United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
Research and Development
EPA-600/S7-83-048 Dec. 1983
f/EPA Project Summary
Shell NOX/S02 Flue Gas
Treatment Process: Pilot Plant
Evaluation
J.B. Pohlenz and A.O. Braun
The Shell Flue Gas Treatment process
was evaluated in a pilot-scale test for
reducing simultaneously the emissions
of sulfur dioxide (SO2) and nitrogen
oxides (NO,) from flue gas produced in
a coal-fired utility boiler. Flue gas
leaving the economizer at about 400°C
with a full load of fly ash is contacted
with a copper-on-alumina acceptor/cat-
alyst in a parallel passage reactor. SOz
is removed by reaction with the acceptor,
and the selective reduction of NO, with
NH3 is catalyzed. Regeneration of the
acceptor at 400°C with hydrogen
releases the sulfur as concentrated SOz
which can be processed into a marketa-
ble byproduct. Fly ash was found to
increase the diffusional resistance to
mass transfer of SO2 and SOs to copper
oxide, requiring an increase of 25% of
acceptor/catalyst over that for clean
service to achieve 90% SO, reduction.
NOx reduction with NH3 was found to
be non-selective at the beginning of
acceptance due to the temperature
increase accompanying copper oxidation,
requiring a further increase in acceptor/
catalyst of 18% to obtain 90% NOx
reduction simultaneously. Estimates of
capital and operating costs increased by
12 and 21%, respectively, due to the
effect of fly ash with further increases
of 7 and 5% to compensate for the
combustion of NH3 at initiation of
acceptance. The objective performance
of 90% simultaneous NO,/SO« reduction
was achieved; however, the demonstra-
tion was not continued for the initially
planned 90 days.
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
In 1973, UOP constructed a 0.5 MW
pilot unit at the coal-fired Big Bend
Station of Tampa Electric Company
(TECO), based on the Shell Flue Gas
Treatment (SFGT) process for removing
sulfur oxides (SO*). This process was in
full scale operation (40 MW) on a boiler
fired with fuel oil in the Showa Yokkaichi
Sekiyu (SYS) refinery near Yokkaichi,
Japan, but its performance in coal-fired
service had not been determined. The
TECO pilot plant was operated as a
desulfurization unit by UOP during 1974-
1976, during which it was established
that the SOX accepting material (copper
oxide supported on alumina) is stable in
this service and that the reactor design
(parallel passage) can function effectively
on flue gas containing a full load of coal
fly ash.
Between 1973 and 1975, laboratory
experiments and field tests (SYS) proved
the activity of copper as the oxide or the
sulfate to catalyze the selective reduction
of nitrous and nitric oxides with ammonia
to nitrogen and water. The feature of NOx
reduction, simultaneous with SO,reduc-
tion, was successfully added to the SYS
operation in 1975.
In September 1976, the EPA invited
proposals (RFP No. DU-76-A122) for the
operation of pilot plants to treat flue gas
from coal-fired utility boilers for the
reduction of NO»and/or the simultaneous
reduction of NO, and SO,. TKe work was
to be performed on a scale of about 0.5
MW, and the scope was intended to
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provide information to permit a technical
and economic evaluation of the treatment
process that was proposed.
In the response to EPA's RFP, UOP
proposed to demonstrate the SFGT
technology at the TECO pilot plant.
Coupled with the combined NO»/SOx
reduction in the commercial operation on
oil in Japan and the desulfurization pilot
plant work on coal at TECO, the simulta-
neous NOx/SOx operation at TECO on a
pilot scale would provide the last develop-
mental stage before performance in a
full-scale application to a coal-fired boiler
could be represented and guaranteed.
Consequently, EPA awarded Contract
68-02-2676 to UOP early in 1978. The
technical objective of the contract was
simultaneous reduction of NOX and SOx
by 90% each in a pilot unit when treating
flue gas from a coal-fired utility boiler at a
rate equivalent to 0.5 MW. The demonstra-
tion period of continuous operation was
to be a minimum of 90days and was to in-
clude 75 days in compliance with the 90%
reduction requirement of each pollutant.
Process Description
The underlying chemistry of the
process, described extensively in the
technical literature (1, 2, 3, 4), is
summarized here.
