objectives of the pilot plant tests
conducted by UOP were not met Under
typical operating conditions, S02 removal
was 90 percent while the NOX reduction
efficiency averaged only about 70 percent
This was due to poorer-than-expected
performance of the acceptor. As a result,
the pilot plant reactor was undersized for
the flue gas composition at the Tampa
Electric site. While the overall program
objectives were not met, the tests did
document the technical feasibility of apply-
ing the SFGT process to a coal-fired power
plant. The pilot plant operated for about
2000 hours with no signs of plugging in
the reactor; soot blowing was not required.
-------
In terms of process performance, the
pilot plant tests did not demonstrate
simultaneous reduction in NOX and S02
emissions at design operating conditions.
However 90 percent NOx/SOa reduction
was achieved by using preoxidation and
cooling steps which were not in the origi-
nal process design. Extrapolation of the
pilot plant test results indicates that it
should be possible for the process to
reduce NOX and SOa emissions by 90
percent without preoxidation and cooling.
However, this requires a larger reactor and
additional acceptor which will significantly
impact the estimated costs for the SFGT
process. Because of this cost impact and
the good performance achieved by using
preoxidation and cooling steps, UOP now
proposes to use these steps in the com-
mercial design and operation of the SFGT
process.
The test program briefly examined the
effects of key operating parameters but
did not provide a detailed characterization
of the effects of various operating param-
eters on process performance. Two pa-
rameters in particular, temperature and
flowrate, were shown to affect process
performance, yet their effects were not
thoroughly documented. Temperature
and flowrate are significant parameters
since they would be expected to change
with swings in boiler load, thus changing
NOX and SOa emission reduction efficien-
cies.
Probably the most important aspect of
the SFGT process performance which was
documented during the pilot plant tests
was the stability of acceptor activity. The
tests showed that when first exposed to
flue gas, acceptor activity initially declined,
but then remained stable during the 700
hours of-eeerationTThis is favorable in
terms of applying the process to a coal-
fired boiler since, after the initial decline,
there was no measurable change in activ-
ity. However, note that this does not
document acceptor activity over a period
equivalent to 1 year of commercial opera-
tion. While demonstration of a 1-year
acceptor life was not an objective of the
test program, a 1-year acceptor life is
critical to the economic feasibility of the
SFGT process. And, if the acceptor can
maintain activity for longer than 1 year,
this could result in a significant reduction
in process costs.
Overall, the pilot plant test results indi-
cate that applying the SFGT process to a
coal-fired boiler is technically feasible.
However, these tests did not demonstrate
several key factors:
The ability of the process to simul-
taneously reduce NOx and SOa emis-
sions by 90 percent under design
operating conditions.
The performance of the process
under conditions which simulate
reduced boiler loads.
The stability of the acceptor over a
period equivalent to 1 year of com-
mercial operation.
Of these factors, the one most critical to
the commercial success of the process is
the stability of the acceptor. Although this
was not demonstrated, note that no dete-
rioration of acceptor performance was
observed during the program and that
UOP will guarantee a 1 - year acceptor life
for a commerical application of the process.
Results of Radian's
Independent Tests
The independent evaluation test pro-
gram by Radian had two primary objec-
tives: to ensure .the quality of the data
collected at the SFGT pilot plant and to
quantify changes in the concentrations of
certain pollutants across the SFGT reactor.
Data quality was determined by quality
assurance (QA) audits and continuous
monitor certification tests; changes in
pollutant concentrations were determined
by a secondary emissions sampling pro-
gram. Results of each element of the
independent evaluation program are sum-
marized below.
Quality Assurance Audits
The QA audits conducted by Radian
were designed to ensure the accuracy of
the process data required to characterize
the operation of the SFGT pilot plant
Radian used reference methods for audit-
ing process operating parameters which
were measured on a continuous or routine
basis by UOP. One exception was the
measurement of NHa emissions which
were not routinely monitored by UOP,
although the original design of the pilot
unit included an analyzer intended to
determine NHa emissions.
