AN EXAMINATION OF
ALKALI INJECTION • WET SCRUBBER PROCESS
DEMONSTRATION PROJECTS
NOVEMBER 1970
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MTR-1494
II'
,
AN EIAMINA TION OF
ALKALI INJECTION. WET SCRUBBER PROCESS
-
0'-
DEMONSTRATION PROJECTS
L. HOFFMAN
K. E. YEAGER
NOVEMBER 1970
Contract No.:
Fl9628-68-C-0365
Contract Sponsor:
National Air Pollution Control Administration
Project No.: 839C
THE
1\1ITRE
This document was prepared for authorized distribution.
It has not been approved for public release.
CORPORATION
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Department and
Project Approval:
Richard S. Greeley
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ABSTRACT
This paper discusses the operating experiences of two electric
utility plants with prototype installations of the alkali injection-
wet scrubber S02 removal process.
. 0
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TABLE OF CONTENTS
INTRODUCTION
DESCRIPTION OF THE PROCESS
UNION ELECTRIC EXPERIENCE
KANSAS POWER AND LIGHT EXPERIENCE
PROCESS COST ESTIMATES
REFERENCES
SUMMARY DISCUSSION
. ~
DISTRIBUTION LIST
LIST OF ILLUSTRATIONS
FIGURE NUMBER
1
ALKALINE INJECTION-WET SCRUBBING S02 REMOVAL
PROCESS AS APPLIED TO UNION ELECTRIC MERAMEC
STATION UNIT 112 AND KANSAS POWER AND LIGHT
LAWRENCE STATION
2
ALKALI INJECTION-WET SCRUBBER OPERATING COST
TABLE NUMBER
SCRUBBER OPERATING LOG
I
II
III
c
IV
V
VI
OPERATING ECONOMICS
CAPITAL COSTS FOR 140 MW UNIT WET SCRUBBER SYSTEM
FIXED CHARGES, LABOR, AND MAINTENANCE
SUMMARY OF ESTIMATED AND PROJECTED OPERATING COST
COMPARISON OF UNION ELECTRIC COMPANY AND KANSAS
POWER AND LIGHT COMPANY.
v
Page
1
1
6
9
10
16
20
21
Page
2
15
8
11
12
13
14
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AN EXAMINATION OF THE ALKALI
INJECTION-WET SCRUBBER PROCESS DEMONSTRATION PROJECTS
INTRODUCTION
This paper describes the alkali injection-wet scrubber demon-
stration projects currently being performed at Union Electric CompanYt
St. Louist Missouri, and the Kansas Power and Light Company (KPL),
Topekat Kansas.
The purpose of this paper is to examine the techni-
. "
cal and economic factors associated with the commercial scale alkali
injection-wet scrubber S02 emersion control systems installed in
generating plants at these two utility companies. Although a number
of commercial flue gas S02 removal systems are in various stages of
development, the scrubber process installed at Union Electric and
KPL is the only one for which full-scale utility operating experience
is available.
The use of these flue gas treatment processes in
conjunction with coal pyrite removal prior to combustion may be
most practical method of achieving S02 emission goals without
excluding the majority of utility coal fuel sources.
the
DESCRIPTION OF THE PROCESS
1. The tailend S02 removal process used by both Union Electric
and KPL may be described as the Alkali Solids Injection-Wet Scrubbing
Figure 1.
The utility installation of the process is diagrammed in
In this process a solidt alkaline material (dolomite or
Process.
"
limestone) is calcined by direct injection into the high-temperature
section of the boiler. The solid calcined material reacts in the dry
state with about 20% of the sulfur oxides present in the boiler gas
stream, forming solid alkali-sulfur compounds. These compounds,
unreacted additives, and flue gases enter a wet, turbulent-bed scrubber.