Technical Basis
Copper, as copper oxide or copper
sulfate, catalyzes the selective reduction
of NO and NO2 (NOx) in flue gas to
nitrogen and water with ammonia (NH3)
at temperatures of 350-450°C. Conver-
sions and efficiency (ammonia utilization)
are high, resulting in low concentrations
of both NO and NH3 in the treated gas.
If flue gas containing SOX, NOx, and the
reductant ammonia is processed over
copper at 400°C, the copper is converted
first to the oxide, then to the sulfate, and
NOx reduction begins. As the conversion
to copper sulfate continues, the NOx
concentration of the treated gas decreases
to a minimum value and the concentration
of SO2 increases, approaching that of the
untreated gas.
Copper sulfate can be reduced with a
variety of fuels (e.g., Hz, CO, CH4) at
400°C, yielding a concentrated stream of
SO2 and water and-changing the copper
to elemental form.
Thus, the copper system provides the
technical base for flue gas treatment
capable of NOX reduction, SOX reduction,
and the simultaneous reduction of both
(Figure 1). It offers the potential of a dry
process, without waste products, and
with modest energy requirements. The
technical base has been applied (i.e.,
reduced to practice) in several forms: first
by type (NOx-only, SOx-only, and com-
bined NOx/SOx), and then by function (re-
search/development, pi lot/demonstra-
tion, and commercial- or full-scale).
Reduction to Commercial
Practice
The full-scale application of this
technology to a NOx-only process is as a
fixed-bed reactor with provisions for
ammonia introduction and mixing. The
reactor is of special design-to accommodate
fly ash (Figure 2). The catalyst is
contained in woven-wire baskets sus-
pended in the gas stream so that the gas
flows in the open channels between
baskets (parallel passages). The reactants
enter and the products leave the catalyst
bed by radial diffusion. The design is
'modularized in units of cells, 0.5 m
square by 1 m long, which can be stacked
one atop another for the required space-
time.
For SOx removal, the operation is cyclic
and requires that the reactor be isolated
from the flue gas circuit for regeneration,
producing a concentrate of S02 and
restoring the copper to elemental form.
Flue gas is processed continuously with
multiple reactors, at least one of which is
always in regeneration. A unit designed
for SO, removal can operate in NOx -only
reduction mode by adding ammonia and
eliminating the regeneration step. A unit
designed for SOX removal also can
operate to provide simultaneous NOx
reduction by introducing ammonia to the
untreated flue gas during the acceptance
step.
The performance characteristics of the
design are such that the percent SOa
removal is high at the initiation of
acceptance and "slipped" S02 (SO2 in
treated gas) increases as the sulfur
loading of the acceptor material increases
with acceptance time. Control of time-
averaged percent de-SOx is obtained by
adjusting the acceptance time. Slipped
NOx with time is the reverse (mirror
image) of that for S02; NOX slip is high at
the beginning of acceptance and decreases
with acceptance time (see Figure 3).
There are two ways to increase the de-
NOx performance while holding the SOX
removal constant at 90%. In the first, the
initial NOX slip is decreased using some
combination of: (1) ammonia injection
time and rate, (2) incomplete regeneration
to leave a heel of su(fated copper which
provides a catalytic function immediately
when flue gas is introduced, and (3)
partial oxidation with air and temperature
reduction at the reactor inlet before
initiation of acceptance. In the second
method, the acceptance period is increased
with enough reduced space velocity to
offset the initial NOX slip to the desired
average level.
This reduction-to-practice is called the
SFGT process. Commercial applications
have been in operation since 1973
treating flue gas from various fuels not
including coal.
Equipment and Operation
A simplified process flow of the test
unit used in this program (UOP Pilot Plant
247) is shown in Figure 4. Flue gas is
taken from boiler No. 2 at Tampa Electric
Company's Big Bend Station at the outlet
of the economizer through approximately
50 m of insulated 14-in. (35.56 cm) pipe;
1 1/2 Oz
^-
(a+1)H2—+y.
Jf aCuSQt
aSOz d ~ <*> CuO
(a + 1) H20
Regen. Off-Gas
Figure 1. Basic chemistry.