Results of the NHa emissions sampling
are shown in Table 1. Samples were
collected during both NOx/SOa and NOX-
only tests. As shown, the samples from
the NOx-only tests indicate relatively high
NHa emissions, averaging 49 ppm. But
the samples from the NOx/SOa tests indi-
cated NHa emissions averaging about 1 5
ppm. At 15 ppm, NHa emissions are not
expected to result in any significant opera-
tional or environmental problems; how-
ever, these emissions are not expected to
represent a commercial SFGT process
designed for 90 percent reduction of NOX
and SOa. Changes in reactor design
required to achieve the 90 percent NOx/
SOa reduction can significantly increase
NH3 emissions.
Results of the other QA audits con-
ducted by Radian are summarized in Table
2. As shown, all but the flue gas flowrate
measurements were within 10 percent of
the values recorded by UOP. In general,
the QA audit results indicate that the
process data collected by UOP accurately
characterize the operation of the SFGT
pilot plant However, the discrepancy in
the flowrate measurements indicated that
there could be a problem with this mea-
surement technique: the reactor may
have been processing flue gas at greater
than design flowrates. This question was
resolved during subsequent tests in which
UOP confirmed the accuracy of their flow-
rate measurement by an independent test.
Based on the results of the QA audits
and subsequent tests by UOP, the major
process measurements made by UOP
were determined to be accurate within the
limits of the techniques employed to make
the measurements. This indicates that the
data collected by UOP can be used to
characterize operation of the process.
Secondary Emissions Sampling
The secondary emissions sampling pro-
gram was conducted by Radian during
Table 1. SFGT Pilot Plant NHs Emissions
Mode of Operation
NO,/SO2
NOx/SO2
NOx/SO2
NOx/SO2
NOx/SO2
NOx/SOz
NOx/SO2
NOx/SO2
NOx/SO2
NOX Only
NOX Only
NO*. Only
NOxin
ppm dry
380
420
390
375
-
.
392
402
-
420
327
224
NH3.-NO,
1.17
1.21
1.31
1.25
-
-
1.17
1.19
.
1.18
1.21
1.38
NHs Emissions
ppm dry
15
16
22
17
16
11
12
13
16
47
52
48
-------
June and July 1980, concurrent with
demonstration tests conducted by UOP.
The objective was to quantify changes in
the emission rates of pollutants other than
NOX and SOa. For the most part, these
tests were conducted during tests in
which both NOX and S02 were being
removed from the flue gas.
Table 3 summarizes results of the
secondary emissions sampling program at
the SFGT pilot plant. As shown, concen-
trations of both hydrogen cyanide (HCN)
and nitrosoamines at the reactor outlet
were below the detection limits of the
analytical techniques employed. For HCN,
this detection limit is equivalent to 10
ppbv; and for N-nitrosodimethylamine, 2
ppbv. For both, concentrations are below
that which is considered safe for emission
sources.
Decreases in both the hydrocarbon and
CO concentrations were measured across
the reactor. This change is probably due to
Table 2. QA Audit Results
Measurement
Audited
oxidation of these pollutants in the reactor.
Table 3 also shows that a decrease in SOs
concentration was also measured across
the reactor. This decrease is due to
removal of SOa from the flue gas in the
SFGT reactor. The apparent change in
paniculate concentration is believed to be
due to unaccounted-for stratification in
the ducts. Note that results for nitrous
oxide (N20) are not presented, because
the analytical technique used to measure
NaO proved unsatisfactory for use in a flue
gas stream.
In addition to measuring the concentra-
tion of particulates in the flue gas, an
elemental analysis of the particulates was
completed in an attempt to determine if
erosion of the acceptor has a measurable
effect on paniculate composition. Table 4
shows results of the elemental analysis of
the particulates collected at the SFGT pilot
plant As shown, no significant change in
the composition of the particulates was
Audit
Procedure
Relative11
Error, %
Flue Gas Flowrate
Injection Rate
Reactor Pressure Drop
Reactor Operating
Temperature
EPA Reference Method 2
Absorption followed by
wt gain measurement -
(analogous to EPA
Method 4)
Magnehelic differential
pressure gauge
Thermocouple with
traverse of reactor inlet
-14.4
7.6
-1.4
-1.3
aRelative error = (Process measurement - Audit result) x 100%
/Audit result}
measured with respect to these elements.
