C P A U.S. Environmental Protection Agency Industrial Environmental Research
™ • •• Office of Research and Development Laboratory
Research Triangle Park, North Carolina 27711
EPA-600/7-78-010
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JSRUar '
PROJECT MANUAL FOR
FULL-SCALE DUAL-ALKALI
DEMONSTRATION AT LOUISVILLE
GAS AND ELECTRIC CO. -
Preliminary Design and Cost Estimate
Interagency
Energy-Environment
Research and Development
Program Report
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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-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
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)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
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
systems; and integrated assessments of a wide'range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-78-010
January 1978
PROJECT MANUAL FOR FULL-SCALE
DUAL ALKALI DEMONSTRATION
AT LOUISVILLE GAS AND ELECTRIC CO. -
Preliminary Design and Cost Estimate
by
R.P. VanNess, R.C. Somers, T. Frank, J.M. Lysaght,
II. 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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ABSTRACT
The dual alkali process developed by Combustion Equipment Associates, Inc.
(CEA) and Arthur D. Little, Inc. (ADL) is being installed to control S02
emissions from Louisville Gas and Electric Company's (LG&E) Cane Run
Unit No. 6. The Federal Environmental Protection Agency (EPA) has
selected this system as the demonstration plant for dual alkali technology
and is participating in funding of the operation, testing, and reporting
of the project. The project covers the full-scale application of the
system to Unit No, 6, a high sulfur, coal-fired boiler having a gross
peak capacity of 300 megawatts (Mw). The system is expected to start up
in late 1978.
The project consists of four phases: Phase I - preliminary design and
cost estimates; Phase II - engineering design, construction, and
mechanical testing; Phase III - startup and performance testing; and
Phase IV - one-year operation and testing.
This report is the Project Manual for the system developed as a part of
Phase I. The report includes detailed descriptions of the process
chemistry, design of the demonstration system at LG&E, material and
energy balances for the system preliminary specification of major equip-
ment items and offsites, and capital and operating costs. The costs for
this application have been generalized for new applications on 500 Mw
and 1,000 Mw high sulfur coal-fired boilers.
iii
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TABLE OF CONTENTS
Page No.
Abstract ill
List of Figures vii
List of Tables ix
Acknowledgements xiii
Applicable Conversion Factors
English to Metric Units xv
I. SUMMARY 1
A. Introduction 1
B. CEA/ADL Dual Alkali System 1
C. Application of the Dual Alkali System to Cane
Run Unit No. 6 1
D. Capital and Operating Costs 3
II. INTRODUCTION 5
A. Purpose of Project 5
B. Scope of Work 5
C. Project Schedule 7
III. CEA/ADL DUAL ALKALI PROCESS 9
A. Process Chemistry and System Description 9
B. Pollution Control Capabilities - CEA/ADL
Dual Alkali Process 15
C. Waste Properties 16
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TABLE OF CONTENTS (Continued)
Page No.
IV. DUAL ALKALI DEMONSTRATION SYSTEM AT LG&E 17
A. Boiler System Description 17
B. Design Basis for the Dual Alkali System 17
C. Guarantees 21
D. General Description of the Dual Alkali System 22
V. MATERIAL AND ENERGY BALANCES 32
A. Material Balances 32
B. Energy Consumption 43
VI. PROCESS EQUIPMENT AND INSTRUMENTATION 47
A. Equipment 47
B. Piping and Instrumentation 48
VII. OFFSITES AND AUXILIARIES 73
A. Electrical Power 73
B. Water Supply 73
C. Instrument Air 74
D. Oil 74
E. Carbide Lime Facility 75
F. Laboratory and Shop Cababilities 75
VIII. CAPITAL AND OPERATING COSTS—DUAL ALKALI SYSTEMS 77
A. 300 Mw Retrofit System for LG&E Cane Run No. 6 77
B. Generalized Capital and Operating Costs 86
vi
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LIST OF FIGURES
Figure No. Page No.
II-l Dual Alkali Demonstration Overall Project
Schedule 8
I1I-1 Dual Alkali Process Flow Diagram 10
III-2 (CaSO^/CaSOo) Ratio in Reactor Solids as a
Function of Reactor Liquor Composition 13
V-l Block Diagram of Water Balance at 100% Load 39
V-2 Water Balance at 100% Load (3.8% S Coal, 55%
Solids in Cake, 2.0 Wash Ratio) 40
V-3 Water Balance for 4.7% Sulfur Coal 41
V-4 Water Balance for 3.8% Sulfur Coal 42
V-5 Evaporation in a 120' Diameter Thickener 44
LIST OF DRAWINGS
Process Flow Diagram 040044-1-1, Rev. G 25
Material Balance for Drawing 040044-1-1, Rev. G 26
Process Flow Diagram 040044-1-2, Rev. F 27
Material Balance for Drawing 040044-1-2, Rev. F 28
vii
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LIST OF TABLES
Table No. Page No.
1-1 Summary of Estimated Capital and Operating
Costs (1976) Dollars 4
IV-1 Ultimate Coal Analysis (Dry Basis) 18
IV-2 Flue Gas Conditions at the Inlet of the
Dual Alkali System 19
IV-3 Design Basis 20,
IV-4 Carbide Lime Specifications 23
V-l Basis for Material and Energy Balances 33
V-2 Overall Material Balance for the Dual Alkali
System 34
V-3 Water Balance at Expected Operating Conditions
(All Flow Rates in gpm) 37
V-4 Electrical Energy Requirements for the Dual
Alkali System at the Louisville Gas &
Electric Company 46
VI-1 Equipment List 49
VI-2 Materials of Construction 52
VI-3 Agitators 55
VI-4 Dampers 56
VI-5 Ductwork 57
VI-6 Expansion Joints 58
VI-7 Booster Fans 59
VI-3 Reheaters 60
VI-9 Pumps 61
VI-10 Tanks 62
VI-11 Soda Ash Silo 63
ix
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LIST OF TABLES (Continued)
Table No. Page No.
VI-12 Thickener 64
VI-13 Vacuum Filter 65
VI-14 Absorber 66
VI-15 Preliminary List of Instruments for the Dual
Alkali S02 Control System 67
VI-16 Control of Stream Flow Rates to Maintain Liquid
Level in Various Tanks in the Dual Alkali Process 70
VIII-1 Design Basis for the Dual Alkali System at the
Cane Run 6 Louisville Gas and Electric Company 78
VIII-2 Estimated Capital Costs for Dual Alkali System
at the Cane Run 6 Louisville Gas and Electric
Company 79
VIII-3 Cost of Major Equipment Components for Dual
Alkali System at the Louisville Gas and
Electric Company 81
VIII-4 Additional Purchased Parts Cost for Dual Alkali
System at the Louisville Gas and Electric
Company 82
VIII-5 Estimated Average Annual Operating Costs for
Dual Alkali at the Louisville Gas and
Electric Company (1979 $) 84
VIII-6 Estimated Average Annual Operating Costs for
Dual Alkali System at the Louisville Gas
and Electri-c Company (1976 Dollars) 85
VIII-7 Design Basis for the Generalized Dual Alkali
System 88
VIII-8 Estimated Capital Investment for Generalized
Dual Alkali System 90
VIII-9 Size Cost Factors Used to Estimate Capital Costs 91
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LIST OF TABLES (Continued)
Table No. Page No.
VIII-10 Estimated. Annual Operating Costs for Dual
Alkali System - 500 Mw Boiler, S02 Removal
to meet NSPS (78.1% Removal Efficiency) 93
VIII-11 Estimated Annual Operating Costs for Dual
Alkali System - 500 Mw Boiler, 90% S02
Removal 94
VIII-12 Estimated Annual Operating Costs for Dual
Alkali System - 1,000 Mw Boiler, S02
Removal to meet NSPS (78.1% Removal
Efficiency 95
xi
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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. 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 pro-
vided 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.
xiii
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APPLICABLE CONVERSION FACTORS
ENGLISH TO METRIC UNITS
British
Metric
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
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
xv
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I. SUMMARY
A. INTRODUCTION
The dual alkali process developed by Combustion Equipment Associates,
Inc. (CEA) and Arthur D. Little, Inc. (ADL) is being installed to control
S02 emissions from Louisville Gas and Electric Company's (LG&E) Cane
Run Unit No. 6. The Federal Environmental Protection Agency (EPA) has
selected this system as the demonstration plant for dual alkali technology
and is participating in funding of the operation, testing, and reporting
of the project. The project consists of four phases: Phase I -
preliminary design and cost estimates; Phase II - engineering design,
construction and mechanical testing; Phase III - startup and performance
testing; Phase IV - one year operation and test program. The system is
scheduled to start up in October 1978 with the one year test program
beginning in early 1979. This Project Manual covers the work in Phase I.
A more detailed manual will be prepared at the end of Phase II, and it
will be updated at the conclusion of Phase IV.
B. CEA/ADL DUAL ALKALI SYSTEM
The dual alkali system involves absorption of S02 using an aqueous
solution of alkaline sodium salts. Regeneration of the spent absorbent
solution if accomplished using lime which produces a solid waste of
calcium-sulfur salts. The process operates in a concentrated active
sodium mode* and is capable of 502 removal efficiencies in excess of 95%
over any range of inlet SOo concentration encountered in coal-fired
utility boiler applications. In addition to S02 removal, the system is
highly effective in absorption of chlorides from the flue gas. Particu-
late removal can also be accommodated by appropriate selection of scrubbers.
The system is operated in a closed loop. The only waste material from
the system is a washed filter cake—there are no other liquid or solid
purge streams.
C. APPLICATION OF THE DUAL ALKALI SYSTEM TO CANE RUN UNIT NO. 6
The Cane Run Unit No. 6 is a high sulfur, coal-fired boiler having a
gross peak capacity of 300 megawatts. The sulfur content of the coal
burned in this unit ranges from 3.5% to 6.3% (dry basis); chloride levels
typically vary from 0.03% to 0.06% (dry basis). The system design is
based on 5.0% sulfur (dry basis) in the coal. Design flue gas conditions
downstream of the induced draft fan and at the inlet of the S02 control
system are as follows:
aSee Glossary for definition of dual alkali terminology.
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• Gas flow rate 1,065,000 acfm
• Temperature 300°F
• Pressure -1 to +2 inches W.G.
• SO 3471 ppm (dry basis)
• Particulate <.0.0537 gr/acf
The CEA/ADL dual alkali system has been designed to meet the following
guarantees:
• The emissions from the system shall be no greater than 200 ppm
S09 (dry basis) at coal sulfur contents of up to 5.0%; 95%
removal for coal containing over 5% sulfur.
• The system will cause no increase in particulate matter in
the flue gas.
• The consumption of lime will not exceed 1.05 moles CaO per
mole of S0« removed from the flue gas.