Flue Gas
Outlet
Flue Gas
Passage
Acceptor
Material
Gauze Layer
Figure 2.
Flue Gas
Inlet
Principle of parallel passage
reactor.
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450
400
i I i r r
At Reactor Inlet:
I
I
c
-------
pressure testing of the reactor, cell-stack
bypassing, ammonia and flue gas mixing,
and distribution. Calibration of instruments
— flow meters, and temperature and
pressure indicators — was frequent and
conformed to UOP standard pilot plant
practice.
Each start-up after a turnaround was
carried out in a "clean" plant, one from
which fly ash had been removed mechani-
cally as part of the turnaround. Initial
operation used air with pollutants added.
The "air" base performance for that run
was determined in tests of 99-minute
acceptance time (maximum for the
sequencer) during which the reactor inlet
and outlet concentrations of S02 and NO*
were monitored continuously yielding
"slip" curves for these species. (Slip
curves are plots of pollutant concentrations
in the treated gas versus time; i.e.,
pollutants which slipped through the
monitor.)
Process Performance Testing
NO and NO2 were analyzed continuously
with on-line analyzers in the reactor inlet
and outlet. SOz was also monitored with
on-line analyzers in the reactor inlet and
outlet, and in the regeneration off-gas.
NH3/NOx ratio was calculated from a
metered rate of NH3 addition, a metered
rate of flue gas, and NOX analysis in
untreated flue gas. Continuous SO3 and
NH3 monitoring was attempted but never
achieved; instead wet absorption methods
were used late in the program which, by
their nature, represent time-averages.
Results
Eleven runs were carried out in the
demonstration/pilot unit (UOP Pilot Plant
247). Runs 1 -6 were completed in 1974-
1976 for reduction of SOx-only on the
same load of acceptor; the results have
been reported (5). Runs 7-10, under EPA
Contract 68-02-2676, included cyclic
tests for simultaneous NO«/SOX reduc-
tion and non-cyclic tests for NOx-only re-
duction on sulfated copper acceptors,
commercial preparations (SK-501 and
SC-501) furnished by Shell, and a proto-
type UOP acceptor (SOx-1 -2). Run 11 de-
monstrated the selective catalytic reduc-
tion of NO, over a catalyst in commercial
use in both Japan and the U.S. (at Flet-
cher Refining Company). The catalyst (JP-
501) is promoted vanadium on a support
resistant to sulfation. Although the test
work on Run 11 was not funded by the
EPA contract, it is included in the report to
indicate the performance for this catalyst
in coal-fired service.
An operational summary covering
Runs 7-11 is shown in Table 1. There
were approximately 300 days of cyclic
and non-cyclic operation. For simultaneous
NOx/SOx operation, there were over
2000 cycles of 1-2 hours cycle length.
During the NOx-only operation, tests
were represented by operating data
recorded approximately every 1 or 2
hours.
Shown in Table 1 is the performance
average for tests on those days which
qualify as "demonstration" days in that
the unit was in test for 18 hours of each
24 hour period of continuous plant
operation; i.e., the ratio of tests to cycles
was equal to or greater than 0.75. There
were three such periods, one in Run 9
and two in Run 10. In each, the unit was
operated for 90% de-SOx and the de-NOx
determined at NH3/NO« = 1.2-1.25.
Under these constraints, the de-NOx
increased from 70 to 80 to 90%; plant
operation was stable in each
demonstration period.
The step-wise improvement in NO»
performance was attained by
lengthening the acceptance period to
increase the cumulative NOX reduction.
This was possible by adjusting operating
conditions and capacity of acceptor for
sulfur in order to hold cumulative de-SOx
at 90% as the acceptance time was
increased from 63 to 86 to 99 minutes
(see Table 1).
Although the project performance
objective of 90% reduction of both SO*
and NOx was achieved, the demonstration
was not continued for the initially
planned 90 days.
/VOx/SOx Operation
During the initial phases of Run 10,
base or reference performance was
established with air plus added pollutants
and a 1-week performance evaluation
was completed preceding a scheduled
outage of the TECO boiler. Tests with flue
gas began with Cycle 43 and continued
for 7 days. Acceptance time was set at 85
minutes to give an average de-SOx of
90%, and with an NH3/NOX ratio of 1.20,
the average de-NOx was 79%.
