U.S. Environmental Protection Agency Industrial Environmental Research EPA-600/7-78'0103
Office of Research and Development Laboratory *
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been, grouped into nine series. These nine broad cate-
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The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
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RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
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This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-78-010a
January 1978
EXECUTIVE SUMMARY FOR FULL-SCALE
DUAL-ALKALI DEMONSTRATION
AT LOUISVILLE GAS AND ELECTRIC CO.
Preliminary Design and Cost Estimate
bV
R.P. VanNess, R C. Somers, T. Frank, J.M. Lysaght,
I L. Jashnani, R.R. Lunt, and C.R. LaMantia
Louisville Gas and Electric Company
311 West Chestnut Street
Louisville, Kentucky 40201
Contract No. 68-02-2189
Program Element No, EHE624A
EPA Project Officer: Norman Kaplan
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, N.C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
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TABLE OF CONTENTS
Page No.
I. PURPOSE AND SCOPE 1
A. PURPOSE OF PROJECT 1
B. SCOPE OF WORK 1
II. DESCRIPTION OF THE CEA/ADL DUAL ALKALI PROCESS TECHNOLOGY ... 4
A. SYSTEM CHEMISTRY AND PROCESS CONFIGURATION 4
B. POLLUTION CONTROL CAPABILITIES 8
III. DUAL ALKALI SYSTEM APPLICATION TO CANE RUN UNIT NO. 6 10
A. SYSTEM DESIGN 10
B. OPERATING REQUIREMENTS 16
C. GUARANTEES 16
IV. CAPITAL AND OPERATING COSTS — DUAL ALKALI SYSTEMS 19
A. 300 MEGAWATT RETROFIT SYSTEM FOR LG&E CANE RUN UNIT NO. 6 19
B. GENERALIZED CAPITAL AND OPERATING COSTS 21
ill
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LIST OF FIGURES
Figure Page No.
1-1 Dual Alkali Demonstration Overall Project Schedule 3
II-l Dual Alkali Process Flow Diagram 5
LIST OF TABLES
Table Page No.
III-l Dual Alkali Process Design Basis 11
III-2 Process Operating Requirements at Design Conditions 17
IV-1 Summary of Capital and Operating Cost Estimates for the Dual
Alkali System at the LG&E Cane Run Unit No. 6 20
IV-2 Summary of Estimated Capital and Operating Costs (1976)
Dollars 22
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ACKNOWLEDGEMENTS
This report was prepared by Arthur D. Little, Inc.; however, the information
and data contained in the report represent the work of many individuals from
several organizations who have been involved in this project.
The principal participating organizations are Louisville Gas and Electric,
Inc.; Combustion Equipment Associates, Inc.; and Arthur D. Little, Inc.
The persons within each of these companies who were directly involved in
the preparation of this report and the work performed during Phase I are
listed below:
Louisville Gas & Electric
R. P. Van Ness
R. C. Somers
R. C. Weeks
Combustion Equipment Associates
T. M. Frank
J. M. Lysaght
Arthur D. Little
I. L. Jashnani (now with Martin Marietta
Corporation)
C. R. LaMantia
R. R. Lunt
In addition to the above, we would like to acknowledge the efforts and
contributions from persons in other organizations. Norman Kaplan, the
EPA Project Officer for this demonstration program, has made important
technical contributions and has been instrumental in the management of the
entire project. Mike Maxwell, the Director of Emissions/Effluent Technology
at EPA's Industrial Environmental Research Laboratory, was responsible for
overall planning and review for this program and has provided invaluable
guidance and support. And Randall Rush of the Southern Company Services
has made important contributions of a technical nature to the design of
the system.
vii
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APPLICABLE CONVERSION FACTORS
ENGLISH TO METRIC UNITS
British
5/9 (°F-32)
1 ft
1 ft2
1 ft3
1 grain
1 in.
1 in2
1 in3
1 Ib (avoir.)
1 ton (long)
1 ton (short)
1 gal.
1 Btu
Metric
°C
0.3048 meter
0.0929 meters2
0.0283 meters3
0.0648 gram
2.54 centimeters
6.452 centimeters2
16.39 centimeters3
0.4536 kilogram
1.0160 metric tons
0.9072 metric tons
3.7853 liters
252 calories
ix
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I. PURPOSE AND SCOPE
A. PURPOSE OF PROJECT
The project involves the full-scale application of a dual alkali flue gas
desulfurization (FGD) process to a coal-fired utility boiler. The dual
alkali system, developed jointly by Combustion Equipment Associates, Inc.
(CEA) and Arthur D. Little, Inc. (ADL) is being installed by the Louisville
Gas and Electric Company (LG&E) on Unit No. 6 at the Cane Run Station in
Louisville, Kentucky. Unit No. 6 is an existing 300 megawatt (gross peak
capacity), high sulfur, coal-fired boiler equipped with a high efficiency
electrostatic precipitator. The dual alkali system is being installed to
comply with requirements of the Jefferson County Air Pollution Control
District, the Division of Mr Pollution of the State of Kentucky, and
Region IV of the U.S. Environmental Protection Agency (EPA)—i.e., removal
of 85% of the S02 present in the flue gas entering the scrubber.
The system is being designed with the capability for controlling S02
emissions beyond this 85% removal requirement. When burning coal contain-
ing greater than 5% sulfur, the system will remove 95% of the S02 in the
inlet flue gas. When burning coal containing less than 5% sulfur, the
S02 emissions will be controlled to less than 200 ppm (dry basis). Since
the system will follow an electrostatic precipitator, it is not designed
for particulate removal. However, it is designed such that it will not
increase the particulate loading in the flue gas.