The unreacted calcined additive dissolves in the solution circulating
through the scrubber, supplying its alkalinity. Sulfur dioxide and
any sulfur trioxide present in the flue gas dissolve in the same
1
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DEMISTER
N
RECYCLE
LINE
(MODIFICATION)
SURGE
TANK
+
PUMP
REHEAT SOOT
BLOWER
DEMISTER
SPRAY LINE
SPRAY
WATER
LINE
SPRAY
PU~IP
MAKE - t:P
DOTTED LI~E I,N_D_I_C_A_T,ES UNIO~ WATEiR
ELECTRIC I~STALLATION ONLY
- --- ----------------,
I
I
"~j;J [~S::J~:~~:
---O--u---~ :
I : UNDERFLOW CLEA.~!
: PilllP RECYCLE
FIGURE I
ALKALINE INJECTION - WET SCRUBBING S02 REMOVAL PROCESS AS APPLIED TO
UNION ELECTRIC MERAMEC STATION UN IT # 2 AND KANSAS POWER AND LIGHT LAWRENCE STATION
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solution and react with the alkali to form sulfites and sulfates.
In
practice, this removes about 65% of the sulfur oxide in the flue gas.
Because the solution circulating through the scrubber is saturated,
these sulfites and sulfates precipitate and exit the scrubber as a
slurry.
On the order of 99% of the ash and any other particulates
present in the flue gas are also removed in the scrubbing process.
The settled solids from the scrubber, containing the sulfur and ash
. u
removed from the flue gas, are dewatered for disposal.
Although no efforts are made to recover marketable sulfur, the
system is attractive because of its simplicity and low cost of instal-
lation relative to other tailend processes.
It appears equivalent in
cost to the tall stack and electrostatic precipitator combination with
the advantage of both particulate and S02 removal.
2.
Basic Operations and Probable Associated Reactions.
The probable reactions occurring during each reactive phase of the
alkali solid injection-wet scrubbing S02 removal process may be sum-
marized as follows:
a.
Injection of Alkali Solids - Calcination
CaC03.MgC03(s)--'CaC03(s) + MgO(s) + C02 (g)
(1)
Reaction temperature = 850°F - 1900°F
CaC03(s)--.CaO(s) + C02 (g)
(2)
Reaction temperature = l400°F - 2250°F
b.
Dry State Reactions in Furnace
CaO.MgO(s) + S02(g) + ~02(g)--.CaS04(s)'MgS04(s)
CaO.MgO(s) + S02(g)--.CaS03(s)'MgS04(s)
CaS03.MgS03(s) + ~02(g)--.CaS04(s)'MgS04(s)
(3)
;)
(4)
(5)
Reaction temperature = l400°F to l550°F (lower temperature
limit for calcination of CaC03 to upper temperature limit
for MgO + S02 reaction)
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c.
Flue Gas Scrubbing
soz (g) + OH- (1) _HSO; (1)
HSO;(l) + OH-(l)-+SO;(1) + HZO
-++ -++
CaO(s)'MgO(s) + ZHZO(l)-+Ca 'Mg (1)
-++ -++ =
Ca 'Hg (1) + ZS03(1)-+CaS03.MgS03(s)
CaS03.MgS03(s) + 0Z(g)-+CaS04'MgS04(s)
(6)
(7)
+ 40H- (1)
(8)
(9 )
" .
(10)
3.
The economic credit of the alkali injection-wet scrubber
process is corrosion reduction at both high and low temperatures.
At high temperature the sulfur contaminants in coal can form K3-or
Na3 Fe (S04)3' a corrosive compound which in its molten state at
temperaturesabove 1100°F can cause corrosive damage to super-heater
and reheater pipes.
This has forced the utility industry to stabilize
boiler steam temperature at 1000°F to avoid the costs of maintenance
and power outages caused by corrosion.
These costs have been estimated
at 10 to ZO cents per ton of coal burned, depending on the coal compo-
sition.
This corrosion "barrier" has restricted the development of
higher temperature, more thermally efficient steam cycles when using
coal as a fuel.
Limestone and dolomite preferentially retain the alkalies
as double salts of the type KZ CaZ (S04)3 thus preventing formation of
the corrosive alkali-iron-trisulfate.