Following the boiler outage, the unit
was brought up on air only to operating
temperature, the flue gas circuit was
established through the bypass, and flue
gas was processed through the reactor
without regeneration to convert
completely the oxide to sulfate in
preparation for non-cyclic NOX reduction.
The first 99 minutes of acceptance were
monitored, yielding the following results:
Reynolds No. (NRe)*
Inlet SOz/NOx, ppmv
Reactor Inlet Temp., °C
NH3/NO
Cumulative Reduction, %
SOz
NOx
2000
1940/407
390
1.21
91.4
90.3
"In this work, Reynolds No. is directly proportional to
the gas mass flow rate through the reactor.
The de-SOx performance was as
expected; i.e., the sulfur loading capacity
of the bed at 90% cumulative removal
was 90% of the 2000 ppmv S02 entering
the reactor at 2000 Reynolds No. for 99
minutes. The NOx reduction showed that
99 minutes of acceptance is long enough
to average down the high initial slip
which occurs during the first 10 minutes
into acceptance. But two other conditions
existed during this test which affect both
SO2 and NOxSlip curves; i.e., acceptance
was started with copper as the oxide and
the oxidation temperature wave traversed
the reactor so that acceptor temperature
at the reactor inlet was about 400°C.
Laboratory experiments with copper
oxide and a fixed NH3/NO« ratio of 1.0
show that the characteristic maximum in
NOX reduction with temperature occurs at
about 350°C. At 400°C the net relative
rate of oxidation of NH3 to reduction of
NOX has increased such that net reduction
of NOx has declined; i.e., at 400°C copper
oxide no longer selectively catalyzes the
desired reaction. Similar laboratory
experiments with copper in the sulfate
state show greater selectivity toward
promoting the reduction over the oxidation
reactions up to 450°C, beyond which
oxidation takes over.
The reaction rates of selective catalytic
reduction of NOx or acceptance of SOX are
not very temperature sensitive at 400°C,
but NH3 is oxidized readily at 450°C in the
presence of copper oxide and competes
successfully with copper for oxygen at
500°C+, both conditions which exist at
the entrance of the catalyst bed when flue
gas first contacts regenerated acceptor.
The time-averaged NH3 emission value
for the first 15 minutes (i.e., during the
oxidation period) was measured at 2 ppm;
that from 50 to 77 minutes averaged 17
ppm. Also explained is the reduced NOX
slip at initiation of acceptance when
processing air plus pollutants, even
though (in steady-state operation for NOX
reduction only) performance is essentially
the same for flue gas and air plus
4
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Table 1. SFGT Operation Summary, EPA Contract 68-02-2676
Run Number 7 8
Dates of Operation 6/2/79-12/17/79 2/8/80-4/19/80
Acceptor Catalyst SK-501 Blend SC-501
Cells Loaded 6 (Fresh)
KG Acceptor Loaded 40 1
GMo/es Copper Loaded 327
Total Operating Days (Cycles) 99/10747)
Days of Cyclic Air • Pollutants go
Days of Cyclic Flue Gas 9
Days of Steady State A • P 0
Days of Steady State FG 0
Total Days Plant Outage 97
Total Days TECO Outage 2
SO, NO, Demonstration
Dates of Operation
Operating Days (Cycles)
Compliance Days
Avg. Performance
DeSO,%
DeNOf/o
Acceptance Time Min
NHi/NO,
/VR.
Sulfur R,<%
R, Inlet °C
NO, Only Demonstration
Dates of Operation
Operating Days
Compliance Days
Avg. Performance
DeNO,%
NHs/NO,
/Vn.
R,Avg°C
Key Descriptor Mechanical
Shakedown
6 (Fresh)
(New Cells)
357
300
54(5341
34
14
4
2
13
20
Process
Shakedown
9
5/9/80-8/24/80
SC-501
6 (Screened)
1 (Fresh)
471
389
89(511)
11
34
8
36
19
11.