EPA has selected the Cane Run dual alkali system as a demonstration unit
for dual alkali technology and will participate on a cost-shared basis
with LG&E for design, operation, testing, and reporting of the demonstra-
tion project. As a demonstration system, the purpose of the installation
and operation is to establish:
• Overall performance—S02 removal, lime utilization, sodium
makeup, regeneration of spent liquor, water balance, scale
potential, materials of construction, waste cake properties,
reliability, and availability; and
i
• Economics—capital investment and operating cost.
B. SCOPE OF WORK
LG&E will have overall responsibility for the design, construction, and
operation of the system (including operation during the one-year test
program). CEA, as a subcontractor to LG&E, will provide the engineering
design for the dual alkali system and will supply all process equipment,
instrumentation and control systems, and all process buildings. CEA is
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also responsible for system startup and acceptance of the system as
defined by the process guarantees. ADL will provide assistance to CEA
in the process design and startup of the system and will assist LG&E in
the operation during the one-year test program. In addition, ADL is
also responsible for reporting progress during each phase of the demon-
stration program.
The work under the demonstration program is divided into four phases:
• Phase I - preliminary design and cost estimate;
• Phase II - engineering, design, construction, and mechanical
testing;
• Phase III - startup and performance testing; and
• Phase IV - one year of operation and testing.
The overall project schedule covering all phases of the dual alkali
demonstration project is shown in Figure 1-1. The overall project, in-
cluding the one-year test program, is scheduled for 40 months (with an
additional one month for completion of the final draft report). In order
to expedite the overall project, Phases I and II were scheduled to begin
simultaneously and run concurrently. Phase I (preliminary design) was
scheduled for five months, including preparation of the draft report.
Phase II (engineering, design, and construction) is scheduled for 24
months. A three-month period has been allowed for Phase III (startup and
acceptance testing). The one-year test program (Phase IV) is scheduled
to start in late 1978, approximately 27 months after the initiation of
the project.
This summary (EPA-600/7-78-010A) covers work performed under Phase I of
the project as reported in the Project Manual. The Project Manual (EPA-
600/7-78-010) contains information generated in preparation of the pre-
liminary design in sufficient detail to convey the total concept of the
proposed plant and to provide a complete basis for the cost estimates.
Included in the Project Manual are: a general description of the process
technology and its adaptation to Cane Run Unit No. 6; detailed material
and energy balances; overall utility requirements; plot plans and the
general arrangement of equipment; specification of major equipment; an
instrument list; piping and instrumentation diagrams; a discussion of off-
sites, and laboratory and shop capabilities; and the project schedule. A
detailed estimate of capital and operating costs for the demonstration plant
has also been prepared based on the process design. These costs are broken
down into the components used in preparing the estimate.
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1976
1977
1978
1979
1980
ONDJFMAMJJASONDJFMAMJJASONDJFMAMJJASONDJFMAMJ
16 20 24 28 32 36 40 44
8
12
• Preliminary Engineering
• Cost Estimation
• Phase 1 Report
Phmll
• Detailed Engineering
• Material and Equipment
Specification
• Purchasing
• Field Construction
• Operator Training
• Phase 1 1 Report
PhMClll
• Process Startup
• Acceptance Testing
• Phase III Report
PtWMlV
• Review/Input Test Plan
• Test Program
• Phase IV Report
• Final Report
••
•
••
mi
mm
tm
mm
*
r
-
wm
-
mm
mm
\-
mm
mm
m*
mm
mm
m*
mm
mm
mm
mm
mm
mm
FIGURE 1-1. DUAL ALKALI DEMONSTRATION OVERALL PROJECT SCHEDULE
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II. DESCRIPTION OF THE CEA/ADL DUAL ALKALI PROCESS TECHNOLOGY
A. SYSTEM CHEMISTRY AND PROCESS CONFIGURATION
The CEA/ADL dual alkali S02 control process involves scrubbing of the flue
gas with a solution of alkaline sodium salts. Spent scrubbing solution is
regenerated using lime to produce a solid waste consisting principally of
a mixture of calcium-sulfur salts.
The system can be conveniently broken down into three processing sections:
gas scrubbing; absorbent regeneration; and waste solids dewatering. The
equipment utilization and operation of each process section depends on
specific requirements of the particular application. Figure II-l shows
a generalized flow schematic of a dual alkali process as applied to a
boiler equipped with a high efficiency electrostatic precipitator. The
following discussion provides a description of the basic system configura-
tion and process flow scheme.
1. Flue Gas Scrubbing
In the generalized system, shown in Figure II-l, flue gas from the elec-
trostatic precipitator (or induced draft fan for the boiler) is forced by
a booster fan through an absorber. In the absorber the gas passes upward
through a set of sprays to quench the gas, then through a set of sieve
trays for S02 removal, and finally through a demister to remove entrained
liquor. The clean flue gas leaving the tower is finally reheated before
being discharged to the stack.
Regenerated absorbent solution, containing a mixture of sodium salts
(sodium hydroxide, sodium sulfite, sodium sulfate, and some carbonate), is
mixed with scrubber recycle liquor and fed to the top tray of the absorber.
The solution flows countercurrent to the gas through the tray system and
is collected at the bottom of the absorber in the internal recycle tank.
The collected liquor supplies solution for both the quench sprays and
recycle to the trays.