• Sodium makeup will not exceed 0.045 moles of Na^CO_ per mole
of SO removed from the flue gas.
• The system will consume less than 1.1% of the power generated
by the boiler at peak load.
• The filter cake will contain a minimum of 55% insoluble solids.
• The system will have an availability of at least 90% for a
one year period.
The principal features of the system at LG&E are:
• The system can be operated from 20% to 100% of the gross peak
capacity.
• The flue gas can be reheated by 50 F° at maximum gas flow rate.
• The system is modular in nature and includes two absorber
modules, two reactor trains (each train consisting of two
reactors in series), one thickener and three filters. The
system can be operated with one reactor train at 100% load
for short durations, and with one absorber module at up to
60% load.
aAvailability is defined as the ratio of the hours the system is avail-
able for operation and the total hours in the operating period
(expressed as percent).
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• Spare capacity in the system:
Pumps 100%
Filters 50%
Instruments for operation 100%
• The filter cake will be disposed of in an onsite pond after
treatment.
• Normally, the system will utilize locally available carbide
lime (a byproduct of acetylene production); commercial lime
will be used for some test periods.
D. CAPITAL AND OPERATING COSTS
The estimated capital investment and operating costs for the dual alkali
system on Cane Run Unit No. 6 and projected costs for generalized systems
(500 Mw and 1,000 Mw) are presented in Table 1-1 (in 1976 dollars). The
generalized systems are based on commercial lime as raw material, 3.5%
sulfur in coal, and an annual operating time of 7,000 hours/year. As
seen in Table 1-1, the capital investment varies from $43/kw to $53/kw,
and the operating cost varies from 30C/106 Btu to 36C/106 Btu heat input
(equivalent to 2.7 - 3.2 mills/kwh).
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TABLE 1-1
SUMMARY OF ESTIMATED CAPITAL AND OPERATING COSTS (1976) DOLLARS
Boiler, Mw
New or Existing
Operating Hours
S in Coal, %
S02 Removal Efficiency
Sludge Disposal
Reheat, °F
Capital Investment, $/kw
Annual Cost, 0/10^ Btu
Annual Cost, Mills/kwh
300
(Cane Run Unit
Existing
5,256
5
94.2
500 500
£\ f flA«'h«-t4*n1-fnn*4
New New
7,000 7,000
3.5 3.5
78.1 90
(NSPS)
1,000
\
/
New
7,000
3.5
78.1
(NSPS)
Onsite after Onsite
Treatment
Onsite
Onsite
Od-50
53. 2b
23.0a-26.7
2.29a-2.65
35
50.2
32.9
2.96
35
52.8
35.8
3.22
14
43.7
30.3
2.73
Reheating of the wet gas (from scrubbers) is not in operation
(savings in the reheat energy only).
The capital investment for Cane Run Unit No. 6 is equivalent to
$53.2/kw based upon gross peak load (300 Mw) and $57.5/kw based
upon gross net load (277 Mw).
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II. INTRODUCTION
A. PURPOSE OF PROJECT
The project covers the full scale application of the CEA/ADL dual alkali
flue gas desulfurization (FGD) system to Unit No. 6, a coal-fired boiler
at Louisville Gas and Electric Company's (LG&E) Cane Run Station in
Louisville, Kentucky.
The system will be installed on this existing 300 Mw (gross peak capacity)
unit to comply with requirements3 of the Jefferson County Air Pollution
Control District, the Kentucky State Division of Air Pollution, and
Region IV of the U.S. EPA. EPA has selected the dual alkali S0£ control
process at LG&E as a demonstration system for dual alkali technology and
will participate on a cost-shared basis with LG&E for design, operation,
testing, and reporting of the demonstration project.
The dual alkali system will be installed following the existing electro-
static precipitator and will have the capability to control the S02 emissions
to less than 200 ppm dry basis without additional air dilution when burning
coal containing up to 5% sulfur. When burning coal containing greater than
5% sulfur, the system will remove at least 95% of the sulfur dioxide in the
inlet flue gas. The dual alkali system is not designed for particulate re-
moval; however, it is designed not to increase the particulate loading in
the flue gas. 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, scaling and solids buildup
problems, materials of construction, waste cake properties, reliability
and availability.
• economics - capital investment and operating cost.
B. SCOPE OF WORK
LG&E will design, construct, and operate (for an operating period of one
year following startup) a CEA/ADL dual alkali flue gas desulfurization
system on Unit No. 6 at the Cane Run Station, an existing coal-fired boiler.
The system shall treat the total flue gas emitted by the nominal 280 MW
boiler. The system shall be capable of treating flue gas equivalent to a
minimum of 60 Mw and a maximum of 300 Mw of generating capacity. LG&E shall
be responsible for the execution of such subcontracts as are required to
accomplish the design, procurement, construction, startup, and operation of
the demonstration system.
Removal of 85% of the S02 present in the flue gas at the scrubber inlet,
-------
The CEA scope includes engineering of the dual alkali system and will
provide all the equipment including instruments, control panel, filter
building, etc. for the process to LG&E. CEA is responsible for startup
and acceptance of the system, and for process guarantees.
The ADL scope includes process engineering help to CEA both during the
design and startup of the system, assisting LG&E to conduct a one-year
test program, and ADL is responsible for writing reports for the EPA/LG&E
contract.
The system shall be designed such that emissions from the stack shall be
no greater than 200 ppm S02 dry basis without additional air dilution when
burning coal containing up to 5% sulfur. When burning coal containing
greater than 5% sulfur, the system shall be designed to remove at least
95% of the sulfur dioxide in the inlet flue gas.
The work 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.
This report covers work performed in Phase I of the project. In Phase I,
LG&E/CEA/ADL was to prepare a process design and a capital and operating
cost estimate for the demonstration system. The process design is for a
dual alkali system including system hardware, offsite requirements; and
ducting, piping, and other interfaces with the host boiler to render the
FGD process fully operational. The term "preliminary design" as used here
is intended to cover all work required to adapt the dual alkali flue gas
desulfurization process to the particular application and produce a pre-
liminary visualization of all features of the proposed plant in sufficient
detail to make a reasonable engineering estimate of the capital and operat-
ing costs.
Information generated in preparing the preliminary design was to be assem-
bled in the form of the Project Manual. The Project Manual was to contain
sufficient detail to convey the total concept of the proposed plant and to
provide a complete basis for the cost estimates. It includes: general
process description; material and energy balances; utility requirements;
plot plans; offsites; major items of equipment; general arrangement and
specification of major equipment; instrument list; piping and instrument
diagrams; laboratory and shop capabilities; and process schedule.
A detailed estimate of capital and operating costs for the demonstration
plant was to be prepared based on the process design. These costs are
broken down into the components used in preparing the estimate.
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C. PROJECT SCHEDULE
The overall project schedule covering all phases of the dual alkali
demonstration project is given in Figure II-l. 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).
Phases I and II were scheduled to begin simultaneously to expedite the
overall project. Phase I (preliminary design) was scheduled for five
months including preparation of the draft report. Phase II (engineering,
design, and construction) was scheduled for 24 months starting with the
signing of the contract.
A three-month period is allowed for Phase III startup and acceptance test-
ing. The one-year test program (Phase IV) will be planned during the
latter part of Phase III. Phase IV is scheduled to start in late 1978 and
end in early 1980.
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1976
1977
1978
1979
1980
00
-I \-
^
-»
-i
ONDJF MAM J JASONDJ F MAMJJASONDJF MAMJ JASONDJFMAM J
04 8 12 16 20 24 28 32 36 40 44
• IM«C •
• Preliminary Engineering
• Cost Estimation
• Phase 1 Report
Phmll
Q) Detailed Endineerino
• Material and Equipment
Specification
• Purchasing]
• Field Construction
• Operating Manual
• Operator Training
9 Maintenance Plan
• Mechanical Testing
• Phase 1 1 Report
PhMtllt
• Process Startup
• Acceptance Testing
• Phase III Report
Phase IV
• Review/Input Test Plan
• Test Program
• Phase 1 V Report
• Final Report
••
•
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•
•
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Ml
M3
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15
Figure II-l DUAL ALKALI DEMONSTRATION OVERALL PROJECT SCHEDULE
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III. CEA/ADL DUAL ALKALI PROCESS
This chapter provides technical information on the process chemistry,
process and generalized system design, pollution control capabilities,
and waste properties. The S02 control system at LG&E differs slightly
from the generalized system in this chapter, and is described in the next
chapter.
A. PROCESS CHEMISTRY AND SYSTEM DESCRIPTION
The CEA/ADL dual alkali process for S02 control from boiler flue gas in-
volves sodium solution scrubbing with regeneration of the absorbent solu-
tion using lime.
The system can be conveniently broken down into three process subsystems:
gas scrubbing, absorbent regeneration, and solids dewatering.
The equipment utilization and operation of each subsystem depends on
specific requirements of the particular application. The following is a
general description of the system components for a CEA/ADL dual alkali
system operating in the concentrated active sodium mode using lime for
regeneration. Figure III-l shows a generalized flow schematic of the
process.
1. Flue Gas Scrubbing
The S02 scrubbing system consists of an absorber equipped with a liquid
entrainment separator, an enclosed recycle tank to contain the scrubbing
liquor, and recycle pumps.
In a generalized system, gas from the electrostatic precipitator (or in-
duced draft fan for the boiler) is forced by a booster fan through the
absorber. Gas passes upward through the sprays, a set of trays, and then
through a demister. The clean flue gas leaving the tower is finally re-
heated before being discharged through the stack.
|
Regenerated absorbent solution, containing sodium hydroxide, sodium sulfite,
sodium sulfate and some sodium carbonate, is mixed with scrubber recycle
liquor and fed to the top tray of the absorber. The solution flows counter-
current to the gas through the tray system and is collected at the bottom of
the absorber in the internal recycle tank. This collected liquor supplies
solution both for spraying and the pH control across the trays.
A continuous bleed stream is drawn from the absorber recirculation loop and
is sent to the absorbent regeneration system. This bleed rate is controlled
on the liquor level in the tank.
The feed forward flow of process liquor to the scrubber system is set accord-
ing to the pH of the absorber bleed liquor. The flow is adjusted to maintain
this pH within a prescribed range dictated by the required S02 concentration
-------
Scrubbed Gas
Solids
FIGURE 111-1 DUAL ALKALI PROCESS FLOW DIAGRAM
-------
in the exit flue gas. For example, a pH of 6.0 may result in the S02 con-
centration (in the exit flue gas) of 200 ppro or lower depending on the
operating conditions.
The absorption of SQ2 produces a spent sodium sulfite/bisulfite liquor,
as shown in the following reactions:
2NaOH + SO-»• NaSC> + H0
Na2S03 + S02 + H20 •* 2NaHSO.