In the lo~ temperature section of the boiler, the air reheater,
and the flue gas ducts, sulfur trioxide reacts with water vapor in the
flue gas to form sulfuric acid.
If the flue gas temperature falls below
the acid dewpoint. the acid condenses and corrodes the surrounding
metallic surfaces. The magnesium oxide in dolomite has been shown to
effectively reduce the low temperature corrosion through removal of the
gaseous sulfur trioxide during the combustion process.
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4. An important consideration in this wet scrubber SOZ removal
system is possible pollution of ground water by the process effluent.
The calcium sulfite formed in the process is a particular danger since
it will remove oxygen from ground water if settling ponds are not care-
fully isolated.
The possible basicity of the process effluent can also
seriously effect the ecological balance if drainage into surrounding
streams occurs.
A third factor necessitating effluent isolation is the
formation of magnesium sulfate, more commonly known as Epsom salts,
when dolomite is used as a reactant.
.L
5.
Both the Union Electric and KPL scrubber systems were designed
and installed by Combustion Engineering, Inc.
The KPL system, however,
involved relatively more direct engineering support from the KPL engi-
neering staff during design and installation.
6.
Both utilities had basically fixed-price contracts with
Combustion Engineering for the design, fabrication, and installation
of the scrubber system.
Improvement modifications after installation
have been performed at Combustion Engineering's expense.
7.
The wet scrubber system designed by Combustion Engineering
had previously been employed on a pilot plant scale at Detroit Edison.
On the basis of this experience, Combustion Engineering announced to
the utility industry that they had a SOZ removal system in which suf-
ficient confidence was available to guarantee performance. Combustion
Engineering, in addition, requested that the utility industry provide
operating utility plants to demonstrate the full scale capability of
the system.
Union Electric and KPL responded because this appeared to
'-'
be the least expensive and most reliable SOZ removal system available
to meet or exceed SOZ emission control regulations.
8.
The primary installation and operating differences between
the two facilities may be summarized as follows:
a.
The KPL system is designed with externally controlled baffles
to quickly isolate the scrubber system for maintenance.
The Union
Electric system requires installation and removal of welded-in plates.
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This change to take the scrubber on- or off-line requires 16 welders
for 3 shifts (384 man-hours) plus boiler cool down and start up time.
b. The KPL system uses a dilute scrubber solution as produced
in a 37 million gallon settling pond. The Union Electric system uses
a relatively concentrated solution as produced in a 100,000 gallon
clarifier.
c.
The KPL system currently operates at 110% stoichiometric lime-
stone injection, while Union Electric employs 130%.
This difference may
possibly be traced to excessive calcination in the Union Electric installa-
tion where injection occurs at a higher temperature furnace zone than that
at KPL, plus the use of dolomite rather than pure limestone. The MgC03 in
dolomite has a lower temperature zone for reactive calcination than CaC03.
UNION ELECTRIC EXPERIENCE
Discussions were held with Mr. J. F. McLaughlin, Executive
Assistant, Union Electric Company, to discuss the cleaning concept and
economics.
The Meramec power plant ~"as then visited where conferences
were held with Messrs. Schaefer and Tapperson concerning the scrubber
and its operating history.
tion was closely inspected.
In addition, the inoperative scrubber installa-
Observations are summarized as follows:
1.
The scrubber is presently off-line with modifications being
made.
It is not expected that the unit will be put back into use until
after the high July and August electrical load period.
2.
The system was designed and installed on the Meramec No.2
generating unit between October 1967 and June 1968. The No.2 generating
unit has a maximum generating capability of 140 MW and uses four pulverizers.
When the scrubber is operating, one of the four pulverizers is used to
handle the limestone.
3.
The design of the system is such that the entire generating
unit must be taken off-line and cooled down in order to make any modifica-
tions required.
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4.
Operating the scrubber system has revealed many problems
that were unexpected though not surprising considering the pilot nature
of the installation.