Changes shown in Table 4 are due to
random errors in sampling or analysis and
do not represent real changes in particu-
late composition.
Of the secondary emission sampling
results, the most significant was that SOs
is removed in the SFGT reactor. The
removal of SOa in the reactor reduces the
sulf uric acid dewpoint which permits addi-
tional heat recovery in an air preheater
downstream of the SFGT process. The
additional heat recovery reduces the energy
requirements of the process and conse-
quently reduces process costs.
Continuous Monitor Certification
Tests
Certification tests were conducted for
the SOa and NOX monitors used to mea-
sure flue gas concentrations of pollutants
at the inlet and outlet of the reactor. The
tests were included in the independent
evaluation program to ensure the quality
of the pilot plant performance data being
collected by UOP. Certification of contin-
uous emission monitors (CEMs) involves
a formal procedure developed by EPA to
ensure the accuracy of monitors measur-
ing emissions from sources which must
comply with new source performance
standard emission limitations. For a CEM
to be certified, it must pass a number of
performance tests, including calibration
error, response time, drift, and relative
accuracy. The performance specifications
for each certification test are shown in
Table 5, along with test results. The
performance specifications are those in
the Federal Register, Vol. 44, No. 197,
Table 3. Stack Sampling Results at the SFGT Pilot Plant
Flue Gas
Component
Reactor Inlet
Concentration3
Reactor Outlet
Concentration3
Measurement Technique
Nitrosoamines13
Hydrogen Cyanide
Sulfur Trioxide
<5 \ig/dscmc
<0.01 mg/dscm
11.4 ppmv (dry basis)
aAverage of 2 or more tests.
hBelow the detection limit
cdscm = dry standard cubic meter.
<5
<0.01 mg/dscm
0.1 ppmv (dry basis)
Absorption, extraction, gas
chromatograph w/nitrogen
specific detector
Absorption, distillation,
titration
Controlled condensation,
ion chromatograph
Hydrocarbons
(C,-C6)
Carbon Monoxide
Nitrous Oxide
Particulates
28.5 ppmv
0. 13%
-
8.9 g /dscm
2 1.0 ppmv
<0.017%t>
-
6.3
Gas chromatograph
flame ionization detector
Fischer gas partitioner
Infrared spectroscopy
In-stack filter
-------
Table*.
Component
Results of Particulate Analysis at
the SFGTPilot Plant*
In
Out
Out/In
At
Ca
Fe
K
Mg
Mn
Sn
Na
Si
Zn
Cu
Ti
V
8.6%
1.8%
12%
1.5%
5100 ppm
300 ppm
270 ppm
4300 ppm
20%
410 ppm
96 ppm
5400 ppm
255 ppm
8.0%
1.8%
11.1%
1.4%
5000 ppm
320 ppm
270 ppm
5100 ppm
16%
720 ppm
100 ppm
5100 ppm
340 ppm
0.93
1.00
0.93
0.93
0.98
1.07
1.00
1.19
0.80
1.76
1.04
0.94
1.33
"Concentrations are on a mass fraction basis.
Wednesday, October 10, 1979 - "Pro-
posed Rules: Standards of Performance
for New Stationary Sources; Continuous
Monitoring Performance Specifications."
As shown in Table 5, results for both
the NOx and S02 CEMs met the perform-
ance specifications with one exception:
the relative accuracy of the outlet NOx
CEM was over 50 percent (performance
specifications require a relative accuracy
of 20 percent or less). These data indicate
that except for the outlet NOX analyzer,
the CEMs were accurately measuring flue
gas NOX and S02 concentrationa
The poor relative accuracy of the outlet
NOX analyzer shown in Table 5 indicates
that the CEM was accurately measuring
flue gas NOX concentrations. However,
several factors must be considered when
evaluating these test results. First the
absolute error in the Method 7 versus
the monitor measurements averaged only
16 ppm. This is a relatively small dif-
ference. A second factor, which indicates
that the outlet NOX monitor's performance
was within acceptable limits, is that the
performance specifications require that
relative accuracy be less than or equal to
20 percent or 10 percent of the applicable
standard, whichever is greater. Using the
NSPS for bituminous-coal-fired sources
as a basis, the relative accuracy of the
outlet NOx CEM is approximately 5 per-
cent of the standard which is within
acceptable limits.