During absorption, and to a less extent through the remainder of the sys-
tem, some sulfite is oxidized to sulfate:
Na2S03 + 1/2 02 •* Na2S04,
converting an "active" form of sodium into an "inactive" form. (The
active sodium includes NaOH, Na2C03, Na2S03, and NaHS03.)
The majority of oxidation occurs in the scrubber system. The level of
oxidation experienced is generally a function of the scrubber configura-
tion, oxygen content of the flue gas, and the scrubber operating tempera-
ture. At excess air levels (equivalent to 5 to 6% oxygen in the flue gas-
dry basis) normally encountered in utility power plant operations burning
medium or high sulfur coal (coal containing 2.5% sulfur or higher), the
level of oxidation is expected to be on the order of 5 to 10% of the sulfur
dioxide removed.
2. Absorbent Regeneration
Spent scrubber solution from the absorber recirculation line is bled to
this regeneration reactor system where it is reacted with hydrated lime.
The reactor system incorporates a novel design developed to produce solids
with good settling and filtration characteristics over a broad range of
concentrations of sulfite and sulfate in the feed liquor. The reactor
train consists of two reactor stages: a short residence time first stage
(3-15 minutes) followed by a longer residence time second stage (20-40
minutes). The normal mode of operation is to feed hydrated lime slurry
to the first stage reactor only. The process can be operated in conjunc-
tion with a lime slaker or can use carbide sludge.
The rate of the lime feed is controlled by the pH of the secondary reactor
liquor. 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. No
recycle of solids is necessary to produce waste material with good properties.
The overall reactions are shown below.
11
-------
2NaHS03 + Ca(OH)2 -* Na2S03 + CaS03 • 1/2 E^ + 3/2 H2
-------
0.25
Condition:
Active Sodium = 0.2-2.3M
Sulf ate = 0.05-1.7M
0.20 _
2 0.15 —
CC.
c
8
3
0.10
o
E
0.05
0.0365
/
V
[S04
[80
Legend:
• Pilot Plant Data
O Laboratory Data
10
mols Na2S04/mol Na2S03 in Reactor Bleed Liquor
FIGURE 111-2 (CaSO4/CaSO3) RATIO IN REACTOR SOLIDS AS A
FUNCTION OF REACTOR LIQUOR COMPOSITION
13
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then vary with changes in oxidation, the sulfate/sulfite ratio adjusting
to whatever level is required to keep up with sulfate formation in the
system.
3. Solid/Liquid Separation and Solids Dewatering
Slurry from the regeneration reactor system is fed to the center well of
the thickener. The thickened slurry from the bottom of the settler is
sent to a rotary drum vacuum filter. The slurry is recirculated past the
filter in a recycle loop that returns the slurry to the solids zone in
the settler. The feed to the filter is drawn as the bleed from this re-
circulation loop. The filter is equipped with an overflow pipe returning
to the solids zone in the thickener to provide protection against inadvertent
overflow of the filter hold tank as well as to allow for operation in an
overflow mode.
The solid cake is washed on the filter 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 to the system, thereby
reducing sodium losses and minimizing sodium carbonate makeup. The total
wash rate will usually be set to be a constant percentage of the cake dis-
charge rate. The mixed filtrate and wash liquor from the filter are returned
to the thickener.
Makeup sodium carbonate solution is fed to the thickener center well at a
rate based upon the lime feed rate to the regeneration reactor system. The
sodium makeup rate is tied to the lime feed, as the amount of sodium loss
from the system will be a constant percentage of the solids discharged
from the filter (for a given wash rate and cake properties). Over a rea-
sonable period of time the solids discharge rate will in turn be in direct
proportion to the lime feed.
The sodium carbonate can be fed to the thickener in order to allow easy
removal of any CaC03 precipitated or the sodium carbonate can be fed directly
to the scrubber system with no CaC03 precipitation. The sodium carbonate
in the thickener will react with calcium sulfite producing sodium sulfite
and calcium carbonate. The calcium carbonate will precipitate in the
thickener. This represents a loss of calcium because it is associated with
carbonate and not with sulfite or sulfate. On the other hand, the sodium
carbonate in the abosrber will react with the sodium bisulfite producing
sodium sulfite and carbon dioxide. The .carbon dioxide is librated in the
absorber. Thus, calcium carbonate is not generated and there is no loss
of calcium.
The sodium carbonate is not intended for use as a softener, since soluble
calcium concentrations in the regenerated liquor will run less than
100 ppm.
Clear liquor overflow from the thickener is collected in the thickener
hold tank which acts as a small surge capacity for the absorbent liquor
feed to the scrubber system. Water is also added to this hold tank to
14
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makeup for the difference between total system water losses (evaporation
and cake moisture) and total water inputs from other sources (sodium make-
up solution, pump seals, lime feed, and cake wash).
B. POLLUTION CONTROL CAPABILITIES - CEA/ADL DUAL ALKALI PROCESS
!_. S02 Control
The sodium-based dual alkali process, operating in the concentrated active
sodium mode, is capable of S02 removal efficiencies in excess of 95% over
any range of inlet SC>2 concentrations encountered in coal-fired utility
boiler applications. In most cases, removal efficiencies approaching 99%
can be achieved on a continuous basis. This is accomplished by proper
selection and design of the absorber unit and by adjustment of the active
sodium/S02 stoichiometry in the absorber. Such variation in SC»2 absorption
efficiency can be affected without influencing the overall lime stoichiometry
or the sodium makeup requirement. These high S02 removal efficiencies can be
achieved in tray-type absorbers at low L/G ratios, typically in the range of
5-10 gpm/1,000 acfm of saturated gas. The pressure drop across the trays
may be minimal, in the range of 4-6 inch WG.
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 and bypassing hot, untreated gas to provide part or all of the
reheat while still meeting the overall plant S02 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, and the reheat
requirements are reduced or eliminated.
2. Particulate Control
Particulate removal can be accommodated in the process by appropriate
selection of scrubbers to be used for both the particulate removal and the
SC>2 absorption duty. If particulate removal is to be accomplished as part
of the overall system than a higher energy particulate removal device, such
as a venturi scrubber, may be incorporated in this system to provide for both
SC»2 and particulate removal. Particulate removal down to 0.02 grains/scfd
or lower can be accomplished using venturi scrubbers at moderate pressure
drop of about 15 inch WG.
3. Halogen Control
A major fraction of the chlorides in coal (greater than 90%) is volatilized
and appears in the flue gas as HC1. Any aqueous-based scrubbing system would
be highly effective in absorption of HC1 (and any HF) in the flue gas. As a
result, chloride concentrations will build in the closed liquor loop to
levels such that the rate at which chloride is discharged from the system in
the washed cake will equal the rate at which chloride enters the system with
the flue gas. Steady-state levels of chloride in the closed liquor loop of
a 20 Mw prototype CEA/ADL dual alkali system rose to as high as 11,000 ppm
15
-------
(0.05-0.1% Cl in coal) with no apparent effect on the process operation
(LaMantia, e't al., 1977). Tests of the lime regeneration reaction at ADL
have shown that lime utilization and solids properties are unaffected by
chloride concentrations as high as 25,000 ppm.
C. WASTE PROPERTIES
The only waste material from the CEA/ADL dual alkali process is the solid
waste calcium salt mixture which is washed and contains some residual process
liquor. There are no other purges from the system.
This solid material will contain approximately 55-70% insoluble solids and
will have excellent handling properties due to precipitation of mix crystals
of CaS04/CaS03. The material has a very high angle of repose and is easy to
manage in solids handling and transport equipment. The solids are non-
thixotropic, drain well, and do not reslurry when exposed to rain. If
further chemical treatment is required, these excellent handling properties
should prove to be an advantage.
The exact chemical composition of the solids will depend somewhat upon fly
ash loading, the chemical composition of the flue gas and fly ash, and the
degree of oxidation of sulfite to sulfate encountered in the system. For
a high sulfur coal application we would expect the following general chemical
composition (dry cake basis):
CaSO_ • 1/2 H20 = 80-85 wt %
CaS04 = 10-15 wt %
Na2S04 + Na2S03 + NaCl = 1-2 wt %
CaC03 + Inerts = 5-10 wt %
Results of the EPA/ADL dual alkali program indicate that the calcium sulfate
is coprecipitate'd with the calcium sulfite and is not present as gypsum in
solids from the concentrated dual alkali mode (LaMantia, et al., 1977). The
sodium salts in the washed cake at these low levels of sodium content appear
to be occluded in the calcium salt crystals and are difficult to wash or
leach out to lower levels. Sodium losses at these levels are negligible as
an element of the overall cost of operating the system.
The waste material will also contain chloride (as NaCl) and other volatile
constituents such as fluorides, in the coal as sodium salts which are removed
in the scrubbing system. The levels of these constituents will build ir. the
closed liquor loop to levels at which the losses in the washed cake become
equal, at steady state, to the rate at which the trace constituents are
scrubbed from the flue gas. This problem is similar to that encountered in
any wet scrubbing system, even recovery systems which employ a "prescrubber
loop" to protect the closed loop chemical system.
16
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IV. DUAL ALKALI DEMONSTRATION SYSTEM AT LG&E
This chapter provides the description of the dual alkali system under
construction on LG&E Cane Run Unit No. 6. At the Cane Run Plant, lime
slurry scrubbing processes have been installed on Units 4 (180 Mw) and
5 (170 Mw).
A. BOILER SYSTEM DESCRIPTION
Cane Run Unit No. 6 consists of a pulverized coal-fired steam generator,
built by Combustion Engineering, with a Westinghouse turbine-generator.
The unit operates from a minimum of 60 Mw during off-peak hours to a
maximum load of 300 Mw during peak hours. The annual average load is
equivalent to approximately 180 Mw (about 60% of the gross peak capacity).
In the present system, flue gas from the steam generator passes, in parallel
streams, though two Ljungstrom combustion air preheaters. Each air pre-
heater discharges flue gas through separate ducts to an electrostatic
precipitator designed for 99.4% particulate removal efficiency. From the
precipitator the gases enter two induced draft fans (each handling 50% of
the total gas) and the two gas streams are then combined before entering
the stack.
The sulfur dioxide system will be installed between the existing induced
draft fans and the chimney. Hot flue gas will be drawn from the existing
ducting at the outlet of the induced draft fans and fed to the dual alkali
scrubber system through two booster fans. The scrubber gas will be re-
heated and then returned to' the existing entrance to the stack. Appropriate
dampers will be provided to allow bypass of gas around the scrubber system
using the existing duct.
Coal for Unit No. 6 is received from a number of sources. A dry ultimate
analysis given in Table IV-1 being typical of the coal fired. The average
sulfur content 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 will result in
an average S02 emission of about seven times of those allowed by the present
Federal New Source Performance Standards (1.2 Ibs of S02/MM Btu).