The absorption of S02 and some oxygen from the flue gas produces a spent
sodium sulfite/bisulfite, sulfate liquor as shown in the following
reactions:
2NaOH + S02 -*• Na2S03 + H20
Na2C03 + S02 ->• Na2S03 + C02+
Na2S03 + S02 + H20 -»- 2NaHS03
1/2 02 •*
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Scrubbed Gas
NO. 2
Fuel Oil
Air
CaO
Silo
Watei
Slaker
jrry
rage
ank
r
1
R
S
^«,
Reactor
System
H2O
Hold
Tank
H20
JL£
Mix
Tank
Na2C03
Silo
Solids
FIGURE 11-1 DUAL ALKALI PROCESS FLOW DIAGRAM
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The S02 removal efficiency in the absorber is principally a f traction of
the inlet S02 concentration, the number of gas/liquid contacting stages,
and the pH at which the absorber is operated. For a given scrubber con-
figuration and inlet S02 level, SC>2 removal can be adjusted simply by
varying the scrubber operating pH. In most utility boiler applications,
better than 95% SC>2 removal can be easily achieved.
During absorption and to a lesser extent through the remainder of the
system, some sulfite is oxidized to sulfate, converting an active alkali
(Na2SC>3) into an "inactive" salt (Na2S04) — Na2SC>4 does not absorb SC>2.
The majority of the oxidation occurs in the scrubber system; and the
amount of oxidation experienced is generally a function of the scrubber
configuration, oxygen content of the flue gas, and the scrubber operating
temperature. At excess air levels normally encountered in utility power
plant operations, the level of oxidation is expected to be on the order
of 5 to 10% of the sulfur dioxide removed (for medium and high sulfur
coal applications).
2. Absorbent Regeneration
A bleed stream from the absorber recirculation loop is sent to the re-
generation reactor system where it is reacted with hydrated lime. The
CEA/ADL reactor system incorporates a novel design developed to produce
solids with good settling and filtration characteristics over a broad
range of operating conditions. The reactor system consists of two
reactor vessels in series: a short-residence time first stage (3-15
minutes) followed by a longer residence time second stage (20-40 minutes).
The process can be operated in conjunction with a lime slaker or can use
purchased hydrated lime (e.g., commercial hydrate or carbide sludge).
The lime neutralizes the bisulfite acidity in the scrubber bleed" and
further reacts with sodium sulfite and sodium sulfate to produce sodium
hydroxide. These reactions precipitate mixed calcium sulfite and sulfate
solids, resulting in a slurry containing up to 5 wt % insoluble solids,
as shown below:
2NaHS03 + Ca(OH)2 -*• Na2S03 + CaS03 • 1/2 H2(H + 3/2
Na2S03 + Ca(OH)2 + 1/2 H20 -»• 2NaOH + CaS03 • 1/2
Ca(OH)2 -»• 2NaOH
The CEA/ADL dual alkali process is designed to operate in a relatively
"concentrated" active alkali mode (roughly 0.5M active Na+ • — where active
sodium is defined as that sodium attributable to OH", 003, HCO^, S0|, and I
HS03 in solution). In this mode, sulfate removal cannot be effected by
precipitation of gypsum (CaSC>4 • 2H20) , since the high sulfite levels
prevent soluble calcium concentrations from reaching levels required to
exceed the gypsum solubility product. Thus, the system operates unsat-
urated with respect to calcium sulfate, thus minimizing scale potential.
However, calcium sulfate is coprecipitated with calcium sulfite in the
regeneration reactor, which allows the system to keep up with absorbent
oxidation.
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3. Solid/Liquid Separation and Solids Dewatering
Slurry from the regeneration reactor system is fed to a thickener where
the slurry is concentrated to 20-45% solids. Clarified liquor from the
thickener is collected in a hold tank from which it is returned to the
absorber. The thickened slurry is sent to a rotary drum vacuum filter,
where the solids are filtered to a cake containing 55-70% solids. The
filter cake is the only waste material generated by the process. There
are no other solid or liquor purges from the system.
The high solids content of the filter cake and the excellent handling
properties of the material are a direct result of the controlled conditions
for crystallization in the reactor system. The material is much like a
moist silty to sandy soil and is easy to manage in solids handling and
transport equipment. If further chemical treatment is required, these
excellent physical properties should prove to be an advantage.
On the filter the cake is washed using a series of water spray banks.
This wash removes a large fraction (approximately 90%) of the occluded
soluble salts from the cake and returns these salts along with the filtrate
to the system, thereby reducing sodium losses and minimizing sodium car-
bonate makeup.
The exact chemical composition of the solids will depend somewhat upon fly
ash loading (if any), the chemical composition of the flue gas and fly ash,
and the degree of oxidation of sulfite to sulfate encountered in the system.
The following general chemical composition (ash-free, dry cake basis) is
typical for a high sulfur coal application:
CaS03 • 1/2 H20 = 80-85 wt %
CaS04 • 1/2 H20 = 10-15 wt %
Na2S04 + Na2S03 + NaCl = 1-3 wt %
CaC03 + Inerts = 5-10 wt %
The mix of sodium salts in the cake is importantly dependent upon the
chloride content of the coal. Essentially all of the chloride in the
coal is released to the flue gas as HC1 gas, and it is efficiently re-
moved in the absorber. The chloride is purged from the system in the
filter cake (as NaCl) at the rate at which it is absorbed. Thus, the
higher the chloride content of the coal, the higher the fraction of sodium
salts as sodium chloride.
Makeup sodium carbonate solution is fed to the system to replace sodium
value lost in the filter cake. The sodium carbonate is not intended for
use as a softener, since soluble calcium concentrations in the regenerated
liquor runs less than 100 ppm. The quantity of sodium carbonate required,
therefore, is quite small, and the sodium carbonate costs represent a
negligible element in the overall cost of operating the system.
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B. POLLUTION CONTROL CAPABILITIES
1. S02 Control
A sodium-based dual alkali process, operating in the concentrated active
sodium mode, is capable of SC<2 removal efficiencies in excess of 95% over
almost any range of inlet S02 concentrations encountered in coal-fired
utility boiler applications. In most high sulfur coal applications,
removal efficiencies approaching 99% can be achieved on a continuous basis
in low-energy, tray-type absorbers. SC^ removal efficiencies can be easily
varied by adjusting the operating pH of the absorber with little or no
affect on the overall lime stoichiometry or the sodium makeup requirement.