Overall, certification tests indicate that
the NOx and S02 CEMs at the SFGT pilot
unit were performing acceptably. There-
fore, the data collected during the pilot
plant tests by UOP represent the pilot
plant's performance. This is partially a
result of UOPs extensive monitor main-
tenance program which was designed to
ensure the accuracy and quality of the
performance data collected.
Results of a 500 MW Concep-
tual Design of the SFGT Process
A conceptual design of a 500 MW
SFGT process was prepared based on
selected pilot plant test results. This
conceptual design served as a basis for
material and energy balance calculations
and for a cost estimate for a 500 MW
application of the SFGT process.
Table 6 summarizes results of the con-
ceptual design for a 500 MW application
of the SFGT process. As shown, the key
design variable levels are presented. The
results of this design indicate that it is
technically possible to simultaneously
reduce NOX and S02 emissions by 90
percent using the SFGT process without
using preoxidation and cooling steps.
However, the reactor size and the quantity
of acceptor required to meet the design
NOx and SOa reduction efficiencies are
significantly greater than previous esti-
. mates (based on the same type of process
operation).
To some extent the increase in the
quantity of acceptor is a function of the
limitations placed on the conceptual de-
sign to reflect pilot plant operation. Data
were collected which indicate that sub-
stantial improvement in NOX and S02
reduction efficiencies could be achieved
through modification of process opera-
tion. But, limitations of the pilot plant
prevented adequate characterization of
process performance under modified
operating conditions.
Reactor pressure drop and other design
parameters are fairly consistent with pre-
vious estimates for the processes. The
results, however, indicate the need for
equipment to control the temperature and
flowrate of the flue gas entering the
reactor. This is primarily due to the fact
that the S02 reaction rate is reduced at
reduced temperatures and flowrates, and
data were not developed to characterize
overall process performance under con-
ditions which simulated reduced boiler
loads.
In summary, the conceptual design
indicates that the SFGT process can simul-
taneously reduce NOX and S02 emissions
by 90 percent However, this level of
emissions reduction is achieved only at
the expense of an increased quantity of
acceptor and a corresponding increase in
costs. Note that there may be other means
of improving process performance; but
these were not considered in preparing
the conceptual design.
Material Balance Calculations
for a 500 MW SFGT Process
Application
Material balance calculations for a 500
MW application of the SFGT process were
included as part of this study to identify
raw material requirements for the process
and to serve as a basis for an estimate of
capital investment and annual revenue
Table 5. Results of the Continuous Monitor Certification Tests at the SFGT Pilot Plant
Certification
Test
Performance
Specification
Inlet S0za
Monitor
Outlet S0za
Monitor
Inlet NOX
Monitor
Outlet NOX
Monitor
Calibration Error, %
-high level
-mid level
Response Time, min
Zero Drift %
(2-hour)
Calibration Drift, %
(2-hour)
Relative Accuracy, %
<5
<5
<2
<2
<20»
1.4
0.7
0.8
0.25
0.49
14.0
1.4
0.7
1.3
0.25
0.49
8.6
3.85
4.62
1.7
0.64
1.35
12.6
2.52
2.62
0.8
1.04
1.18
52.3
aOne instrument was used to measure both inlet and outlet of the reactor.
*'Alternatively, <10 percent of the applicable emissions standard.
-------
requirements. The material balance was
based on the pilot plant and secondary
emissions sampling test results, and thus
reflects those results in the estimated
process and component flows. The most
significant results of the material balance
calculations include estimation of hydro-
gen, steam and NHa requirements and
NHa and S02 emissions from the process.
Table 7 summarizes the material bal-
ance calculations and compares them with
the material requirements identified in
TVA's preliminary economic analysis. As
shown, hydrogen requirements increase
by approximately 25 percent, because H2
consumption in the pilot plant was higher
than previous estimates indicated. Steam
requirements increased by the same frac-
tion, indicating that the steam to Ha ratio
of the TVA design is essentially identical to
that of the pilot plant tests. The naphtha
requirements increase in direct proportion
to the hydrogen requirements. This is
perhaps the single most important increase
in a material flowrate because it has
significant impact on annual revenue re-
quirements for the process. The signifi-
cantly increased NHa requirements, due
to the high NHa/NOx ratio used in pre-
paring the conceptual design, reflect the
relatively poor performance of the pilot
plant at lower NHa/NGv injection ratios.