The flue gas conditions at the exit of the existing induced draft fans are
given in Table IV-2. The gas flow rate through each fan is controlled to
be equal. The gas flow rate shown in Table IV-2 represents the total gas
flow.
B. DESIGN BASIS FOR THE DUAL ALKALI SYSTEM
The design basis for the dual alkali system is summarized in Table IV-3.
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/hr is equivalent to the boiler peak load capacity of
17
-------
TABLE IV-1
ULTIMATE COAL ANALYSIS
(Dry Basis)
Carbon
Hydrogen
Nitrogen
Chlorine
Sulfur
Ash
Oxygen
Moisture
Heat Content, Btu/lb
Typical
Analysis,
67.15
4.72
1.28
0.04
4.81
17.06
4.94
8.95
11,000
Range,
64.0-70.0
4.3-5.25
0.6-1.5
0.03-0.06
3.5-6.33
15.5-24.5
3.8-6.2
8.0-10.75
9,500-12,400 Maximum
10,400-11,900 Normal
18
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TABLE IV-2
FLUE GAS CONDITIONS AT THE INLET OF THE DUAL ALKALI SYSTEM
Normal Operating Temperature
Maximum Gas Temperature for Periods up to 5 Mins.
Normal pressure at I.D. Fan Outlet
Boiler Excess Air
Air Heater Leakage
Flue Gas Density at Sea Level @ 70°F
Total Pressure at Stack Entrance
Boiler Load Points (Ibs/hr flue gas):
Design
Boiler Maximum Continuous Rating
Control Load
Minimum Normal Operating Load
300 °F
600°F
-1" to +2" WG
25%
Maximum 35%
10%
0.078 lb/ft3
+2" WG
3,372,000
3,003,000
1,440,000
658,000
19
-------
TABLE IV-3
DESIGN BASIS
Coal (Dry Basis):
Sulfur
Chloride
Heat Content
Inlet Gas:
Flow Rate (Volumetric)
(Weight)
Temperature
SO,,
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%
<0.10 lb/106 Btu
1200 ppm-(M). 45 lb/106 Btu)
iO.10 lb/106 Btu
20
-------
300 Mw. The dual alkali system will meet all applicable federal, state,
and local pollution control and safety regulations. The maximum SC>2 con-
centration in the clean gas will be 200 ppm (for coal containing up to 5%
sulfur), well below requirements of the Federal NSPS.
At present, Cane Run Unit No. 6 is operating with all applicable federal,
state, and local operating permits for air, water (NPDES), OSHA, etc.
Construction permits have been issued by the Air Pollution Control District
of Jefferson County District (APCDJC) for the construction of an S02 re-
moval system for Cane Run Unit No. 6. The permit complies with the two
enforcement orders with the EPA (November 5, 1975) and the APCDJC
(December 10, 1975).
Disposal of wastes from the dual alkali system will meet all applicable
federal, state, and local solid waste disposal regulations in effect at
present. None of the wastes produced by the control system will be dis-
charged to or allowed to enter any naturally occurring surface water. A
long-range disposal plan is under development at this time. Such a plan
will be available by July 1, 1977 in accordance with present agreement
under the NPDES Permit Regulations. A preliminary disposal plan is pre-
sented as part of this manual.
The existing 518 foot stack will be the only source of gaseous emissions
from the system. A flue gas bypass will be provided to allow untreated
boiler flue gas to enter the stack, bypassing the control system scrubber.
The scrubber system is designed to be completely isolated from the flue gas
during periods in which the bypass is open, to allow safe entry into the
scrubber system for maintenance and inspection while the boiler continues
normal operation. Also, each absorber can be isolated independently and
maintenance can be provided to the absorbed while the other absorber is in
operation. The duct dampers are designed such that with the dual alkali
system in operation and the bypass closed, no more than 1.0% of the total
flue gas will leak through the bypass system into the stack.
The dual alkali system will be equipped with sufficient instruments, in
addition to those required to operate the process, to permit accurate
measurements of the appropriate streams required to calculate, material and
energy balances. In particular, instrumentation will be provided to permit
continuous monitoring of S02 concentrations in the flue gas entering and
leaving the control system as well as the measurement of the quantities of
all. chemicals and water entering the system.
""" '" i '" i • ' * "
C. GUARANTEES
1. Sulfur Dioxide Emission
The system shall provide such control that emissions from the stack shall
be no greater than 200 ppm S0£ 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.
21
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2. Particulate Emission
In addition to meeting applicable regulations, the system shall also be
designed to meet Federal New Source Performance Standards for emissions
of particulates under all conditions of boiler operation. The dual alkali
system will not add any particulate matter to the emissions of particulate
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 moles CaO per
mole of S02 removed from the flue gas.
4. Sodium Carbonate Makeup
Soda ash makeup will not exceed 0.045 moles of Na2C03 per mole of S02
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 mole Na2C03 for each mole 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 Na2C03 from the guarantee point
to a level approaching minimal makeup.
5. Power Consumption
At the peak operating rate (300 Mw) 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. SC>2 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.
D. GENERAL DESCRIPTION OF THE DUAL ALKALI SYSTEM
The dual alkali system will use carbide lime and soda ash as raw chemicals.
Carbide lime is a byproduct of acetylene production and is available
locally at a significantly lower price compared to commercial lime. The
carbide lime will be barged to the plant in the form of slurry containing
30% solids. The slurry is unloaded at the Cane Run Plant and stored in a
tank. The specifications of carbide lime are given in Table IV-4.
22
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TABLE IV-4
CARBIDE LIME SPECIFICATIONS
Carbide Lime
Slurrya
Calcium hydroxide
Ca(OH) ....................... 92. 50
Available calcium oxide
CaO ........................... 70.01
Calcium carbonate
CaC03 ......................... 1. 85
Silica
.......................... 1.50
Iron and alumina oxides
R203 .......................... 1.60
Magnesium oxides
MgO ........................... 0.07
Sulfur ........................... 0. 15
Phosphorus ....................... 0.01
Free carbon ...................... 0.25
Free water .......................
i
Not analyzed ..................... 2.07
Available as slurry containing 30% insoluble
solids.
Source: Airco catalog (1969).
23
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The lime is. specified to have a Ca(OH)2 content of 92.5% and a particle
size distribution equivalent to 90% through a 325 mesh screen.
As discussed previously, the dual alkali system can be divided into three
major sections: absorber section; reactor section; and solids/liquid
separation section. 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. Also, spare instrumentation has
been provided for critical control operations.
In addition to the dual alkali system, a sludge disposal system will be
installed at the Cane Run Plant. The details of the sludge disposal are
given in the later part of this chapter.
The process flowsheet for the system is shown in CEA drawings3 040044-1-1
and 040044-1-2, and the plot plan is shown in CEA drawings 040044-2-0 (not
included here). The flue gas from the Cane Run Unit No. 6 boiler passes
through two existing electrostatic precipitators and two existing induced
draft fans before entering the dual alkali system.
1. Absorption Section
The flue gas from the existing induced draft fan is forced by a booster
fan into an absorber. There are two absorber modules and each module is
equipped with a booster fan. A common duct connects the two inlet ducts
to the booster fans.
The hot flue gas is cooled by sprays of absorber solution directed at the
underside of the bottom tray. These sprays keep the underside 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. Prior to entering the stack,
the saturated gas from the demister is heated 50F°, to 175°F, by hot flue
gas from a reheater fired with No. 2 oil.
The absorber design is based upon full scale and pilot experience with
similar sodium absorption systems. The design is conservatively based
upon 9.0 fps gas velocity, a rate consistent with good mass transfer, low
pressure drop, and minimum entrainment. 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 common duct
and shutting down one absorber module) or with two absorber modules.
a
A set of large size CEA drawings for this system may be obtained from
Environmental Protection Agency, Research Triangle Park, North Carolina.
Because of too many details, these drawings cannot be reduced; therefore,
most of them are not included here.
24
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I
-------
Stream No.
Volume, ACFM
Temperature, F
Pressure, inches WG
Dry Gas, 0/min
H.O Vapor, #/min
Total Gas, 0/min
SO., #/min
S02, PPM (Dry Vol)
Particulates, 0/min
H,0, #/min
z
Na-CO, , j/min
NaOH, #/roin
Na2S03. #/pin
NaHSOj, ///rain
Na2SOA. fAun
Ca(OH)2, #/min
CaSO.-isH 0, #/min
CaCO,, S/rain
3
Inerts, #/min
NaCL, tf/min
Total, tf/rain
Z Solids, ///min
Flow, GPM
PH
Temp, °F
1
532,907
300
+2.0
26,699
1,316
28,015
194.95
3,471
2.48
11
19,933.5
174.9
666.9
1,542.9
445.8
22,764
0
2,481
4-8
120-140
2
525,880
303
+11.5
26,699
1,316
28,015
194.95
3,471
2.48
12
12,919.5
113.4
432.2
1.000.0
288.9
14,754.0
0
1,608.0
4-8
120-140
3
436,516
126
+3.5
26,515
2,474
28,989
11.25
200
2.48
13
7,014.0
61.5
234.7
542.9
156.9
8,010.0
0
873.0
4-8
120-140
4 5
11,000 487,215
60 176
AHB +2.0
850 27,839
11.25
200
2.48
1* 15 Jl 11
13,642.8 14,828.1 21,867.0 4,582.0
6.8
50.0
119.7 347.2 582.0
456.4 95.0
1,056.0 1,016.3 1,559.2
305.1 303.6 460.5
15,580.0 16,552.0 24,563.7 4,582.0
00 00
1,698.0 1,837.0 27,101.0 550.0*
4-8 7-13 6-11
120-140 120-140 120-140
32
3.0
AMB.
Combustion Equipment Assoc.