The high S02 removal capability of this process, when used in conjunction
with a boiler equipped with adequate particulate control, allows the option
of removing virtually all of the SC<2 from the flue gas treated in the
scrubber. Thus, there is the option of bypassing hot, untreated gas to
provide part or all of the reheat while still meeting the overall plant
SC>2 emission regulations in the combined treated and untreated flue gas.
In such a system the scrubber size can be reduced, since not all flue gas
is treated. Also, reheat requirements are reduced or eliminated. In the
system for Cane Run Unit No. 6, bypass for reheat is not provided. All
of the flue gas will be treated with reheat provided by injection of hot
gas from the combustion of No. 2 fuel oil.
2. Particulate Control
While particulate removal capability is not incorporated in the Cane Run
system, it can be accommodated in the process by appropriate selection of
the type of scrubber system to be used. If particulate removal capability
is to be incorporated in the system, then a higher energy particulate
removal device, such as a venturi scrubber, would be required. This can
be used alone for both S02 and particulate control; or, if additional S02
removal is required (> 95%), a venturi can be used in combination with one
or more trays at a small incremental cost. Particulate removal down to
0.02 grains/scfd or lower can be accomplished using venturi scrubbers at
moderate pressure drops (about 15 inches WG).
Where particulate control is already provided ahead of the scrubber system,
the SC-2 scrubbing system will not result in any increase in particulate
emissions. Because a solution is used for SC>2 absorption rather than a
slurry, any entrainment of scrubbing solution in the gas can be efficiently
and reliably removed using standard mist eliminators without wash water
prior to exhausting the gas.
3. Chloride Control
Most of the chlorides in coal (>90%) is volatized and appears in the flue
gas as HCL. Any aqueous-based scrubbing system would be highly effective
in absorption of HC1 (as well as HF) from the flue gas. As a result,
chloride concentrations will build in the closed liquor loop to levels
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such that the rate at which chloride is discharged from the system in
the washed filter cake will equal the rate at which chloride enters the
system with the flue gas. The CAE/ADL dual alkali system has been
successfully operated for extended periods with steady-state levels of
chloride in the closed liquor loop as high as 11,000 ppm (consistent
with 0.05-0.10 wt % chloride in the coal).
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III. DUAL ALKALI SYSTEM APPLICATION TO CANE RUN UNIT NO. 6
A. SYSTEM DESIGN
1. Design Basis
Cane Run Unit No. 6 is a 280 megawatt, pulverized coal-fired boiler. It
is equipped with a high efficiency electrostatic precipitator capable of
99.4% particulate removal. The unit operates from a maximum load of 60
megawatts during peak hours to a minimum load of 60 megawatts during off-
peak hours (20% of gross peak capacity). The annual average load is equiva-
lent to approximately 180 megawatts (about 60% of the gross peak capacity).
The system is designed to operate over the full range of anticipated
boiler loads.
Coal for Unit No. 6 is received from a number of sources. The average
sulfur content of the coal on a dry basis is 4.8% and varies from 3.5%
to 6.3%. The average chloride content of the coal is 0.04% and varies
from 0.03% to 0.06%. The average 4.8% sulfur content and 11,000 Btu/lb
corresponds to an average S02 emission of about seven times that allowed
by the present Federal New Source Performance Standards (1.2 Ibs of S02/
MM Btu).
At present, Cane Run Unit No. 6 is operating in accordance with all appli-
cable federal, state, and local regulations covering air emissions, water
discharges, and operator safety and health. Construction permits have been
issued by the Jefferson County Air Pollution Control District for the con-
struction of an S02 removal system for Cane Run Unit No. 6. The permit
complies with the two enforcement orders issued by the EPA (November 5, 1975)
and the Jefferson County Air Pollution Control District (December 10, 1975).
The dual alkali system for Cane Run Unit No. 6 is designed for SO, re-
moval only. The design basis for the system is summarized in Table III-l.
Design conditions correspond to coal containing 5% sulfur and 0.04%
chloride, and having a heating value of 11,000 Btu/lb. The design gas
capacity of 3,372,000 Ibs flue gas/hour is equivalent to the boiler peak
load capacity of 300 megawatts. The dual alkali system will meet all
applicable federal, state, and local pollution control and safety regu-
lations. The maximum S02 concentration in the clean gas will be 200 ppm
(for coal containing up to 5% sulfur), well below.requirements of the
Federal New Source Performance Standards.
2. System Description
The system configuration and operation will differ slightly from the
generalized process discussed previously. The principal difference is
that the system will utilize locally available carbide lime, a calcium
hydroxide byproduct from acetylene production, rather than slaked
quicklime.
10
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TABLE III-l
DUAL ALKALI PROCESS DESIGN BASIS
Coal (Dry Basis);
Sulfur
Chloride
Heat Content
Inlet Gas;
Flow Rate (Volumetric)
(Weight)
Temperature
so2
°2
Particulate
Outlet Gas;
so2
Particulate
5.0% S
0.04% Cl
11,000 Btu/lb
1,065,000 acfm
3,372,000 Ib/hr
300°F
3471 ppm
5.7%
SO.10 lb/106 Btu
<200 ppm (^0.45 lb/106 Btu)
<0.10 lb/106 Btu
11
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The system design is modular in nature, with spare capacity provided both
as excess capacity within modules as well as spare modules and equipment
where appropriate. Redundant instrumentation has also been provided for
critical control operations.
a. Absorption System
The sulfur dioxide system will be Installed between the existing induced
draft fans and stack. Hot flue gas will be drawn from the existing duct-
ing at the discharge of the two induced draft fans downstream of the
electrostatic precipitator and fed to the dual alkali scrubber system
through two booster fans. There are two absorber modules, with one booster
fan for each module. A common duct connects the two inlet ducts to the
booster fans (not shown in Drawing No. 040044-1-1, Rev. G of the Project
Manual, EPA-600/7-78-010).