Although the Union Electric scrubber installation
is advertised as a "demonstrator" uni.t, consideration has not been
given to the installation and operating implications inherent in such
as innovative demonstration.
The apparent expectation of immediate
operating reliability has limited the operating and maintenance flexi-
bility designed into the installation.
The resultant expenses in both
o "-~
time and money, plus the fact that Union Electric is mainly coal oriented,
with limited fuel switchover capability, has tended to create a negative
reaction to the scrubber project in Union Electric management.
ficulties have arisen in the following areas:
Dif-
a.
The wash water system for cleaning deposits on the heat
exchanger carried over to the I.D. fans and caused a heavy
build-up of deposits on the fan blades.
required to remove the deposits.
Sand blasting was
b.
In a very short time, calcium sulfate deposits restricted
the overflow drain screens.
c.
When operating the system longer than a few days, plugging
of the marble-bed occured.
d.
The marble-bed plugging caused carryover of water and
solids to the demister and reheater.
As a result, the
reheaters of both scrubbers became plugged.
e.
Deposit buildups have occured at the scrubber inlets.
f.
The clarifier and slurry pumping systems have had
plugging problems.
Extensive modifications have been,and are currentl~ in progress
to overcome problems that have surfaced during system operation.
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Table I shows total days during which the scrubber was opera-
tional and the type of operation during each test period:
TABLE I
SCRUBBER OPERATING LOG
No Gas Firing Coal Firing Total
From To Load 50-125 MW 50-55 MW 100-110 MW Days
9-9-68 10-5-68 4 17 4 25
11-11-68 12-5-68 5 1/2 11 9 25 1/2
2-15-69 3-2-69 8 6 1/2 1 1/2 16
3-16-69 6-21-69 1/2 1 1/2 3 5
10-3-69 10-10-69 3 1/2 3 1/2 7
11-24-69 12-22-69 2 6 20 28
2-16-70 3-25-70* 10 1/2 6 1/4 20 1/4 37
*
Unit was shut down temporarily from March 6 to March 17 but not
converted tv precipitator operation.
The actual period of coal firing at 100-110 MW output is the signif-
icant portion of the total operating period when considering system
performance.
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KANSAS POWER AND LIGHT EXPERIENCE
Discussions were held with Mr. C. Green, Assistant Manager of
Electric Production; Mr. M. Funston, Production Engineer; and ~1r. L.
Brunton, Plant Engineer, Lawrence Power Station.
1.
The wet scrubber system is installed on a 125 MW Unit at the
Lawrence Station for evaluation purposes prior to installation on a
new coal burning 425 MW Unit.
The wet scrubber was chosen because
studies indicated that it could be purchased and installed at the same
cost as an electrostatic precipitator but with the advantage of S02
removal.
2.
The installation on the 125 MW Unit was performed to gain
operating experience and to ensure the reliability of the scrubber
system prior to installation on the new coal fired 425 MW Unit, which
will be in service in 1971.
This attitude, which is significantly
different than that of Union Electric, is reflected in the basic
design of the scrubber installation which permits rapid changeover
from
on-line to off-line for maintenance and experimentation.
The
KPL Utility Company, with the exception of the new 425 MW Unit, is
a gas burning system. Coal use is limited to the winter season when
competing gas demands limit the amount of gas available. This reli-
ance on gas permits continued use of the generator unit without the
scrubber.
KPL installed their scrubber system as an experimental prototype
to ensure. ultimate success of such a system on the first primary coal
fired unit in their system.
It is interesting to note that the KPL
purchased both the prototype scrubber and the scrubber system to be
installed on the 425 MW Unit at the same time. This would motivate
KPL to ensure the success of the project.
Union Electric, on the other
hand, did not consider their scrubber installation as a prototype and,
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as a probable result, did not design maintenance and experimental
flexibility into their installation.
3.
In the KPL system, the optimum quantity of limestone injected
is about 110% of the stoichiometric amount for the CaO + H2S04 reaction.