Material Balance
for
Drawing #040044-1-1 Rev. G
*Intermittent Max. Flow
-------
•i
SS f
040044--f~2 R£y. F
.„ _,, CCA AOL DUAL ALKALI DKMJLFUMIATlON
.OUIVVIU.I OAI • CUKTHIC "" "
-------
Strv.im No. 14 15
KjO, f/mln 13,642.8 14,828.1
Na2COr »/mln 6.6
NaOH, l/mtn ' 50.0
NajSOj, 1/nUn 119.7 347.2
NaHSO.,, J/mln 456.4
NajSO^, J/mln 1,056.0 1,016.3
Ca(OH)2, l/mln
CaSOj-'sHjO, J/mln
CaS04-ljH20. J/min
CaCO,, l/mln
Inercs, l/min
Nad, l/mln 305. j 303.6
Total, ff/min 15,580.0 16,552.0
I Solids 0 0
Flow, era 1,693.0 1,637.0
pll
Te»p. °F
•Includes water unu-rinx process
from pump seals
**Inlcrai t tent Mnximtim
17 IS 19
2,150.8 537.7 14,233.0
50.2
349.4
1,019.8
852.0 213.0
331.0
39.4
5.6
69.2 17.3 17.3
305.1
3,072.0 768.0 16,351.0
30.0 30.0 2.4
305.2 76.3 1,785.0
10-14 7.0 6-13
120-140
2.0 21 22 21 24 25 26 27 28 29 30 33
2.108.5 29,182.fl 756.0 442.1 2.421.4 40). 9 403.9 878.0 1.075.4
11.9 U.9 13.7 n.J
7.3 101.3 0.50 6.8 1.4 i.u
51.0 704.9 1.4 47.5 9.6 9.6
146.7 2,057.6 10.0 138.8 J7.9 27.9
426.0
662.0 662.0
76.8 78.8
11.6 11.6
34.6 34.6 34.6
44.5 615.5 1.00 41.5 K.I 8.3
3,147.0 32,676.0 756.0 1,246.0 2,656.0 46S.II 13.7 451.3 878.0 1,536.0
25.0 0 0 6J.I 0 0 30.0
302.0 1,618.0 91.0 299.0 50.0 50.0 105.0* 152.6 250. 0«« 135.0 max
7-13 7-13 7-1J 8-14 7-11 7-13
120-140 120-140 AMU. 120-140 120-140 120-140 AMB. 120-140
Combustion Equipment Assoc.
Material Balance
Ear
i Drawing 040044-1-2 Rev F
-------
For control of tray feed liquor pH, regenerated scrubbing liquor from
thickener hold tank is mixed in line with absorber recycle liquor for
each unit; the mixture is then fed to the top tray in each absorber. The
absorber recycle liquor is used in the spray section below the trays. A
bleedstream of the absorber recycle liquor is withdrawn and sent to the
reactor system for regeneration. The bleed rate is controlled by the liquid
level in the absorber. 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 recircula-
tion rate for each absorber (sprays plus trays) corresponds to an L/G of
5.7 gals./I,000 acf.
The overall gas pressure drop through the dual alkali system is less than
9.5 inches WG and includes a pressure drop of 4-6 inches WG across the
absorber trays.
On the gas side, appropriate interlocks are provided in the bypass and FGD
system inlet dampers to enable bringing scrubbers on- or off-line without
interruption of the boiler operation. The speed of each of the booster
fans is controlled to maintain the desired pressure level at the outlet of
the existing boiler induced draft fans (with load input from the boiler
control system) . Pressures and temperatures are measured at appropriate
points throughout the gas flow and the scrubber system. S02 is monitored
by continuous analyzers at the inlet and outlet of the absorber. Provision
is made for emergency water supply for automatic quenching, if recycle pumps
fall.
2. Reaction Section
The spent liquor is introduced to the primary reactor of the two-stage
reactor system along with slurried carbide lime from the carbide lime
storage tank for the dual alkali system (day tank). The primary reactor
has a nominal liquor holdup time of 4.5 minutes at design flow. The primary
reactor overflows by gravity into the secondary reactor, which has a nominal
liquor holdup of 40 minutes at design flow, where the reaction between lime
and sodium salts is completed. The reaction product is a slurry containing
2-4% insoluble calcium salts and the regenerated sodium salt solution. The
reactor liquor is pumped to the solid/liquid separation section. The pump-
ing rate is controlled by the liquid level in the reactor.
There are two reactor trains in the system and each train consists of a
primary reactor, a secondary reactor, and a reactor pump. 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. Both the reactor trains are sized
identically; each module can be operated on liquor from the corresponding
scrubber or liquor from both the scrubbers. For short term, 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.
29
-------
The carbide lime slurry used from regeneration of the spent absorber
solution is received as a 30% solids slurry and stored in a large tank
for use in the three FGD systems at Cane Run. 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. The
slurry feed rate to the primary reactor is controlled by the pH of the
liquor in the corresponding secondary reactor. For example, the slurry
feed rate may be controlled to maintain a pH of 12.0 in the secondary re-
actor.
3. Solids/Liquid Separation
The reactor effluent streams are fed to the 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 rated to handle 50% of the total solids pro-
duced at the design conditions. Each filter can be operated independently.
For optimum performance (to obtain cake containing high dry solids and low
soluble salts) it is desirable to operate the filters at fixed conditions
(constant drum speed, submergence, wash ratio, etc). Therefore, the cake
rate is controlled by changing the number of filters in operation. The
number of filters in operation is determined by the quantity of solids
accumulated in the thickener, which is reflected in the solids concentra-
tion in the underflow slurry. The density of the underflow slurry is
measured and thickener hold tank liquor is added as required to maintain
the percent solids in the underflow slurry to about 25%. The number of
filters in operation is changed if the concentration of solids in the under-
flow slurry cannot be controlled using the dilution liquor.
Soda ash is added to the system to make up for the sodium salts lost in the
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 feed rate is generally controlled in
proportion to the lime slurry feed rate. Over the long run the lime slurry
feed is proportional to the filter cake produced, and thus, the sodium |
losses in the cake. The soda ash solution is prepared using thickener hold
tank liquor, which is fed to the soda ash solution tank at a constant 50 gpm.
Soda ash solution is pumped to the thickener.
30
-------
4. Spills and Leakages
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, some liquor can be lost, though, 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.
5. 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, will
be submitted to the Jefferson County Air Pollution Control Board in
July 1977.
As currently conceived, 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 approximately
40% solids. The combined wastes will then be transported to an onsite dis-
posal 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 adequate
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.
31
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V. MATERIAL AND ENERGY BALANCES
Cane Run Unit No. 6 has a rated capacity of 280 Mw and a peak load capacity
of 300 Mw. The system is designed to handle the peak load, and the material
and energy balances have been calculated for the design conditions. The
basis for the material and energy balances is given in Table V-l. The de-
sign coal contains 5% sulfur and 0.04% chloride. All estimates are based
on 94% of the sulfur in the coal appearing in the flue gas. Process flow-
sheets with detailed material balances for the system are given in CEA
Drawings 040044-1-1 and 040044-1-2 in Chapter IV.
A. MATERIAL BALANCES
1. Overall Balance
The overall balance for the dual alkali system is shown in Table V-2.
Filter cake is the only waste product from the system. The weight of the
filter cake (1,246 Ibs/min.) is roughly equal to the weight of the S02 and
chloride absorbed (370 Ibs/min.), plus the weight of net bound and unbound
water in the cake (394 Ibs/min.), plus lime (461 Ibs/min. as Ca(OH)2 and
inerts), and soda ash (14 Ibs/min.). The small difference is due to oxida-
tion in the system and evolution of carbon dioxide from the soda ash.
The total gas flow rate at the inlet of the system is 1,065,000 acfm at a
temperature of 300°F. Gas is supplied from two existing induced draft fans
located downstream of the existing precipitators. The gas'flow rate for
each fan is 50% of the total gas flow. Two absorber trains are used in the
dual alkali system; each train has its own booster fan to force the gas
through the absorber. The total saturated gas flow rate from both absorbers
is 873,000 acfm at 126°F. Combustion gas from the oil-fired reheater is
mixed with saturated gases to reheat the exhaust gases 50°F. The total flow
rate of reheated gas from the two trains is 974,000 acfm at 176°F.
The total S02 in the combined inlet gas to the two scrubbers at design con-
ditions is 390 Ibs/min., which corresponds to an S02 concentration in the
absorber inlet gas of 3,471 ppm on a dry volumetric basis. The 862 con-
centration in the absorber outlet gas is 200 ppm. This is equivalent to
a total of 22.5 Ibs/min. of SC>2 in the. outlet gases, which represents a
design removal efficiency of 94.2%.
At design load, regenerated scrubbing liquor is fed to each absorber at a
flow rate of 3,675 gpm, which is equivalent to about 4.2 gals/1,000 acf of
saturated gas. The total design flow rate to the top trays in the two
absorbers including recycle of absorber bottoms is 5,400 gpm, equal to
about 6.2 gal/1,000 scf of saturated gas. Absorber bottoms are also re-
circulated to the spray system in each absorber. The flow rate to the
sprays in the two absorbers is 3,200 gpm, equivalent to 3.7 gals/1,000 acf
of saturated gas. The spent absorber stream from the two absorbers at the
rate of 3,400 gpm is sent to the two reactor trains. The difference be-
tween the feed forward to the two absorbers and the bleed from the absorbers
33
-------
TABLE V-l
BASIS FOR MATERIAL AND ENERGY BALANCES
Coal (dry basis);
Sulfur
Chloride
Heating value
5.0% S
0.04% Cl
11,000 Btu/lb
Inlet Gas:
Flow rate
Temperature
S02
02
Particulate
1,065,000 ACFM
300°F
3471 ppm (dry basis)
5.7 vol. %
<0.1 lb/106 Btu
Outlet Gas:
S02
Particulate
200 ppm (dry basis) (M).45 lb/106 Btu)
20.10 lb/106 Btu
Absorber Feed Concentration:
NaOH + 2[Na2C03]
Na2S03
0.09 M
0.18 M
Oxidation and Sodium Makeup Rates;
Oxidation
10% AS02 (molar basis)
£4.5% AS02 (molar basis)
Calcium Feed Stoichiometry;
Solids in slurry
Available Ca(OH)2
Ca(OH)2 efficiency
30%
92.5% solids
98%
Waste Solids:
Wash ratio
Insoluble solids
2.0 displacement washes
>55 wt %
34-
-------
TABLE V-2
OVERALL MATERIAL BALANCE FOR THE DUAL ALKALI SYSTEM
S02 - inlet flue gas
- outlet flue gas
- cake
390 Ibs/min
22 Ibs/min
368 Ibs/min
Water - input to process3 325 gpm
- evaporation in scrubber 278 gpm
- cake 47 gpm
Lime
460 Ibs/min
Makeup soda ash
13.7 Ibs/min
Fuel oil - (to reheat wet gases)
6 gpm
Cake
1,246 Ibs/min
Basis: 5% S in coal
94% S02 removal
300 Mw boiler load
Includes all water inputs (filter cake wash water, seal
water, water in carbide lime slurry, and makeup water).
35
-------
is 278 gpm, equal to the design rate of evaporation in the two absorbers.
This evaporation rate is roughly 1 gpm/megawatt.
As discussed before, at excess air levels equivalent to 5-6% Q£ in the
boiler flue gas encountered in utility boiler operations burning coal
containing higher than 2.5% sulfur, the level of oxidation is expected
to be on the order of 5-10% of the sulfur dioxide removal. As shown in
Table V-l, the oxidation in the system is conservatively estimated at 10%
of the SC>2 removed. The sulfite and sulfate concentrations indicated in
the table are consistent with the level required to precipitate sulfate
as a calcium salt in balance with 10% oxidation rate (taking into account
losses of Na2SC>4 in the washed cake). The total active sodium concentra-
tion in the absorber feed is set at 0.45 M ([Na2SC>3] = 0.18 M, [NaOH] =
0.08 M, and [Na2C03] = 0.01 M), which results in a Na2S04 concentration
of 0.47 M.