/\
6/13/80-7/7/80
22(291)
17
904
69.0
62.8
1.24
2000
100.8
412
7/8/80-8/18/80
35
31
89.5
1.26
1998
416.0
Demo With
Shell Acceptor
10 11
9/ 1 5/80- 1 1 /3/80 11/1 2/80- 1 1 / 24/80
SO.-? -2 JP-501
6 (Fresh)
270
472
48(198)
7
26
7
7
3
4
NO PREOX PREOX
9/30/80-10/7/80 10/28/80-11/3/80
7(561 5(34)
6 4
90.0 90.5
79.0 90.3
85.9 99.0
1.20 1.23
2033 1498
95.9 96.4
388 386
10/14/80-10/20/80
7
Variable Study
Demo With
U OP Acceptor
2 (Fresh)
192
—
17
0
0
?
15
0
0
NO, Testing
W Fletcher
Catalyst
pollutants. Copper oxidation is 10 to 20
times faster for air than for flue gas since
the oxidation rate is limited by the rate at
which oxygen is supplied to the oxidation
front.
To circumvent the NHa combustion
problem and high initial slip of NO,, a
preferred procedure would be to leave an
unregenerated "heel" of copper sulfate
in the bottom cell for NO, redu'ction at
initiation of acceptance, but this would
be at the expense of sulfur loading
capacity and acceptance time and would
not avoid the temperature wave resulting
from copper oxide formation.
Ammonia emissions, time-averaged
over the acceptance period, were 10-20
ppmv with an NH3/NO, ratio of 1.2. This
average was the same for the conventional
cycles with 90/80% SOx/NO, reduction
and the modified cycles with separate
oxidation/cooling steps in which the
reduction was 90/90%. The NH3 required
for the increase in de-NO, with modified
cycles using the same ratio was burned
during oxidation in the conventional
cycles.
Measured SOa content of the treated
flue gas, time-averaged over the accep-
tance period, was less than 3 ppmv,
indicating SOa reduction of 70-90%. This
result, consistent with the proposed
mechanism of the S02/CuO reaction,
was not unexpected. Copper oxide reacts
directly with SOa at acceptance conditions
and will remove SOa and S02 from flue
gas, the latter probably as SOa after
surface oxidation of adsorbed S02.
Laboratory experiments indicate that the
SOa in the treated gas increases with
temperature and sulfur loading and is not
dependent on the SOa content of the
untreated gas. At a given temperature,
the SO3 increases to a maximum as the
sulfur/copper ratio approaches unity and
then declines rapidly with higher sulfur
loadings, indicating that CuS04 does not
catalyze S02 to S03 oxidation.
NOi-Only Operation
The performance of the fully sulfated
acceptor was determined in the early
stages of Run 10 with air plus added SO,
and NO, and with the plant free of fly ash.
Later in the run after processing flue gas
for about 3 weeks in simultaneous
N0,/S0x operation, the acceptor was
completely sulfated in flue gas, and de-
NO, performance was measured again.
Recognizing that (1) control of the
adiabatic heaters was not uniform, (2)
NHa/NO, ratios were not precise, and (3)
the oxygen content of the untreated gas
was at times low due to fuel-rich
operation of the in-line heating units, the
NOx reduction was judged to be equivalent
to that observed early in the run,
indicating that the presence of fly ash has
little effect on catalytic reduction activity.
The performance of the sulfated
acceptor may be summarized as follows:
Temperature, °C
NOx Reduction,
% (6 stages)
NOx Reduction,
%/Stage
NHa Slip, ppmv
NHa/NOx
1.0
415
85
27
10
Mole Ratio
1.2
415
95
39
30
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Laboratory studies of the copper-SOa
system showed that copper sulfate does
not catalyze the S02 oxidation. It was,
therefore, expected that SOa in and out of
the reactor should be substantially the
same over sulfated acceptor. Given that
both accuracy and precision of the
controlled condensation method for SOs
analysis are low, this conclusion was
essentially confirmed with five tests on
five days showing consistently lower SOs
content in the treated gas than in the
feed.
In preparation for Run 11, two cells
were loaded with JP-501 catalyst and
positioned in the reactor atop three and
below two empty cells in a stack of seven.