Originally the installation used a higher percentage of limestone
because of excessive calcination, thus leading to lower than expected
reactivity of the alkali oxides.
This was solved by moving the lime-
stone injector higher in the furnace to reduce calcination temperature.
~
This produces a pH of 5.5 - 6.5 in the marble bed with a resultant
unreacted S02 emission of 300 - 350 ppm (equivalent to about 0.5%
sulfur per ton of coal burned). The tradeoff involved in determining
pH level is operating reliability against higher S02 removal. At a
lower pH, for example 4.5, the reaction produces soluble bisulfite
with no reliability problems but S02 emission increases to about
600 ppm. At higher than optimum pH, S02 emission as low as 200 ppm
has been achieved, but sulfite production rapidly blocks the scrubber
water feed and drain headers.
PROCESS COST ESTIMATES
The following discussion of alkali injection-wet scrubber economics
"is based on the Union
preliminary, based on
tion test experience.
Electric Company estimates. These estimates are
projections developed prior to actual demonstra-
Where noted, these estimates have been modified
to account for demonstration test results to date.
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TP..BLE II
OPERATING ECONOMICS
Costs
Dolomite 11.2% X 2,000 lb. = 224 1b./ton coal
(Dolomite $1.10/ton + frt. $1.67/ton = $2.77/ton)
'-
Dolomite handling & grinding cost
(25 cents/ton dolomite)
Calcining do1omite(extra fuel required-
120,000 BTU/ton coal; coal at 21c/MBTU)
Power Cost
Added disposal cost at $0.50/ton
Makeup water $500/yr.
Cost Total
Credits
Corrosion savings
Precipitator operating savings
Steam coil
Credit Total
Net Operating Costs (without fixed chgs.)
11
(cents)
Per Ton Coal
31.0
2.8
2.5
9.0
5.6
0.1
51.0
(cents)
Per Ton Coal
5.3
2.0
1.1
8.4
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TABLE III
CAPITAL COSTS FOR 140 t~v UNIT WET SCRUBBER SYSTEM
Equipment furnished by Combustion Engineering
*
$ 830,000 ($1,400,000)
240,000
112,000
50,000
15,000
10,000
20,000
10,000
30,000 manhours @ 8.00/hr.
Foundations and concrete
Electrical wiring, starters, etc.
Partition of coal bunker
Slurry concentrate disposal
Fly ash dust hopper discharge
Raw water makeup piping
Total Capital
$1,287,000
($1,857,000)
Assume 15.2% fixed charge rate
195,000
($
282,000)
*
The cost of equipment furnished by Combustion Engineering is
considered to be commercially low for two factors:
(1) Operating experience has indicated that corrosion
resistant materials should be used to achieve practical
reliability. It is estimated that this will increase
equipment costs by about 10%.
(2) Combustion Engineering sold the system at below cost
in an effort to gain entry to the market.. A practical
market price would be on the order of 40% above that
indicated.
Based on these factors, a practical 1970 planning cost estimate
of the Combustion Engineering equipment would be $10 per KW of
plant capacity.
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TABLE IV
FIXED CHARGES, LABOR, AND MAINTENANCE
Cost/Ton Coal Burned (cents)
Estimated Coal Tons
Load 103 Fixed Chgs. Haint. Labor Total
Year Factor % Burned ($195,000) ($39,000) ($10,000) Cents
1967 65 355 55.0 11.0 2.8 68.8
1970 30 165 118.0 23.6 6.1 147.7
1971 28 152 128.0 25.6 6.6 160.2
1975 20 110 177.5 35.5 9.1 222.1
1980 15 82 238.0 47.5 12.2 297.7
1984 11 60 325.0 65.0 16.7 406.7
15 Yr. Avg.
(1970-84)
19
104
188.0
37.5
9.6
235.1
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TABLE V
SUMMARY OF ESTIMATED AND PROJECTED OPERATING COST
Air Pollution Control System
Operating Cost/Ton Coal Burned
Estimated
Load Net Oper. Fixed Chgs. Total
Year Factor % Cost (~) (Labor & ¥Jaint. (~) Cost ($)
1967 65 42.6 68.8 1.11
1970 30 42.6 147.7 1.90
1971 28 42.6 160.2 2.03
1975 20 42.6 222.1 2.65
1980 15 42.6 297.7 3.40
1984 11 42.6 406.7 4.49
15 Yr. Avg.
(1970-84 )
19
42.6
235.1
$ 2.78
These figures must be taken with caution due to the developmental
nature of the installation and limited operating history.