The NaCl concentration in the absorber liquor is equivalent to 0.34 M and
represents a steady-state level such that the rate at which NaCl is lost
in the washed cake is equivalent to the chloride absorbed from the gas:
1.8 Ibs/min.
The feed forward rate of the regenerated liquor from the thickener hold
tank to the absorber is controlled by the pH of the absorber bleed. At
design conditions the absorber bleed pH is assumed to be 6. At this pH
the absorber bleed will contain 0.31 M NaHS03 and 0.07 M Na2S03. The
Na2SC>4 concentration in the bleed is increased to 0.52 M. The changes
in the concentrations in the outlet and the inlet streams reflect 10%
oxidation, absorption of 368 Ibs/min. of SC>2, and changes in the stream
volumetric flow rate due to the evaporation of water in the absorbers.
The design feed rate to the two primary reactors is about 3,400 gpm of
spent absorber liquor (1,700 gpm to each reactor). Lime slurry contain-
ing 30% solids is also fed to the reactors at a rate of 152 gpm. The
calcium hydroxide available in the solids is 92.5%. Thus, the total
feed of available calcium hydroxide to the two primary reactors is 426
Ibs/min. This rate is equivalent to 1.0 moles of calcium hydroxide per
mole of S02 removed in the absorbers.
The liquor from the primary reactor overflows into the secondary reactor
where the reaction is completed.
The composition of the liquor in the secondary reactor is dependent on
the degree of regeneration. For design purposes the secondary reactor
is assumed to operate at a pH of 12. At this pH the composition of the
secondary reactor liquor is: [NaOH] = 0.085 M, [Na2S03] = 0.19 M, and
[Na2S04] = 0.48 M. The soluble calcium concentration in the liquor is
less than 100 ppm. The liquor also contains calcium sulfite and calcium
sulfate solids. The solids concentration in the slurry is 2.3%. The
solids contain 1-2% unreacted lime, 5% inerts (from the carbide lime
slurry), about 10% calcium sulfate, and about 84% calcium sulfite (see
cake composition in the following paragraphs).
36
-------
The liquor from the two secondary reactors is pumped at a combined rate
of 3,570 gpm to the thickener center well where the solids are allowed
to settle. The underflow slurry is recycled around the thickener and a
bleed from this recirculation loop is sent to the filters. The concentra-
tion of solids in the underflow slurry from the thickener is controlled
at about 25% solids.
The filters are operated on overflow with the slurry level in the filter
tubs controlled by the position of the overflow weir. At design load,
the total slurry feed to the filters is 300 gpm and contains approximately
3,150 Ibs of insoluble solids/hr. (25% insoluble solids). About 60% of the
total slurry fed to the filters is returned in the overflow to the thickener.
The solids are filtered, forming a cake which is washed with water to remove
sodium salts in the liquor entrained in the cake. The design wash rate is
90 gpm,. which corresponds to a wash ratio of about 2.0 (gals, wash water/gal.
entrained liquor). The combined filtrate (wash water and recovered liquor)
is returned to the thickener. The washed cake is discharged at a rate of
1,246 Ibs/min. from the filter drum, and the composition of the washed filter
cake is:
Insoluble salts - 63% of cake weight
CaS0.3 • 1/2 H20 - 84% of insoluble salts
CaS04 • 1/2 H20 - 10% of insoluble salts
Inerts and unreacted lime - 6% of insoluble salts
Soluble salts - 2.2% of insoluble salts
NaCl - 0.9% of insoluble salts
Other Na salts - 1.3% of insoluble salts
The rate of soda ash makeup required to replace the sodium value lost in
the cake is 13.7 Ibs/min., equivalent to 2.3% of the S02 absorbed on a molar
basis. Clarified, regenerated liquor overflows the thickener at the rate of
about 3,600 gpm and is stored in the thickener hold tank from which it is
pumped to the absorbers. Makeup water is also added to the thickener hold
tank to maintain the overall system water balance. The quantity of makeup
water added varies according to the boiler operation and meteorological
conditions. The overall system water balance is discussed in the following
section.
2. Water Balance
a. Steady-State Balance
In order to operate the dual alkali system in a closed loop over a full
range of conditions, it is necessary to have a flexible water balance. The
principal factors affecting the water balance are boiler load, sulfur con-
tent of the coal, and the degree of cake washing. Table V-3 lists the inputs
and outputs for both contact and noncontact water used in the system and shows
the steady-state system water balance for operation on 3.8% sulfur coal (the
expected average sulfur content). The water balance is given for three dif-
ferent boiler loads--20%, 60%, and 100% of the peak 300 megawatt capacity.
37
-------
TABLE V-3
WATER BALANCE AT EXPECTED OPERATING CONDITIONS
(All Flow Rates in gpm)
Basis: 3.8% sulfur coal
55% insoluble solids in the cake
2.0 wash ratio
Load
of 300 Mw)
20%
60%
100%
Process Water Inputs:
Lime Slurry-Free Water
-Chemically Combined Water
Pump Seal Water
Instrument Purge Water
Filter Cake Wash Water
Rain Watera
Total
Noncontact Water Inputs:
Fan Bearing Cooling Water
Vacuum Pump Seal Water
Total
Process Water Outputs:
Evaporation to the Flue Gas
Cake-Free 'Water
-Chemically Combined Water
Evaporation to Atmosphere3
Total
Noncontact Water Outputs:
Fan Bearing Cooling Water
Vacuum Pump Seal Water
Total
Net Water Added to the System to
Close Process Water Balance
20.
2.
20.
0.
24.
0.6
68.4
175
8
183
100.1
175
8
183
31.7
62.6
6.0
21.0
0.5
72.2
0.6
162.9
175
24.2
199.2
236.6
175
24.2
199.2
73.7
104.3
10.0
21.6
0.5
120.3
0.6
257.3
175
40.4
215.4
55.6
12.0
0.5
32.0
166.9
36.1
1.6
32.0
278.2
60.1
2.6
, 32.0
372.9
175
40.4
215.4
115.6
Annual average(see Figure V-5 for evaporation from open vessels).
Note: Seal water is assumed to be 20 gpm.
38
-------
The block diagram in Figure V-l shows the general breakdown of the water
balance by each process section at 100% load. Figure V-2 gives the detailed
schematic showing each flow stream. Water removed from the system includes
evaporation to the gas and water in the filter cake. Water in the cake in-
cludes both free water and chemically combined water (water of crystalliza-
tion). Water is added to the system in the lime slurry (both as slurry water
and chemically combined), cake wash, instrument purge, and pump seals. All
water fed to the pump seals enters the system; that which drains out of the
seals is collected in sumps and returned to the thickener. The evaporation
to the gas is assumed to vary directly with the boiler load and the varia-
tions in the inlet gas temperature and inlet gas humidity. The nonlinear
relationship between the gas flow rate and the percent load is not considered
here. In general, such considerations would tend to increase evaporation of
water to the flue gas at low loads over that estimated here, and thereby
provide more flexibility in the water balance.
In addition to these water streams, which are directly related to the
process operation, there is evaporation of water to the atmosphere from
the open vessels (thickener, thickener hold tank, etc.) and addition of
water to the system from rainfall. The evaporation to the atmosphere
from open vessels is based upon prevailing meteorological conditions in
the Louisville area. Mean monthly values of temperature and humidity have
been used to determine the range of evaporation. The rainfall corresponds
to a range from nil to a daily maximum of 7" per day (34 gpm based on the
thickener and thickener hold tank cross-sectional areas)'.
The noncontact water streams are the booster fan cooling water and the
seal water for the vacuum pumps. The noncontact water streams are not in-
cluded in the process water balance since this water will be segregated
from the process streams. Because the noncontact water will contain no
pollutants and will have a temperature rise of only 5-10°F, it is expected
that the water can be discharged directly in the river.
b. -.Water Balance Sensitivity
In Figures V-3 and V-4 the total water removed from the system is plotted
against water added to the system. The evaporation to the atmosphere from
open tanks and rainfall are not included here since they are not controlled
as part of the system and are considered perturbations. The noncontact
water streams are also not included.' The two figures show the water balance
for combustion of coal containing 4.7% sulfur and 3.8% sulfur. The expected
operating conditions at Louisville are 3.8% sulfur coal, 55% solids in the
cake, and a wash ratio of 2.0 (Figure V-4). The capacity of each filter is
about 400 Ibs of dry cake/min. at the design conditions.
The water balance line (line at 45° to axis) is the locus of points where
the water removed from the system is equal to water added to the system.
Points falling below and to the right of the water balance line indicate
that the system is out of balance, and the points falling above the water
balance line show the system is within balance (the balance maintained by
adding necessary makeup water to the system). The solid lines representing
100% load, 60% load, and 20% load have points representing 0, 1, 2, or 3
39
-------
Noncontact
Fan Bearing
| Cooling Water
I 175 gpm
I
Instrument Purge Water 0.5 gpm
SO2 Absorption
Absorber
F.D. Fan
Absorber Recycle Pump
Noncontact
Fan Bearing
Cooling Water
175 gpm
Evaporation 278.2 gpm
Lime Slurry
Free Water 104.3 gpm
Chemically Combined Water 10 gpm
Pump Seal Water 12 gpm
Cake Wash Water 120.3 gpm
Pump Seal Water 9.6 gpm
Ram Water 0.6 gpm
Net Water Added to Close the Water -
Loop 115.6 gpm
Reactor System
Reactor
Lime Slurry Tank
Soda Ash Tank
Pumps - Reactor,
Soda Ash
Lime Slurry
Noncontact
Vacuum Seal
Water
40.4 gpm
Thickener/Filter
Thickener
Filter
Thickener Hold Tank
Pumps Underflow,
Filtrate
Vacuum and Thickener
Hold Tank
Evaporation 32 gpm
Cake
Free Water 60.1 gpm
Chemically Combined Water 2.6 gpm
Noncontact
Vacuum Seal
! Water 40.4 gpm
FIGURE V-l BLOCK DIAGRAM OF WATER BALANCE AT 100% LOAD
40
-------
Flue Gas
Lime Slurry
Fan
Flue Gas, Evaporation
i to the Gas
Bearing
Cooling Water
1 lie
| 175 gpm
<•
JX
V
K
i
'\
Lime
Slurry
Tank
1 -
1 F.D. Fan
< 278.2 gpm
Absorber
• Fan Bearing
Cooling Water
1 "TK fin
Thickener Hold Tank -^
Net Walei
/
*
^
as
/
?
r
Added
Required
/
Na2C03
Soda
Ash
Tank
Reactor
0.6 gpm .^^
1
»S~
r 104.3 gpm / 1
r Combined Water 10.0 gpm / 1
/
Evaporation
V) aom
X
Thickener
^r
,
1
1
^
^
/
(
V
^
^,
>
1
s
^
I
Pump Seal Water
Pnmns -m ^
ps "*• 21.6 gpm
Instrument Purge Water
Vacuum Pump Seal Water
40.4 gpm
<"
• »- /
' Vacuum | Cake Wash Water 120.3 gpm
Pump j
/^-^ Cake
f \ »• Free Water 60.1 gpm
Filtrate
Receiver
\ Filter / l-nemicaMv i«oniuinea water ^.o gpiti
FIGURE V-2 WATER BALANCE AT 100% LOAD (3.8% S COAL, 55% SOLIDS IN CAKE. 2.0 WASH RATIO)
DASHED LINES SHOW WATER INPUT OR WATER OUTPUT FROM THE SYSTEM
-------
500
400
o.
en
o
O
a
+^
!U
300
200
100
Percent Solids
in Cake
Filter 63 55
0
1
2
3
O
d
3
(Make up Water > 0)
System
In Balance
System
Out of Balance
20% Load
Seal Water + Instrument Bleed Water
I I
100
200 300
Water Added to System, gpm
400
500
Basis: 4.7% S in coal (design condition)
100% seal water added to system (40.5 gpm)
2.0 wash ratio.