In each absorber the hot flue gas is cooled by sprays of absorber solution
directed at the underside of the bottom tray. These sprays keep the under-
side of the tray and the bottom of the absorber free of buildup of fly ash
solids. The cooled gas then passes through a set of two trays, where S02
is removed, then through a chevron-type mist eliminator. The saturated
gas from the demister is heated 50 F° (to 175°F) by hot flue gas from a
reheater fired with No. 2 oil, and the reheated gas is then returned to
the existing duct entering the chimney.
Each absorber is sized to handle 60% of the design gas flow rate, and the
system can be turned down to 20% of the design flow rate. At levels less
than 60% of the design capacity the system can be operated with one
absorber module (by using a common duct and shutting down one absorber
module) or with two absorber modules.
Dampers are provided in the existing ducting and the absorber inlet ducts
to allow bypassing of flue gas around the scrubber modules. These dampers
are interlocked to enable bringing scrubbers on- or off-line without inter-
ruption of the boiler operation. The common ducting and damper systems
allow each scrubber to be independently isolated for maintenance while
the other scrubber continues in operation.
Regenerated absorbent liquor is fed to the top tray along with recircu-
lated liquor from the absorber recycle tank for pH control. The feed
forward of regenerated liquor from the thickener hold tank to the scrubber
trays corresponds to an L/G of 4.0 gals./I,000 acf (saturated) at design
conditions. The total recirculation rate for each absorber (sprays plus
trays) corresponds to an L/G of 5.7 gals./I,000 acf.
b. Regeneration System
There are two identical reactor trains in the system. Each train consists
of a primary reactor, a secondary reactor, and a reactor pump. The. spent
liquors from the absorbers are fed to the primary reactors of each two-
stage reactor system along with slurried carbide lime from the carbide
12
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lime storage tank for the dual alkali system (day tank). Each primary
reactor overflows by gravity into a secondary reactor, where the reaction
between lime and sodium salts is completed. The reactor slurry is then
pumped to the solid/liquid separation section.
Normally, the number of reactor trains in use is the same as the number
of operating scrubber modules, with each reactor train regenerating the
spent liquor from the corresponding scrubber module. However, piping is
provided such that each module can be operated on liquor from the corre-
sponding scrubber or liquor from both the scrubbers. And the reactors
are sized so that for short periods a reactor train can handle the total
liquor from both the absorbers operating at design conditions. Thus,
maintenance can be provided to one reactor train while the system is
operated with the other.
The carbide lime slurry used for regeneration of the spent absorber solu-
tion is received at the plant as a 30% solids slurry and stored in a large
tank for use in the three FGD systems. (Lime slurry scrubbing processes
have been installed on Unit 4, a 180-megawatt boiler, and on Unit 5, a
170-megawatt boiler.) From this main storage the slurry is pumped to
a day tank for each system. Slurry from the dual alkali system day tank
is pumped to the primary reactors as required.
c. Solids/Liquid Separation
The reactor effluent streams are fed to a thickener. Clarified liquor
overflows to the thickener hold tank from which the regenerated solution
is pumped to the absorbers as required. As discussed before, the feed
rate to the absorbers is determined by the pH of the absorber liquor.
The total volume in the system is maintained by controlling the liquid
level in the thickener hold tank using process makeup water.
The thickener underflow slurry controlled at about 25% solids is pumped
to the filter system where solids separation is completed. The filter
cake is washed to recover the sodium salts in the liquor. Combined
filtrate and wash water is returned to the thickener.
There are three filters. Each filter is rated to handle 50% of the total
solids produced at the design conditions, and each can be operated in-
dependently. The number of filters in operation is determined by the
quantity of solids accumulated in the thickener, which is reflected in
the solids concentration in the underflow slurry.
Soda ash is added to the system to make up for the sodium salts lost in
the washed waste filter cake. Dry, dense soda ash is received at the plant
and stored in the soda ash silo from which it is continuously weighed and
fed to the soda ash solution tank. The soda ash solution is prepared
using thickener hold tank liquor.
13
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d. Provisions for Spills and Leaks
Filter cake is the only product of the dual alkali process. The system
is operated in a closed loop, and there is no other liquid or solid purge
from the system. In practice, though, some liquor can be lost through
pump seals and during flushing of pipes and pumps after individual pumps
are shut down or after the system is shut down. The concentration of the
liquor is generally low compared to the concentration in the process
liquor because of dilution with seal or flush water. However, to prevent
water pollution and to reduce sodium loss from the system, this solution
is collected in sump tanks and is returned to the thickener.
e. Waste Disposal
A long-range plan for the disposal of the dual alkali filter cake is now
being developed as a part of an overall disposal plan for all FGD sludges
produced at the Cane Run Station. The plan, in its preliminary form, has
been submitted to the Jefferson County Air Pollution Control Board.
As currently perceived, the disposal operation will involve mixing dual
alkali filter cake with thickener underflow from the direct lime scrubbing
systems on Cane Run Unit Nos. 4 and 5, producing a material of approxi-
mately 40% solids. The combined wastes will then be transported to an
onsite disposal pond. Prior to being placed in the pond, the combined
sludge will be admixed with dry fly ash collected from the electrostatic
precipitators and separately conveyed to the disposal area. Additives,
such as lime, may also be used to promote hardening of the material.