Figure 2
indicates the scrubber operating cost per ton of coal burned for both (1)
the Union Electric estimate and (2) a prediction for general operational
application on existing stationary power plants at the conditions indicated.
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. .
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smtvlARY DISCUSSION
The comparison of the wet scrubber system installation at Union
Electric and KPL are summarized in Table VI.
It is evident that
similar problem areas have been discovered at both.
The Common
problems may be traced to solid deposit buildup caused by the combina-
tion of fly ash, moisture, and calcium sulfate/sulfite. This solid
deposit in the dry state has structural properties similar to concrete.
.
The dilute scrubber solution at KPL has tended to reduce the speed
of this deposit buildup and permit longer scrubber operating periods
,,'
compared to Union Electric.
By the same token, these longer operation
periods have focused attention on corrosion problems which have not
yet been experienced at Union Electric.
Analysis of Table VI indicates that the problems discovered to
date in the full-scale application of the alkali injection-wet
scrubber process may be traced to design deficiencies in the integra-
tion of the scrubber with the utility steam plant, not technical
shortcomings of the scrubber system itself.
The problems encountered
thus far have not been in meeting the S02 and particulate removal
design goals, but rather in maintaining the operating reliability of
the process and the furnace components with which it interfaces.
design deficiencies may be summarized as follows:
These
a.
Inadequate consideration given to handling and disposing
of the large quantities of solid alkali/ash deposits formed
during the full-scale scrubbing process.
b.
Insufficient use of corrosion resistant materials in the
scrubber and associated plumbing.
The factors which create these deficiencies are predictable and
are routinely considered by the chemical industry in scaling laboratory
or pilot plant processes to full-scale operation. Unfortunately the
utility industry and their equipment suppliers do not seem to have
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TABLE vr
COMPARISON OF UNION ELECTRIC COMPANY AND KANSAS POWER AND LICHT COMPANY
1. Furnace
Ins tallation
2. Reactive
Additive
,
3. Begin Install.
Begin Operation 19 September 1968
. .
4. Coal
Properities
5. Primary
System
Installation
Differences
6. Limestone
Ratio
7. Efficiency
8. Problems
[Solutions]
t
UNION ELECTRIC
1
CO.
Tangentially
gas 140 MW
fired coal,
CaC03 . MgC03
October 1967
3% Sulfur, 10% Ash,
11 , 200 B'l'U
(1) Concentrated scrubber
solution from lOOK gallon
clarifier
(2)Difficult on stream/
off stream capability
130% stoichiometric
(11% dolomite by weight)
99% particulate removal
80% S02 removal
(l)Flue gas reheater
water wash system carried
moisture into 10 fan
causing deposit buildup
on fan blades
f~.installed eductor
system on fan boxer.
b.installed plume
reheater]
(2)Calcium sulfate buildup
on overflow drain screen
[increase drain opening
size]
(3)Marble bed plugging
[improved gas distri-
bution]
(4)Reheater plugging
[soot blowem installed]
(5)Scrubber inlet deposits
[soot blowers installed]
(6)Excessive limestone
required for SO removal
[recycle scru5ber underflow
which contains active
calcium hydroxide]
(7)Ash deposit buildup on
underflow return lines
[increase pipe dimension]
17
2
KPL CO.