Note: Dashed lines show solids generated equal to solids removed for different percent solids in cake.
FIGURE V-3 WATER BALANCE FOR 4.7% SULFUR COAL
42
-------
500
(Make up Water >0)
System ^t
In Balance
Seal Water + Instrument Bleed Water
I I
100
200 ' 300
Water Added to System, gpm
400
Basis: 3.8% S in coal (operating condition)
100% seal water added to system (40.5 gpm)
2.0 wash ratio.
Note: Dashed lines show solids generated equal to solids removed for different percent solids in cake.
FIGURE V-4 WATER BALANCE FOR 3.8% SULFUR COAL
43
-------
filters in operation. The dashed lines on the plot show solids generated
in the system equal to the solids removed from the system for cakes contain-
ing different percent solids. Therefore, the dashed lines show steady-state
conditions over a long term, and the points (at 20%, 60%, and 100% load in
the figures) show the actual operating conditions at a given time. The
dashed lines meet this axis at 40.5 gpm (Figures V-3 and V-4), which repre-
sents maximum pump seal water (40 gpm) and instrument bleed water (0.5 gpm)
added to the system.
The water balance is affected by the number of filters in operation. At
low loads (20-35% load) the filters may be shut down to decrease the net
water addition to the system. Therefore, solids will be added to the system
and the total system volume increase will be the sum of net water and the
net solids added to the system.
c. Evaporation and Rainfall
The evaporation of water from the thickener and hold tank is shown in
Figure V-5 (total cross-sectional area is equivalent to a cross-sectional
area of 120' diameter tank). The evaporation rate is plotted against wind
speed. The relationship may be considered to be good to +25% and is based
on the assumption of still liquid surface. In practice, the liquid surfaces
are protected by the sides of the vessels, and therefore the average wind
speed obtained from meteorological data may not be the same as the wind
speed on the liquid surface. Also, the liquid surfaces are not smooth,
and therefore the actual surface exposed to the atmosphere is greater than
the calculated surface area from the vessel dimensions.
The meteorological conditions shown in Figure V-5 represent the average
conditions at Louisville. The mean monthly temperature varies from 30°F
to 80°F, and the mean yearly temperature is 57°F. Similarly, the mean
monthly wind speed varies from 8.8 ft/sec, to 14.7 ft/sec., and the mean
yearly wind speed is 12.4 ft/sec. The humidity varies from 60% to 80%.
The liquor temperature in the thickener (at exposed surface) is expected
to be 120°F during the operation of the system and lower during shutdown
periods. The evaporation rate varies from 21 to 40 gpm (during system
operation) with an average evaporation rate of 32 gpm.
The maximum rainfall is expected to be 2"/hour (hourly average), equivalent
to a water addition rate of 234 gpm (in the thickener and hold tank). The
daily maximum rainfall is 7"/day, equivalent to a water addition rate of
34 gpm. The average rainfall at Louisville is 43"/year, and the average
snowfall is 17.5"/year. The total precipitation is equivalent to a water
addition rate of 0.6 gpm.
B. ENERGY CONSUMPTION
The energy required for the dual alkali system includes both electrical
energy and fuel for reheat. The flue gas supplied to the dual alkali
system represents a waste stream, and the difference in the energy content
of the outlet gas stream and the inlet gas stream is not considered here.
44
-------
30 -
Temperature = 120 F
System in Operation
Atmospheric Temperature, F
Liquor
Temperature = 100°F
System Not in
Operation
60% Relative Humidity
— — 80% Relative Humidity
20 -
10
10 15
Wind Speed, ft/sec
Note: Mean temperature at Louisville = 57 F.
FIGURE V-5 EVAPORATION IN A 120' DIAMETER THICKENER
45
-------
The electrical energy requirement for the dual alkali system is presented
in Table V-4. The energy requirements in Table V-4 are estimated for the
dual alkali system installed on a boiler operating at peak capacity of
300 Mw. The electrical energy is used for fans, pumps, agitators, etc.
Equipment consuming little energy, such as lighting, electrical energy for
the compressor to supply pressurized air for instruments, and maintenance
equipment, are included under miscellaneous items. The total electrical
energy requirement is estimated to be 3.1 megawatts, or approximately 1.0%
of the peak power generation for Unit No. 6. About 60% of the total
electrical energy is required for the booster fans, 10% for reheater fans,
and 30% for the rest of the system. The energy requirement for the fan
varies in direct proportion to the design gas flow rate and therefore varies
directly with the boiler capacity. (The pressure drop through the system is
assumed to be constant for this purpose.) The 30% of the energy used in the
dual alkali system varies roughly with the feed forward rate in the system.
The feed forward rate is in direct proportion to the sulfur dioxide removed
from the system. (The liquor concentration is assumed to be fixed for this
purpose.)
No. 2 fuel oil will be used to reheat the saturated gas. The wet gas will
be reheated from 126°F to 176°F. The estimated fuel requirement is 343 gal/
hour when the boiler is generating 300 Mw. The fuel oil energy requirement
is equal to 48 x 106 Btu/hour.
46
-------
TABLE V-4
ELECTRICAL ENERGY REQUIREMENTS FOR THE DUAL ALKAKI SYSTEM
AT THE LOUISVILLE GAS AND
ELECTRIC
COMPANY
Number at Full Load
Equipment
Booster Fan
Pumps :
Absorber Recycle
Thickener Hold Tank
Thickener Underflow
Soda Ash
Vacuum
Reactor
Filtrate Sump
Lime Slurry
Underflow Sump
Soda Ash Sump
Agitators:
Lime Slurry
Primary Reactor
Secondary Reactor
Soda Ash
Vacuum Filter
Thickener:
Mechanism
Rake
Filter:
Drum Drive
Blowback Fan
Soda Ash Weigh Feeder
Bin Vibrator
Weigh Feeder
Dust Collector
Bin Slide Gate
Reheater
Primary Fan
Secondary Fan
Compressor
Miscellaneous :
Instrumentation,
Space Heaters, Lighting,
H A -a ir -i TI rr Pisat-o-KQ Aff.
Operating
2
2
1
1
1
1.5
2
1
1
0
0
1
2
2
1
1.5
1
0
1.5
1.5
1
1
0
0
2
2
2
Spare
0
2
1
1
1
1.5
0
1
1
2
2
0
0
0
0
1.5
0
1
1.5
1.5
0
0
1
1
0
0
0
BHP
1,246 1
215
157
33
6
100
59
20
30
8.5
5
20
7.5
25
1.5
1.5
5
3
5
2
1.5
1
0.5
0.5
100
40
7.5
200
IHP
,250
250
200
40
10
100
75
25
30
15
7.5
20
7.5
25
1.5
1.5
5
3
5
2
1.5
1
0.5
0.5
100
40
7.5
200
Total BHP
At Full Load
2,492
430
157
33
6
150
118
20
30
0
0
20
15
50
1.5
2
5
0
7.5
3
1.5
1
0
0
200
Ort
80
15
200
TOTAL hp 4,037.5
TOTAL kw 3,102
% of 300 Mw 1.0%
47
-------
VI. PROCESS EQUIPMENT AND INSTRUMENTATION
A. EQUIPMENT
1. General Arrangement
The plot plan for the dual alkali system is shown in CEA drawing3 040044-2-0.
The general arrangement for individual equipment is shown in the following
CEA drawings.a These drawings are preliminary and if required will be up-
dated in the Phase II report to reflect later modifications.
Absorber Lower Plan (CEA drawing 040044-2-1)
The ducting connected to the induced draft fan of the boiler system, booster
fan for the dual alkali system, absorber bypass ducting, chimney base, re-
cycle pumps and the pump building for the absorbers are shown in the drawing.
The dampers indicated by DJ, .platforms and ladders in the lower part of the
absorber are also shown here. The drawing shows only absorber A101 section.
Absorber A102 section is the mirror image and is shown in CEA drawing
040044-2-3. Absorber sections A-A and B-B indicated for absorber A101 are
shown in CEA drawings 040044-2-8 and 040044-2-9, respectively.
Absorber A101 Upper Plan (CEA drawing 040044-2-2)
The drawing shows the upper part of the absorber, outlet ducting, reheater,
connection of ducting to breeching and the chimney. The two manholes in the
upper part of the absorber, platform, and ladders are also shown here. The
drawing shows absorber A101 section only. Absorber A102 section is the
mirror image of this drawing and is shown in CEA drawing 040044-2-4.
Reactor, Silo, Vacuum Filter Areas Plan (CEA drawing 040044-2-6)
The plan is shown at two elevations—at grade and at elevation 475 ft. The
primary and secondary reactors, reactor pumps, filters, filtrate receivers,
vacuum pumps for filter, lime slurry tanks, lime slurry pumps, soda ash
silo, weigh feeder, soda ash solution tank and soda ash solution pumps are
all shown in this drawing. There are two reactor systems, three filter
systems, two lime slurry pumps and two soda ash solution pumps. Also, part
of the thickener and thickener hold tank are shown in this drawing. Sections
C-C, D-D and E-E indicated in this drawing are shown in General Arrangement
Sections-Reactor and Silo Areas, Vacuum Filter and Pump Building (CEA draw-
ing 040044-2-11).