Studies are now underway at the University of Louisville to develop ade-
quate physical properties data to allow for the design of appropriate
handling, mixing, and transport facilities. It is hoped that the dual
alkali filter cake and direct lime thickener underflows can be handled
as a thick slurry capable of being piped to the disposal area.
Since this combined disposal system is still in planning, the necessary
handling and transport equipment will not be operational at the time the
dual alkali system starts up. Thus, in the interim between the startup of
the dual alkali system and installation of the equipment for the combined
waste disposal operation, the filter cake will be conveyed to a feed hopper
where it will be loaded into trucks for transport to the disposal pond.
f. Offsites
The offsites generally required for the' dual alkali system include:
services for electrical supply, water supply, and instrument air; oil,
steam, or hot water if the wet flue gas is to be reheated; raw materials
receiving and storage facilities; a wet chemicals analytical laboratory;
and appropriate shop facilities for repair and maintenance of machinery
and instruments. Except for electrical service, all of these offsites,
including lime receiving and storage facilities, now exist at Cane Run
Station and are available. An electrical substation including appropriate
step-down transformers will be installed for the dual.alkali system.
14
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3. Materials of Construction
The system is designed with appropriate corrosion resistance where re-
quired using stainless steel (316 or 317) or linings (polyester or rubber).
The expected chloride levels in the process liquor range from 10,000 ppm
to 15,000 ppm, but levels can vary from as low as a few thousand ppm to
almost 20,000 ppm depending upon the chloride content of the coal and the
degree of cake washing. Liquor pH's range from about 5.0 in the absorber
loop to greater than 12.0 in the reactor and dewatering systems.
With the exception of the primary reactors, all tanks and vessel linings
in contact with process liquor are lined with flake-reinforced polyester.
The primary reactor is constructed of 316L stainless steel; the filtration
equipment is both 316L stainless steel and fiberglass; and the absorber
trays are 317L stainless steel.
All pumps and agitators in contact with process liquor are rubber-lined.
Process liquor piping is FRP. Hot flue gas ducting is carbon steel, and
the booster fan housing and blades are A441 steel. Saturated flue gas
ducting is polyester-lined between the absorbers and reheater section and
is 317L stainless steel between the reheater and stack.
4. Instrumentation
The system is designed for minimal operator interface consistent with safe
and reliable operation. Feed rates for all raw materials and the flows
of all principal process streams are automatically controlled according
to process operating conditions (tank liquid levels, process flows, and
stream compositions). Non-critical internal process flows are preset and
adjusted intermittently as dictated by process requirements.
All remote controls are located in a centralized control room from which
the system can be started up, operated, and shut down. The control room
is furnished with appropriate controllers, indicators, recorders, alarms,
and other necessary instrumentation for the safe and convenient operation
of the system.
Redundancy has been provided in critical control elements to ensure smooth
operation and minimize downtime. Instrumentation in addition to that
required to operate the process has also been provided to permit accurate
calculation of process material and energy balances. In particular,
instruments are included for continuous monitoring of inlet and outlet
S02 concentrations, the measurement of all chemicals and water entering
the system, and the weighing of all filter cake leaving the system.
15
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B. OPERATING REQUIREMENTS
System operating requirements at design conditions are summarized in
Table III-2. The power required to operate the process (exclusive of
reheat) will be approximately 1.0% of the peak power generation for Unit
No. 6. Of this, approximately 60% is required for the booster fans, 10%
for reheater fans, and 30% for the remainder of the system. Including oil
for reheat, the total energy requirement for the system amounts to about
2.7% of the peak power generation.
The lime and soda ash makeup requirements correspond to feed stoichiometries
of 1.00 mols Ca(OH)2 per mol of 862 removed and 0.022 mols Na2COo per mol
of S02 removed. These feed requirements include the alkali needed for
chloride removal. The total wet cake produced is equivalent to 30 Ibs of
moist filter cake per 100 Ibs of coal (5% sulfur) fired.
C. GUARANTEES
I. Sulfur Dioxide Emission
The system shall provide such control that emissions from the stack shall
be no greater than 200 ppm S02 dry basis without additional air dilution
when burning coal containing less than 5% sulfur. When burning coal con-
taining 5% sulfur or greater, the system shall be designed to remove at
least 95% of the sulfur dioxide in the inlet flue gas.
2. Participate Matter Emission
In addition to meeting applicable regulations, the system shall also be
designed to meet Federal New Source Performance Standards for emissions of
particulate matter under all conditions of boiler operation. The dual
alkali system will not add any particulate matter to the emissions of par-
ticulate matter that is received by the system from the LG&E Cane Run Unit
No. 6 electrostatic precipitator.
3. Lime Consumption
The consumption of lime in the system will not exceed 1.05 mols CaO per
mol of S02 removed from the flue gas.
4. Sodium Carbonate Makeup
Soda ash makeup will not exceed 0.045 mols of Na2CO. per mol of SO^
removed from the flue gas, provided that the chloride content of the
coal burned averages 0.06% or less. If the average chloride content of
the coal is above 0.06%, then additional sodium carbonate consumption
will be allowed at the rate of 1/2 mol ^2^3 for each mol of chloride in
the flue gas resulting from chloride in excess of 0.06% in the coal. The
seller as part of the guarantee shall perform the necessary research and
design to reduce the makeup requirements of Na2CO~ from the guarantee point
to a level of approaching minimal makeup.