-----
Tangentially fired gas, oil, coal
125 MK
CaC03
October 1968
28 November 1968
3.5% Sulfur, 11.5 - 12.5% Ash,
12,500 BTU
(1) Dilute scrubber solution from
37M gallon settling pond
(2) Simplified on stream/off stream
capabili ty
110% stoichiometric
99% particulate removal
80% S02 removal
(1) Scrubber inlet deposit
[modification to reduce stagnant
boundary layer]
(2)Reheater plugging
[flow guides and soot blower installed
suggest moving demister as high as
possible in stack]
(3)Corrosion of scrubber tank and feed
lines
[coat or replace with corrosion-
resistant material]
(4)Reheater plugging
[soot blower installed]
(5)Poor S02 removal
[recycle scrubber underflow water
which contains reactive calcium
hydroxide]
(6)Limestone overburning with
resultant poor reactivity
[Raise limestone injector higher
in furnace]
(7)Ash buildup on flow lines under
scrubber falls off and blocks drain
[increase drain dimensions]
(8)Recycled scrubber water inpinged
on drain pots causing deposit buildup
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applied chemical engineering experience with the reactants and products
of the alkali injection-wet scrubbing process in their demonstration
and test design.
As a result, solutions to these problems are being
achieved by slow, costly, trial and error methods.
Since scrubber
reliability directly affects the total electrical generation reli-
ability of the utility plant with which it is integrated, such methods
produce a negative reaction toward the wet scrubbing process in
particular and S02 emission control in general. The risks which these
trial and error "demonstrations" illuminate, combined ",ith the full
'. .
capacity production requirements of most utilities, may effectively
stall efforts to introduce S02 emission control in the electric
utility industry.
It is suggested that the utilization of appropriate chemical
engineering expertise in the design of the wet-scrubbing installations
examined could have avoided, prior to installation, many of the opera-
tional problems experienced to date.
Finally, the lack of commonality in the design of stationary
power source boilers, flues, reheaters, and other components with
which the scrubber system must interface does not appear to have been
considered in the design and evaluation of the demonstration test
projects examined.
These interface variations can affect many factors
involved in successfully installing a scrubber system, including the
following:
PositiQn of alkali injection
Alkali/coal ratio
Concentration of scrubbing solution
Flow characteristics of the flue system
Corrosion sensitivity of scrubber hardware
Dimensions of scrubber flow lines
Position and operating characteristics of soot blowers
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':
i
f
Disciplines normally foreign to the electric utility industry
should be consulted to design both demonstration installations and
systematic test programs to quantify these installation factors over
the range of abatement process/stationary power source interface
combinations.
The ultimate success of the design, conduct, and
o
evaluation of these qualification test programs also rests on
removing them from the control of either the individual utility or
.-01
the developer advocating the specific 802 removal system. Until the
responsibility for demonstration testing is placed ,~ith an independent,
inter-disciplinary organization capable of objectively viewing the
entire system ~ithin which the 802 removal process must operate, each
operational 802 removal installation can be expected to be an expensive
and time-consuming individual "demonstration" project.
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REFERENCES
1.
J. F. McLaughlin and J. Jonakin, "Operating Experience with
Wet-Dolomite Scrubbing", 69-139, Presented at Air Pollution
Control Association Annual Meeting, New York, N. Y., June 22-26,
1969.
- .
2.
Daric M. Miller, "Experience with Wet Scrubber for S02 Removal
at the Lawrence Station of the Kansas Power and Light Company,"
Special Report Number 85, Presented to Society of Mining
Engineers of AIME, Salt Lake City, Utah, September 19, 1969,
Kansas Engineering Experiment Station, Kansas State University.
",'
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I,
DISTRIBUTION LIST
.:,
D-12
C. A. Zraket
n L. Kirby
1:\.. D-02
W. F. Mason
?
D-22
R. S. Greeley (5)
L. Hoffman (5)
W. D. Rowe (5)
K. E. Yeager (5)
Department File (25)
A-Ol
C. E. Duke
NAPCA
Bureau of Engineering and
Physical Sciences (25)
Washington Library
Bedford Library
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