Finally, the quantity of sulfuric acid is
essentially unchanged: the same quantity
of SO2 is being removed from the flue gas.
Energy Balance Calculations for
a 500 MWSFGT Process
Application
An energy balance, completed as part of
the evaluation of the SFGT process, defined
overall process energy requirements and
quantified the heat credits associated with
the process. The analysis of energy
requirements indicated that the SFGT
process has a net energy consumption
equivalent to 5 percent of the energy input
to the boiler.
Individual components of the overall
process energy requirements are sum-
marized in Table 8. As shown, the single
largest component of the overall energy
requirement is the fuel energy which
could be obtained through combustion of
the naphtha used to generate hydrogen.
This represents over 5 percent of the
equivalent energy consumed by the boiler
and directly depends on the H2 require-
ments of the process. Because the fuel
energy requirement is so large, a given
percentage decrease in H2 requirements
would result in approximately an equiva-
lent percentage decrease in overall energy
requirements for the process. This is a
strong basis for further examination of H2
requirements and the factors which affect
H2 consumption.
The energy requirements associated
with steam and electrical energy are less
than 50 percent of the fuel energy require-
ments. For steam, this represents a small
fraction of the overall energy requirements
of the process and, although some reduc-
tion in steam consumption may be pos-
sible, it will not significantly influence the
annual revenue requirements. In the case
of electrical energy, the major portion of
this requirement results from the energy
of fan compression. This can be reduced
by reducing acceptor volume.
The heat credits associated with the
SFGT process were estimated to be equi-
valenttooverS percent of the energy input
to the boiler, and result in nearly a 40
percent decline in the overall energy
requirements for the process. The heat
credit analysis indicated that nearly all of
the potential heat credits can be recovered
in a commercial application of the SFGT
process.
Estimated Capital Investment
and Annual Revenue Require-
ments for a 500 MW SFGT
Process Application
Total capital investment and annual
revenue requirements for a 500 MW
application of the SFGT process were
estimated as part of this evaluation. The
estimated costs reflect the results of the
pilot plant tests. When compared with the
previous estimate prepared by TVA, the
modified cost estimates indicate the mag-
nitude of the impact the pilot plant results
had on estimated process costs. In
addition, comparison of the modified cost
estimate with cost estimates for other SCR
processes indicates the cost effectiveness
of the SFGT process as tested in the pilot
plant program.
Table 6. Results of the SFGT Conceptual Design
Parameter
Design Level
Developed in this Study
Acceptance Time, min
Reactor Depth, m
Inlet SO2 Concentration, ppm
Recycle Rate, %
NH3/NOX Injection Ratio
Overall NOx/SO2 Reduction %
N0x/S02 Reduction Across Reactor, %
Number of Reactors
Cross-sectional Area of each Reactor, m2
SFGT System Pressure Drop, kPa
148
9'
2548
1.8
1.5
90
89.8
8
40.75
3.93
Table 7. A Comparison of Material Flows for a 500 MW Coal-fired Application of the SFGT
Process
Estimated Flowrate
Material Requirement
Steam, kg/hr
Hydrogen, kg/hr
Naphtha, rrP/hr
NHz kg/hr
H2S04 from acid plant kg/hr
TVA3
31,940
1,300
57
830
16,160
Radian11
40,300
1.630
71
1.120
16.160
Ratio
1.26
1.25
1.25
1.35
1.00
a£stimated prior to pilot plant test program.
bBased on pilot plant test results.