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TABLE III-2
PROCESS OPERATING REQUIREMENTS AT DESIGN CONDITIONS
Basis:
Energy Requirements
Power
Fuel Oil (for reheat)
Total
Makeup Materials
Water
Lime (as Ca(OH>2)
Soda Ash
Coal - 5.0% sulfur
- 0.04% chloride
- 11,000 Btu/lb
S02 Removal - 94.4%
Full Load (300 megawatts)
Consumption Rate
3.1 megawatts
48 x 106 Btu/hr
Consumption Rate
325 gpm
460 Ibs/min.
13.7 Ibs/min.
Equivalent % of
Boiler Capacity
1.03
1.68
2.7
Lbs/lb Coal Fired
0.111
0.003
Cake Production
Dry Basis
Wet Basis
804 Ibs/min.
1,246 Ibs/min.
0.194
0.300
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5. Power Consumption
At the peak operating rate (300 megawatts) the system will consume a
maximum of 1.1% of the power generated by the unit.
6. Waste Solids Properties
The waste produced by the vacuum filter will contain a minimum of 55%
insoluble solids.
7. S02 System Availability
The system will have an availability (as defined by the Edison Electric
Institute for power plant equipment) of at least 90% for one year. Thus,
the system will be available for operation at least 90% of the calendar
time.
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IV. CAPITAL AND OPERATING COSTS — DUAL ALKALI SYSTEMS
Estimates of the capital and operating costs for the demonstration dual
alkali system to be installed on Unit No. 6 at LG&E's Cane Run Station have
been prepared based upon the preliminary engineering in Phase I. Using
these estimates, generalized costs have also been developed for application
of dual alkali systems to new 500 and 1,000 megawatt boilers.
A. 300 MEGAWATT RETROFIT SYSTEM FOR LG&E CANE RUN UNIT NO. 6
The capital investment and operating cost estimates for the dual alkali
demonstration system are summarized in Table IV-1. Capital costs are broken
down into total materials, erection, engineering, spare parts, and working
capital. The costs are as incurred and therefore are roughly equivalent to
September 1977 dollars. The estimated capital investment for the system is
$17,379,000, which corresponds to about $58.0/kilowatt (based on gross peak
capacity).
This capital investment represents the total installed cost for the system
exclusive of land and interest during construction. Since this is a retro-
fit system installed alongside two existing direct lime scrubbing systems,
some cost savings are realized in common offsite facilities. These include
the additional capacity requirements for service water and plant air,
storage for reheater oil, and the switch gear building—none of which are
included in the total capital. Also, the capital costs for the lime handling,
transport, and storage facilities for all three systems have been included
as a part of the delivered cost of lime in the operating costs.
Estimated annual operating costs for the demonstration system are shown in
Table IV-1, both in 1979 dollars (the first full year of operation) and in
corresponding 1976 dollars. Costs in 1976 dollars are shown since these
represent more well-defined costs using recent unit cost data and should
be directly comparable with published cost data for FGD systems. These
estimates have been prepared on present and projected (1979) costs for
labor, utilities, and raw materials, and incorporate LG&E's cost structure
applicable to the plant for overhead rates, interest, and depreciation.
Operating costs are based on an average sulfur content in the coal of 3.8%,
with an average boiler load of 60% and an average sulfur dioxide removal
efficiency of 94.2%. The operating costs are estimated both with and
without operation of the reheat system. (When included, reheat is assumed
to be 50 F°.) The sludge disposal costs are based on onsite solids dis-
posal after mixing with ash and lime.
The total annual operating cost without reheat is estimated to be $3.6
million in 1976 and $4.3 million in 1979. The corresponding costs with
reheat are about 15% higher. The 1976 operating costs range from 2.3 mills
per kwh (23.0
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TABLE IV-1
SUMMARY OF CAPITAL AND OPERATING COST ESTIMATES
FOR THE DUAL ALKALI SYSTEM AT THE LG&E CANE RUN UNIT NO. 6
Basis: 300 megawatt (gross peak load)
60% annual load
9,960 Btu/kwh
3.8% S in coal
94.2% S02 removal
CAPITAL COST ESTIMATES
Total Materials
Erection
Total Engineering
Spare Parts
Total Fixed Plant
Working Capital
Total Capital
Capital Cost Equivalents
$/kw - Based on 300 Mw Gross Peak Load
$/kw - Based on 277 Mw Net Peak Load
OPERATING COST ESTIMATES
1979 Dollars
With Reheat No Reheat
Annual Operating Costs
Direct Costs
Indirect Costs
Total
Operating Cost Equivalents
Mills/kwh
0/106 Btu
$/ton S Removed
(50F°)
$3,019,100
2.082.300
5,101,400
3.24
32.5
218
$2,243,900
2.082.300
4,326,200
2.74
27.6
185
$ 11,162,000
3,307,000
2,478,000
232.000
17,179,000
200.000
17,379,000
$ 57.9
$ 62.7
1976 Dollars
With Reheat No Reheat
(50F°)
$2,344,200 $1,767,300
1.841.200 1.841.200
4,185,400 3,608,500
2.65 2.29
26.7 23.0
179 154
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B. GENERALIZED CAPITAL AND OPERATING COSTS
Generalized costs have been prepared for application of concentrated mode,
lime-based dual alkali systems for S02 control on new 500 and 1,000 megawatt
boilers. Three cases have been considered: (1) a new 500 megawatt boiler
with SC>2 removal necessary to meet current Federal New Source Performance
Standards (NSPS) - 78.1% S02 removal; (2) a new 500 megawatt boiler with
90% S02 removal; and (3) a new 1,000 megawatt boiler with S02 removal to
meet Federal NSPS - 78.1% S02 removal.
Costs have been developed from the estimates for the LG&E system with
appropriate adjustments to the system design and cost factors that are
specific to the Cane Run Plant. In order to provide a common basis for
comparison of system costs, some of the assumptions used by McGlamery (1975)
in prior studies of the economics of S02 scrubbing have been incorporated
in the capital and operating cost estimates. The basis for the costs is
coal containing 3.5% sulfur and 0.1% chloride and having a heating value of
12,000 Btu/lb.