With this arrangement, seals and gasket-
ing procedures were unchanged from the
previous run. De-NOx performance at
400°C with a gas rate of 28 standard
(16°C) cubic meters per minute (scmm)
(2000 IMRe) was 45, 65, and 85% at
NH3/NOx ratios of 0.5, 0.75, and 1.0,
respectively. The corresponding NH3
content inthe treated gas was 15, 25,and
50 ppmv, consistent with little NH3 loss
due to oxidation. Further, the percent NOX
reduction was insensitive to throughput,
temperature, and fly ash. At a ratio of
0.75, 65% NOX reduction was measured
at flue gas rates of 21,28, and 35 scmm
(1500-2500 NRe) and decreased to 63%
as the temperature was reduced from
400 to 325°C. Tests with air plus
pollutants at the beginning of the run in a
clean plant showed the same 85% NOX
reduction (61% per stage) as with flue gas
at a NH3/NOx ratio of 1.0.
Commercial Design
UOP's proposal to the EPA in 1976
contained process specifications for the
design of a SFGT unit to reduce by 90%
the SOx and NOX in the flue gas from a
500 MW, coal-fired utility boiler when
operating at rated load. This was the basis
for an estimate of capital requirements
and first year annual operating charges.
In this design, flue gas from the
economizer is fed directly to a battery of
eight reactors, six of which process flue
gas while two are in regeneration. Fans in
series with the reactor system supply the
pressure drop for the entire treater
circuit. The fans/reactor complex is in
parallel with flue gas ducting, between
the economizer and preheater (see
Figure 5). With this arrangement, the
flue gas flow bypassing the treatment
system is boiler output less treater feed.
The fans are selected in size and number
so that there could be some recycle of
treated gas at any boiler load. The boiler
and the SFGT sections are isolated from
each other, and turndown of the treatment
unit is continuous from zero to 100% of
rated load. The location of the treatment
system upstream of the air preheater
permits recovery in the combustion air of
the sensible heat in thef lue gas above the
acid dewpoint temperature. This includes
reaction heat absorbed by the treated gas
and incremental sensible heat available
due to reduction of S03 in the treater.
The regeneration off-gas, containing
SOz, water, slipped hydrogen, and small
amounts of CO2, CO, and ChU, is cooled,
water is condensed, and the concentrated
SO2 compressed into a gas holder from
which it is released on flow control to a
modified Claus. The first stage of the
Claus prepares Claus feed (2 parts H2S
and 1 part S02) from the S02 in the gas
holder product in a thermal and catalytic
reactor. Part of the reductant is the
slipped H2, CO, and Cmfrom regeneration.
The balance is reducing gas supplied
from the hydrogen manufacturing unit.
Claus tail gas is recycled to the SFGT unit
through the furnace of the boiler (see
Figure 6).
The feed and fuel to the hydrogen
manufacturing unit may be any low-
sulfur light-hydrocarbon stream from
methane through light naphtha. Since
the feed/fuel requirements, expressed as
heat of combustion per unit of hydrogen
produced, is constant, the selection is
economic; i.e., natural gas would be used
Pulverized
Coal
Stack
F.D. Fan
Figure 5. Flow diagram for flue gas from steam generator, showing tie-in for flue gas
treatment.
Producing Gas
Supply Section
Reactor
Section
Flow Smoothing
Section
1 1
Work-Up
Section
1
Steam
Light
Hydrocarbon
Reforming
Reactor
Section
Gasholder
Compressor
Modified
Claus,
NH3
Flue
Gas
Figure 6. Block diagram of SFGT system.
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in the current market. The hydrogen plant
has one stage of shift conversion and
pressurized swing adsorption for CO2
removal.
The process specificationsforthe SFGT
system were developed with reaction
kinetics applicable to flue gas containing
low concentrations of fly ash; e.g., flue
gas from refinery fuel gas and fuel oil.
Qualitatively it was known that fly ash in
the interstitial space and pore structure of
the acceptor would increase diffusional
resistance and reduce acceptance time
and sulfur loading. To compensate for
this effect, the amount of acceptor was
increased by 20%; i.e., the number of
stages was increased from five to six.
From NOx-only and combined NOx/SOx
tests in laboratory reactors (isothermal), it
was estimated that 90% NO* reduction
could be achieved with a NHs/NOx ratio of
1.0. The design specifications prepared
for the proposal are summarized under
Case 1 of Table 2.