Table 8. Overall Energy Requirement for a 500 MW Application of the SFGT Process
Energy Area
Heat Credit
Steam
Electricity
Fuel
Energy Requirement
Gcal/hr
(35.75)
6.98
22.3
63.0
Percent of Boiler
Capacity
(3.2)
0.6
2.0
5.6
Total
56.53
5.0
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Results of Capital Cost Estimate
Table 9 shows the individual compo-
nents and the estimated total capital
investment for a 500 MW application of
the SFGT process. As shown, the total
capital investment was estimated to be
approximately $84.2 x 106 (equivalent to
$168/kW of generating capacity). Com-
pared to TVA' s previous esti mate of $ 6 7.2
x 106, this represents about a 25 percent
increase in total capital investment The
principal difference between the two esti-
mates is the estimated acceptor volume.
The required acceptor volume based on
the pilot plant tests was estimated to be
nearly 90 percent greater, thereby increas-
ing the total capital investment
Results of the Annual Revenue
Requirement Estimate
Table 10 shows the individual compo-
nents and the total estimated average
annual revenue requirements for a 500
MW application of the SFGT process. As
shown, the average annual revenue re-
quirement was estimated to be approxi-
mately $33.6 x 106 (equivalent to 9.60
mills/kWh). Compared to TVA's previous
estimate of $22.5 x 106/yr, this repre-
sents almost a 50 percent increase in
annual revenue requirements for the
process.
As with the capital costs, the principal
factor which increased the annual revenue
requirements is the increased quantity of
acceptor required in the reactor. Addi-
tional acceptor as a raw material accounts
for over 50 percent of the increase in
annual revenue requirements. Another
significant factor which increased annual
revenue requirements is the estimated
increase in naphtha required for hydrogen
generation: about 12 percent of the
increase in annual revenue requirements.
Table 9. Estimated Capital Investment for a 500 MW Application of the SFGT Process"
Investment $
%of
total direct
investment
Direct Investment1"
NHs storage and injection
H2SO4 plant
Reactor section
Flow smoothing section
Steam Naphtha reformer
Gas Handling
Sub-total direct investment (Dl)
Services, utilities (0.06 x Dl)
Total direct investment (TDI)
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense = 0.25 (TDI x 10-6)0.83
Contractor fees = 0.096 (TDI x 10-6)0.76
Total indirect investment (IDI)
Contingency = 0.2 (TDI + IDI)
Total fixed investment (TFI)
Other Capital Charges
Allowance for startup and modification
= (0.1 ) (TFI)
Interest during construction = (0. 12) (TFI)
Total depreciable investment
Land
Working Capital
Total Capital Investment
890,000
7,172,000
27,455,000
2,828,000
4,698,000
1,546,000
44,589,000
Z 6 75,000
47,264,000
709,000
177,000
6, 135,000
1,799,000
8,820,000
1 1,2 1 7,000
67,301,000
6,730,000
8,076,000
82,107,000
14,000
Z05 1,000
84,172,000
1.9
15.2
58.1
6.0
9.9
3.3
94.4
5.6
100.0
1.5
0.4
13.0
3.8
18.7
23.7
142.4
14.2
17.1
173.7
4.4
178.1
aBasis: 500MW new coal-fired power plant 3.5% sulfur coal, 90% NOX removal, 90% SOz
removal. Midwest plant location. Project beginning mid-1977, ending mid-1980. Average basis
forscaling, mid-1979. Investment requirements for fly ash disposal excluded. Construction labor
shortages with overtime pay incentive not considered.
bEach item of direct investment includes total equipment costs plus installation labor, and material
costs for electrical, piping, ductwork, foundations, structural, instrumentation, insulation, and site
preparation.
Cost Comparison and Summary
The capital investment and annual reve-
nue requirements of the SFGT process
have been estimated based on the results
of the test conducted at the EPA spon-
sored pilot plant in Tampa, FL. These cost
estimates indicate that the capital costs
and annual revenue requirements are
higher than the estimated costs prior to
the test program. A more important com-
parison, however, is the cost of the SFGT
process relative to the cost of a con-
ventional, NOX only SCR process.
Since the same basis was used in pre-
paring the modified SFGT cost estimate as
TVA used in preparing preliminary eco-
nomic estimates for other SCR processes,
it is possible to make a direct comparison
with TVA's previously published results.