There are four basic differences between the cost basis for the generalized
plants and the LG&E system:
(1) The generalized plants utilize slaked quicklime rather than
carbide lime and therefore require slaking equipment and dry
lime handling/storage facilities.
(2) The boilers and FGD systems have common fans.
(3) The generalized systems are equipped with flue gas bypass for
reheat of the scrubbed gas. While overall S02 removal effi-
ciencies of 78% or 90% are achieved, removal efficiencies for
the flue gas passing through the absorber may be 98% or higher.
In cases where the overall SC>2 removal is 78.1% (to comply with
NSPS), the amount of flue gas bypassed is 20% and the amount of
reheat provided is 35 °F. In the case where overall S(>2 removal
is 90%, the amount of flue gas bypassed is 8% and the reheat
provided is 14°F. Although reheat is provided with bypassed
gas, absorbers are designed to handle 100% of the boiler flue
gas.
(4) For the generalized systems, the cost of land for process equip-
ment and sludge disposal has been included in the capital costs
(at $3,000 per acre).
The capital and operating cost estimates for the three general cases are
shown in Table IV-2 along with the comparable costs for the LG&E system.
Costs are given in 1976 dollars (for a plant located in the Midwest) in
order to provide a basis for comparison with published data on FGD systems.
McGlamery, G.G., et al., "Detailed Cost Estimates for Advanced Effluent
Desulfurization Processes," EPA-600/2-75-006, January 1975.
21
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TABLE IV-2
SUMMARY OF ESTIMATED CAPITAL AND OPERATING COSTS (1976 DOLLARS)
Boiler Location
Boiler Size (megawatts)
New or Existing
Basis;
Operating Hours
S in Coal, %
S02 Removal Efficiency
Sludge Disposal
me K.UH unit
No. 6
300
Existing
5,256
5
94.2
500
New
7,000
3.5
78.1
(NSPS)
- Lieneranzea
500
New
7,000
3.5
90
1,000
New
7,000
3.5
78.1
(NSPS)
Onsite after
treatment
Onsite
Onsite
a.
Onsite
Reheat, °F
Capital Investment, $/kw
Annual Cost,
-------
The major equipment costs for the generalized cases were, for the most
part, obtained by adjusting the costs for the LG&E system using standard
cost factoring techniques. Due to the modular nature of the system, the
sizes of the various pieces of equipment do not differ appreciably from
those in the LG&E system, so the use of cost factors results in minimal
error. Direct erection labor costs were assumed to be 50% of the direct
materials costs, and project indirect costs (engineering, field expenses,
fees and contingency) were assumed to be proportional to total direct
costs (35% for the 500 megawatt cases and 33% for the 1,000 megawatt
system). Higher relative costs for erection labor were used for the
generalized systems that were used in estimates for LG&E because of
the low cost of construction labor at the Cane Run Plant.
The total capital costs for the generalized 500 megawatt systems are
equivalent to about $50/kilowatt (78% S02 removal) and $53/kilowatt (90%
S0£ removal). These are about the same as for the Cane Run demonstration
system because the savings resulting from economies of scale, absence of
reheater, and the lower sulfur content of the coal are roughly offset by
the higher costs for erection labor, the need for lime storage and slaking
facilities, and the inclusion of the land costs.
The capital cost for the 1,000 megawatt system is estimated at about $44
per kilowatt. This roughly corresponds to a 13% cost savings over the
equivalent 500 megawatt system, due to economies of scale.
The operating costs for the generalized systems range from about 30
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing}
1. REPORT NO.
EPA-600/7-78-010a
2.
3. RECIPIENT'S ACCESSION-NO.
4. T.TLE AND SUBTITLE Executive Summary for Full-scale
Dual-alkali Demonstration at Louisville Gas and Elec-
tric Co. —Preliminary Design and Cost Estimate
5. REPORT DATE
January 1978
6. PERFORMING ORGANIZATION CODE
R. p. VanNess, R. C. Somers, *T. Frank,*J. M,
Lysaght, **I.L. Jashnani,**R.R. Lunt, and **C.R.
LaMantia
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Louisville Gas and Electric Company
311 West Chestnut Street
Louisville, Kentucky 40201
10. PROGRAM ELEMENT NO.
EHE624A
11. CONTRACT/GRANT NO.
68-02-2189
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Exec Summary; 10/76-12/77
14. SPONSORING AGENCY CODE
EPA/600/13
15.SUPPLEMENTARY NOTESIERL_RTP project officer is Norman Kaplan, MD-61, 919/541-
2556. (*)Combustion Equipment Associates. (**)A. D. Little, Inc. The basic report
is EPA-600/7-78-010.
16. ABSTRACT The repOrt. jg tne executive summary for the preliminary design of the
dual-alkali system, designed by Combustion Equipment Associates, Inc./Arthur D.
Little, Inc. and being installed to control SO2 emissions from Louisville Gas and
Electric Company's Cane Run Unit No. 6 boiler. The project consists of four phases;
I—preliminary design and cost estimates; n—engineering design, construction, and
mechanical testing; HI—startup and performance testing; and IV--1 year operation
and testing. Developed as part of Phase I, the executive summary presents salient
facts and conclusions from the Phase I report for use by upper management and the
general public.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Scrubbers
Alkalies
Sulfur Dioxide
Coal
Boilers
Chemistry
Operating Costs
Capitalized Costs
Air Pollution Control
Stationary Sources
Dual-alkali System
13B
07A
07D
07B
21D
13A
14A
9. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport}
Unclassified
21. NO. OF PAGES
33
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
24
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