The design specifications of the pro-
posal were modified in two steps. In the
first, the reaction kinetics for SOx
reduction were adjusted from "Clean" to
"Dirty" service using the data generated
in the demonstration tests of Run 9. The
results are shown in Case 2 of Table 2.
To retain the same cycle (acceptance time
and regeneration time), treated gas is
recycled (10%) and parallel passage
Reynolds No. reduced to 1860. The
reduction of S02 and NOx across the
reactor is 89 and 69%; and across the
system, 90 and 71%.
In the second modification, the bed
length is increased by a stage containing
the JP-501 NOx reduction catalyst tested
in Run 11. This stage, placed at the
reactor inlet, reduces the NOX concentra-
tion at the inlet of the acceptor stages to
35% of that in the reactor feed, giving a
reduction of 89% across the reactor [65 +
(35 x 0.69)] and 90% across the system.
From these specifications, given in
Table 2, Case 3, economics were deve-
loped. Capital and operating costs
increased by 12 and 21%, respectively,
due to the effect of fly ash, and further
increases of 7 and 5% in capital and
operating costs compensate for the
combustion of Nhb at the initiation of
acceptance.
Conclusions
Within the constraints under which this
project was carried out, a number of
conclusions can be drawn which are
consistent with and confirmed by the test
lata obtained.
These constraints include:
• The flue gas processed was derived
from the combustion of blends of
coal from Western Kentucky, Poland,
and Australia in a Riley-Stokerturbo
(wet bottom) boiler of approximately
400 MW capacity; the sulfur content
of the fuel was about 3%.
• The slipstream of flue gas was taken
between the economizer outlet and
air preheater inlet, transported at
high velocity to the demonstration
plant to avoid saltation, and heated
by in-line combustion of propane to
replace heat losses. Approximately
1600 NmVh (ca. 0.5 MW equivalent)
was processed for SOX and/or NOX
reduction.
• The on-line analyzers monitoring
NOx/SOa into and out of the reactor
provided accurate, reproducible,
continuous measurements, both for
simultaneous NOx/SO2 and NOx-
only operation. The NH3 and SOa
analyses were based on time-
averaged values from wet chemical
methods.
• The usual range of S0» in flue gas
was 2000-2500 ppmv; that of NOx,
250-400 ppmv.
• Three acceptor/catalysts with sup-
ported copper were used in the five
runs which constituted the opera-
tional phases of the program. The
first two, SK-501 and SC-501,
represented different commercial
lots. The third, SO«-1-2, was a
prototype not in use commercially,
with increased capacity for sulfur.
JP-501, a commercial selective NOX
reduction catalyst, was given a brief
process evaluation in the last run.
• For desulfurization, process time
was composed of a series of cycles,
each of which consisted of accept-
ance, purge, regeneration, and
purge. Such a cycle is referred to as
a standard or conventional cycle. For
the final stages of the simultaneous
NOx/SOx program, the standard
cycle was modified to remove the
heat released from copper oxidation
before initiating acceptance. This is
defined as a modified cycle. Accept-
ance was upflow; regeneration,
cooling, and purging were downf low.
• The parallel-passage reactor was used
exclusively throughout the program.
Conclusions are:
1. With the copper acceptor/catalyst,
pollutant reduction exceeding 90%
can be obtained for either SOxJSOa +
S02) or NOx (NO + N02), the former as
a non-steady state operation with
standard cycles, the latter as a
Table 2. Design Specifications, SFGT System
Nominal MW of Boiler
Flow Gas from Economizer
Rate. Nm3/h x W6
Temperature, °C
SO* vol-%
No» vol-%
SFGT Reactors
Feed Rate, Nm3/\\ x 1CT6
Temperature °C
SO*, vol-%
NO* vol-%
Recycle, %
Cell Reynolds No.