Table 11 shows the estimated annual
revenue requirements for two pollution
control systems which reduce emissions
of particulates, NOX, and S02 by 99.5,90,
and 90 percent, respectively. As shown,
the pollution control systems employ two
SCR processes tested by EPA; one is the
SFGT process. The other SCR process is
coupled with a flue gas desulfurization
system and both processes have ESPs
downstream to put the cost estimates on a
common basis.
As shown in Table 11, the estimated
costs associated with the SFGT processes
are 35 percent higher than those of the
pollution control system which employs
the HZ SCR process. This indicates that
the SFGT process, as tested in the pilot
plant and presented in the conceptual
design, is not competitive with a conven-
tional NOx-only SCR process for the 500
MW application examined in this study.
Note, however, that the relative costs in
Table 11 are only valid for one specific
application; they could change for other
applications.
Overall, the results of the modified cost
estimate indicate that for the particular
application examined in this study, the
costs of the SFGT process do not appear to
be competitive with the costs of other SCR
processes, based upon the conceptual
design which was limited to operating
conditions demonstrated during the pilot
plant tests. It is possible that estimated
costs would change significantly for a
design based on operating conditions
which include the use of preoxidation and
cooling. It is also possible that SFGT
process costs may be more competitive
with the costs of other SCR processes for
lower sulfur coal applications.
A key factor in all the cost estimates is
the useful life of the acceptor. The
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Table 10. Estimated Average Annual Revenue Requirements for a 500 MW Application of the SFGT Process8
Annual Unit Annual % of annual
Item quantity cost ($) cost ($) revenue required
Direct Costs
Raw materials
NHs
Naphtha
Catalyst
Reformer catalyst
Total raw materials
Conversion costs
Operating labor and supervision
Utilities
Naphtha
Steam
Process water
Electricity
Heat credit
Maintenance
Analyses
Total conversion costs
Total direct costs
7.87 x 1&kg
39,773 m3
-
-
29,200
labor hrs
9,943 m3
1 79,900 GJ
8,078,000 m3
68,859,000 kWh
1,047,500 GJ
4,380 labor hrs
0.16512/kg
132. 1/m3
-
-
12.50/
labor hr
132. 1/m3
1.90/GJ
0.23/rrfl
0.029 kWh
-1.90/GJ
1 7.00/ labor hr
1,299,500
5,254,000
12,600,300
125,100
19.278,900
365,000
1,313,500
341,200
128,000
1,996,900
(1,896,000)
1,891,000
74,500
4,214,100
23,493,000
3.87
15.65
37.53
0.37
57.42
1.09
3.91
1.02
0.38
5.95
(5.65)
5.63
0.22
12.55
69.97
Indirect Costs
Capital charges
Depreciation = (0.06) (total depreciable
investment)
Average cost of capital = (0.086)
(total capital investment)
Overheads
Plant=(0.5) (conversion costs minus utilities)
Administrative = (0.1) (operating labor costs)
Marketing - (0.1) (sales revenue)
Total indirect costs
Spent catalyst disposal
Gross average annual revenue requirement
Byproduct Sales Revenue
H2S04
Total Annual Revenue Requirements
11.1 x 706/cg
-0.033/kg
4,926,400
7,238,800
1,165,300
36,500
366,000
13,733,000
11,400
37,237,400
(3,660,000)
33,577,400
14.67
21.56
3.47
0.11
1.09
40.90
0.03
110.90
(10.90)
100.00
"Basis: 500 MW new coal-fired power plant 3.5% S coal. 90 percent NOX reduction, 90 percent SO2 removal. Midwest power plant location, 1980
revenue requirements. Remaining life of power plant = 30 years. Plant on line 7000 hr/yr. Plant heat rate equals 9.5 GJ/kWh. Investment ana
revenue requirement for disposal of fly ash excluded. Total direct investment $47,264,000; total depreciable investment $82,107,000; and total
capital investment $84,172000.
Table 11. Estimated Annual Revenue Requirements for Two Pollution Control Systems
Annual Revenue Requirements, $ x 10~6
SCR Process
SCR
FGDP
ESP3
Overall
SFGT
Hitachi Zosen
33.6
10.2
14.7
3.0
2.2
36.6
27.1
aFGD and ESP costs are from "Preliminary Economic Analysis of NOX Flue Gas Treatment
Processes." Tennessee Valley Authority - Office of Power. EPA - 600/7-80-021, February 1980.
estimates presented in this evaluation
assumed a 1-year life. If the acceptor life is
longer or shorter than 1 year, costs could
vary significantly from those estimated in
this study. Further development work
could focus on defining acceptor life and
on demonstrating alternate operating/
design conditions designed to minimize
acceptor requirements.
Conclusions
The following conclusions are based
on work performed during this study. For
the most part, the information obtained
during the course of the study is sum-
marized in the report and serves as back-
ground for these conclusions. The major
conclusions of this study are:
The SFGT process can simultane-
ously reduce NOX and SO2 emissions
by 90 percent when applied to a
coal-fired boiler. However, this level
of emissions reduction can only be
attained at the expense of increased
acceptor volume (over the pilot plant
design) or through the use of operat-
ing and/or design options which
were tested only for a short time
during the pilot plant test program.
No problems with reactor plugging
or declinging acceptor activity were
evident during the pilot plant test
program. This indicates that the
copper oxide acceptor and the paral-
lel passage reactor design appear
technically suited for application to a
8
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coal-fired source. The pilot plant
tests did not, however, demonstrate
a stable acceptor life equivalent to 1 -
year of commercial operation. While
this was not an objective of the test
program, it must be verified to estab-
lish the technical and economic feas-
ibility of the process.
> The secondary emissions sampling
program did not indicate that any
adverse environmental impacts would
result from application of the SFGT
process as operated during the pilot
plant tests. However, the measured
NHa emissions may not be repre-
sentative of a full-scale application of
the process.
The secondary emissions sampling
program established that the SFGT
process removes S03 from the flue
gas. This represents a significant
benefit for the process since removal
of SOa permits recovery of additional
heat in the air preheater. In addition,
the low concentrations of SOa mea-
sured at the reactor outlet should
preclude any problems with plugging
and corrosion of a downstream air
preheater due to the formation of
ammonium sulfates.
The conceptual design and material
balance calculations indicated that
significant increases (overTVA's pre-
liminary estimate) in Ha, steam, and
NHa consumption are expected based
on the pilot plant test results. Of
these, Ha consumption has the
greatest impact on the economic
feasibility of the process. Since a
detailed characterization of the fac-
tors which influence H2 consump-
tion was not completed during the
pilot plant tests, it may be possible to
reduce Ha consumption. This area
warrants further investigation.
Nearly all of the potential heat credits
available to the SFGT process can be
recovered, reducing overall process
energy requirements by about 40
percent.
The overall energy balance indicated
that the SFGT process has an energy
requirement equivalent to 5 percent
of the energy input to the boiler for a
500 MW application. When com-
bined with an ESP, the SFGT process
requires about 50 percent more
energy than other SCR systems com-
bined with ESPs and FGD systems.
The principal component of the over-
all process energy requirement is the
fuel energy associated with the naph-
tha used to generate hydrogen.
The estimated total capital invest-
ment and average annual revenue
requirements for the SFGT process
are significantly higher than the costs
of a conventional, NOx-only SCR pro-
cess combined with an FGD system.
This indicates that the SFGT process
is not economically competitive with
other SCR systems for the case
examined as part of this evaluation.
However, alternative applications of
the SFGT process may be more eco-
nomically competitive. The alterna-
tives include the use of preoxidation
and cooling steps now recommended
by UOP and applications of the pro-
cess on sources firing low-sulfur
coal.
Overall, the SFGT process design exam-
ined in this study does not appear eco-
nomically competitive with a conventional,
NOx-only SCR process for high sulfur coal
applications. It may be more competitive
for low sulfur coal applications, but this
evaluation did not quantify costs for such
an alternative. In addition, several tech-
niques could reduce overall process costs,
but these were not examined in detail
during the pilot plant test program.
J. M. Burke is with Radian Corp., 8501 Mo-Pac Blvd., Austin, TX 78759.
J. David Mobley is the EPA Project Officer (see below).
The complete report, entitled "Shell NOi/SQ* Flue Gas Treatment Process:
Independent Evaluation," (Order No. PB 83-144 816; Cost: $23.50, 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
*USGPO: 1983-659-095-591
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