Bed Length, m
Reactor Diameter, m
Reactors, A ccepting/Regenerating
Acceptor/Catalyst, kg/reactor
Acceptance Time, minutes
Acceptor Loading, mot S/mol Cu
% cte-SO,
% de-NOt
SFGT System
System AP, cm HZO
% de-SOt
500
1.657
400
0.2580
0.0634
Case 1
1.657
400
0.2580
0.0634
0
Case 2
1.823
400
0.2368
0.0593
10
Case 3
1.823
400
0.2368
0.0582
10
2,OOO
6
7.4
6/2
54.000
66.0
0.74
90.0
90.0
1,860
6
8.0
6/2
68,000
66.0
0.56
89.0
69.0
1,860
7
8.0
6/2
80,000
66.0
0.56
89.0
89.0
44
90.0
90.0
30
90.0
71.0
32
90.0
90.0
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continuous operation with sulfated
acceptor as a selective reduction
catalyst.
2. For simultaneous reduction of SOx/
NOX with cyclic operation using
standard cycles, and with cycle
time adjusted for 90% de-SOx,
time-averaged de-NOx was limited
to 80% at a NH3/NOx ratio of 1.2.
3. For simultaneous reduction of
SOx/NOx with modified cycles,
timed for 90%de-SOx, time-averaged
de-NOx increased to 90% at a
NHs/NOx ratio of 1.2.
4. Including oxidation of copper, with
the accompanying temperature
front, into the acceptance mode
may result in a net production of
NOx from NH3 at the beginning of
oxidation.
5. Time-averaged over the entire
acceptance period, the slipped NH3
at NH3/NOx =1.2 was 10-20 ppmv.
6. Copper oxide reacts readily with
S03; SOa oxidation to S03 is not
catalyzed by copper sulfate.
7. For a given concentration of copper
oxide in the acceptor, the rate of
SO, reduction is decreased by fly
ash in the catalyst envelope, by an
increase in flue gas throughput,
and by a decrease in temperature.
Both mass transfer and the effective
reaction rate represent significant
resistances.
8. NOx reduction is insensitive to
fly ash, throughput, and tempera-
ture. Mass transfer controls.
9. The promoted vanadium catalyst is
an active de-NOx catalyst usable
over a wide range of temperatures,
but may be unsuitable in applica-
tions with high concentrations of
SO2 due to SO3 production.
10. The parallel passage design is an
effective contacting device for
catalytic systems processing flue
gas from coal-fired boilers in the
presence of full gas loadings of fly
ash.
References
1. AVCO Corporation, A Survey of
Metal Oxides as Sorbents for
Oxides of Sulfur. EPA Report APTD
1178 (NTIS PB 185190), February
1969.
2. McCrea, S.H.,A.J.Formey,andJ.G.
Meyers, Paper presented at 63rd
Annual Meeting of Air Pollution
Control Association, St. Louis, MO,
June 1970.
3. Dauzenberg, F.M., J.E. Naber, and
A.J.J. van Ginneken, The Shell Flue
Gas Desulfurization Process, Chem.
Eng. Prog., 67, 1971.
4. Pohlenz J.B., NOX and SO, Emissions
Control with the Shell Flue Gas
Treating Process. 72nd Air Pollution
Control Association Meeting, Cincin-
nati, OH, June 1979.
5. Arneson, A.D., F.M. Nooy, and J.B.
Pohlenz, The Shell FGD Process —
Pilot Plant Experience at Tampa
Electric. In: Proceedings: Symposium
on Flue Gas Desulfurization —
Hollywood, FL, November 1977
(Vol. II). EPA-600/7-78-058b (NTIS
PB 282091), pp 752-793, March
1978.
6. Imanari, M.,Y. Watanabe, S. Matsuda,
and F. Nakajima, 7th Int. Congress
on Catalysis, Tokyo, Japan, 1980.
7. Levenspiel, Octave, Chemical React-
tion Engineering, John Wiley and
Sons, New York, NY, 1972.
J. B. Pohlenz and A. 0. Braun are with UOP, Inc., Des Plaines, IL 60016.
J. David Mobley is the EPA Project Officer (see below).
The complete report, entitled "Shell /V0,/S02 Flue Gas Treatment Process: Pilot
Plant Evaluation," (Order No. PB 84-102 367; Cost: $49.00, 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
US. OFFICIAL MAIL.
United States
Environmental Protection
Agency
Center for Environmental Research
Information
Cincinnati OH 45268
Official Business
Penalty for Private Use $300
it U.S. GOVERNMENT PRINTING OFFICE 1984-759-102/816
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