&A set of large size CEA drawings may be obtained from Environmental Pro-
tection Agency, Research Triangle Park, North Carolina. Because of too
many details, these drawings cannot be reduced; and, therefore, are not
included here.
49
-------
Thickener. Pipe Tunnel and Filter Building (CEA Drawing 040044-2-10)
Sections A-A and B-B from the Thickener and Hold Tank Plan (CEA drawing
040044-2-5) are shown here. The drawing shows the center well for the
thickener, the superstructure, pipe rack to the feed well, the thickener
underflow pumps, the pipe tunnel and accessway underneath the thickener.
2. Equipment Details
Table VI-1 contains a list of equipment in the system. Materials of con-
struction for the system are summarized in Table VI-2.
The system is designed with appropriate corrosion resistance where required
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 ss; the filtration equipment
is both 316L ss and fiberglass; and the absorber trays are 317L ss.
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 ss between the reheater and stack.
Tables VI-3 through VI-14 give details regarding the design basis, service,
dimensions, and materials of construction for each of the equipment items
listed in Table VI-1.
In accordance with standard design practice at LG&E, all the tanks in
Table VI-10, except the thickener hold tank, are closed top.
B. PIPING AND INSTRUMENTATION
1. General Description
The preliminary list of instrumentation for the dual alkali system is
shown in Table VI-15, and the piping and instrument diagrams are given in
CEA drawings3 040044-1-3, 4 and 6. The system is designed to minimize
operator interface. All the remote controls are located in a centralized
control room from which the system can be started up, operated, and shut1
down. The control room is furnished with appropriate controllers, indica-
tors, recorders, switches, and other necessary instrumentation for the safe
and convenient operation of the system. Included on the control panel are:
A set of large size CEA drawings may be obtained from Environmental Protec-
tion Agency, Research Triangle Park, North Carolina. Because of too many
details, these drawings cannot be reduced; and therefore are not included here.
50
-------
TABLE VI-1
EQUIPMENT LIST
Equipment
1. Agitators
(w/motors)
Description
Reactant Feed Tank
Primary Reactor Tank
Secondary Reactor Tank
Soda Ash Solution Tank
Vacuum Filter
No.
Required
1
2
2
1
3
2. Dampers
Booster Fan Inlet
By-Pass
Outlet
Reheater'Fan
2
1
2
2
3. Ductwork
Take-Off Connecting Duct
Booster Fan Inlet Duct
Booster Fan Outlet Duct
Absorber Outlet Duct
Duct/By-Pass Transition
2
2
2
2.
1
Expansion Joints
Tie-in ,
Booster Fan Inlet
Booster Fan Pant Leg
Booster Fan Outlet
Booster Fan Outlet Duct
Absorber Outlet PC#1
Absorber Outlet PC#2
Breeching
By-Pass
2
2
4
2
2
2
2
1
2
51
-------
Equipment
TABLE VI-1
(Cont.)
Description
No.
Required
5. Fans
Booster Fan, Drive
and Motor
Reheater Fan & Motor
Filter Blow Back Fan & Motor
2
2
2
3
6. Heaters
Reheater
7. Pumps
Reactant Feed Pump & Motor
Reactor Transfer Pump & Motor
Thickener Underflow Pump & Motor
Soda Ash Solution Pump & Motor
Hold Transfer Pump & Motor
Service Pump & Motor
Absorber Recycle Pump & Motor
Vacuum Pumps & Motor
Filtrate Sump Pumps & Motor
Soda Ash Sump Pump
Underflow Sump Pump & Motor
2
2
2
2
2
1
4
3
2
2
2
8. Tanks
Reactant Feed Tank
Primary Reactor Tank
Secondary Reactor Tank
Soda Ash Silo & Accessories
(1) Dust Collector
(1) Bin Bottom with Motor
(1) Vibrator with Motor
Soda Ash Delumper & Motor
Weigh Feed & Motor
Thickener Hold Tank
Soda Ash Solution Tank
Filtrate Tanks
1
2
2
1
1
1
1
1
1
1
1
3
52 _
-------
TABLE VI-1
(Cont.)
Equipment
Description
No.
Required
9. Tanks (Cont.)
Thickener
10. Thickener
Mechanism
Thickener Mechanism & Motor
Thickener Lift Rake Motor
1
1
11. Vacuum Filter
Vacuum Filter System & Drive
12. Vessels
Absorber
53
-------
TABLE VI-2
MATERIALS OF CONSTRUCTION
1. Agitators
(a) Lime slurry tank—carbon steel.
(b) Primary reactors—shaft: carbon steel, rubber lined;
hub and blades: 317L s.s.
(c) Secondary reactors—shaft: carbon steel, rubber lined;
hub and blades: 317L s.s.
(d) Soda ash tank—carbon steel, rubber lined.
2. Dampers
(a) Booster fan inlet —A36 steel
(b) Bypass and absorber outlet—316L s.s.
3. Duct Work
(a) Duct work carrying hot flue gas to the scrubber inlet is carbon
steel.
(b) Duct work carrying saturated flue gas from the scrubber to
reheater is carbon steel, coated internally with a flake
reinforced polyester lining.
(c) Duct work carrying reheated flue gas from the reheater to
stack is 317L s.s.
(d) The bypass/transition duct is carbon steel.
4. Expansion Joints
(a) Expansion joints on inlet side of absorbers are of viton.
(b) Expansion joints on outlet side of absorbers are of chlorobutyl
for wet gas and of viton for dry gas (after reheat).
5. Fans
(a) Housing—A441.
(b) Blades—A441, with wear plates constructed from A441 material.
54
-------
TABLE VI-2
(Cont.)
6. Pumps
(a) Housing—rubber lined
(b) Impeller—rubber lined
7. Tanks
(a) Thickener overflow tank—carbon steel, flake reinforced
polyester lining.
(b) Primary reactors—316L s.s.
(c) Secondary reactors—carbon steel, flake reinforced polyester
lining, rubber pad on bottom.
(d) Lime slurry storage tank—carbon steel.
(e) Soda ash mixing tank—carbon steel.
8. Soda Ash Silo
(a) Carbon steel
9. Weigh Feeders
(a) Frame—mild steel
(b) Internals—304 s.s.
10. Thickener
(a) Thickener shell—concrete with carbon steel interior, flake
reinforced lining.
(b) Rake, shaft and centerwell—carbon steel, rubber lined.
11. Vacuum Filter
(a) Filter drum—316 s.s.
(b) Agitator—316 s.s.
(c) Filtrate receiver—FRP
55
-------
TABLE VI-2
(Cont.)
12. Absorber
(a) Absorber shell—carbon steel, coated internally with flake
reinforced polyester lining.
(b) Absorber trays—317 s.s.
(c) Demister—polypropylene.
13. Piping
(a) All process piping is FRP.
(b) Piping for make-up water and service water and all other
piping not subject to corrosion is carbon steel.
56
-------
TABLE VI-3
AGITATORS
Lime Slurry Reactor
Storage Tank 1
Number Required: 1 2
Impeller Type turbine turbine
Impeller dia. 87" 62"
RPM 30 45
Shaft dia. 4.5" 3"
H.P. 20 7.5
Material of
Construction :
Shaft C.S. R.C.C.S.
Blades C.S. 31 7L S.S.
Reactor Soda Ash
2 Tank
2 1
turbine propeller
92" 12"
37 350
5" 1.5"
25 1.5
R.*C«U*h>* R«U*0«b«
317L S.S. R.C.C.S
Data are given per agitator
C.S. - Carbon steel
R.C.C.S - Rubber covered carbon steel
S.S. - Stainless steel
-------
TABLE VI-4
DAMPERS
Booster Fan Inlet
Ul
00
Number Required:
Design flow rate
- ACFM
- °F
Size
Position of duct
Type
Entry
Normal position
Material of Construction
Max. gas leakage, % of
design flow rate
533,000
350
135-1/4" x 138-1/2"
Horizontal
Guillotine
Bottom
Open
A36 steel
Bypass
1
1,065,000
350
162" x 240"
Horizontal
Multi-louver
Closed
316L s.s.
Absorber Outlet
487,000
200
156" dia.
Horizontal
Guillotine
Bottom
Open
316L s.s.
Paint external members
Zinc chromate
Zinc chromate
Zinc chromate
-------
TABLE VI-5
DUCTWORK
Equipment
No. Required
Dimensions
Take off connecting duct
VO
Booster Fan Inlet Duct
Booster Fan Outlet Duct
Absorber Outlet Duct
Duct Bypass/Transition
Inlet 11'8" x 11'6"
Outlet to booster fan inlet duct 11T3" x 11'6"
Outlet to bypass transition ll'l" x 12'1"
Overall dimensions 11'8" x 11'6" x 16'10"
Inlet 11'3" x 11'6"
Outlets 16'8" x 3'2" (two)
Overall dimensions 11'6" x 28' x 16'6"
Inlet duct 10'7" d
Outlet duct 13'9" d
Overall length 12*
Inlet 13'd
Outlet 13'd
Overall length 80'
Inlets from take off connecting duct ll'l" x 12'1" (two)
Inlets from absorber outlet duct 13'd (two)
Outlet 28' x 13'6"
Overall dimensions 30'3" x 24'6" x 19'10"
See Table 7.3 for materials of construction.
-------
TABLE VI-6
EXPANSION JOINTS
Service
No.
Required
Size
Material
Tie-in
Booster Fan Inlet
Booster Fan Pant Leg
Booster Fan Outlet
Absorber Inlet
Absorber Outlet 1
Absorber Outlet 2
Breeching
Bypass
Reheater Duct
2
2
4
2
2
2
2
1
2
2
ll'lO" x ll'8-l/2"
11'10" x 11'8-1/2"
3'4-3/8" x 16*10-1/2"
10'9-7/8" x 8110-1/8"
13'11-5/8" dia.
13'2" dia.
13f2" dia0
13'8" x 28*2"
11'10" x 11'8-1/2"
Viton
Viton
Viton
Viton
Viton
Chlorobutyl
Viton
Viton
Viton
Reheater vendor to specify size and material
All the expansion joints except absorber outlet 1 and reheater duct expansion joints are designed for
400°F with excursions to 600°F for 5 minutes at 4 times a year. All the expansion joints are 9" wide.
-------
TABLE VI-7
BOOSTER FANS
Number Required
Flue gas Volume
Flue gas temperature
Inlet static pressure
Outlet pressure at design
flow rate
Gas density
Inlet dust loading
Maximum vibration
amplitude
Type
Fan blade design
Materials of construction
Drive
Motor HP
Volts
Motor rpm
533,000 acfm
300°F
+2 inch WG
10.5 inch WG
0.0526 lb/cu ft
0.0537 gr/cu ft
2.2 mils at 720 rpm
Centrifugal forced draft
Backward inclined airfoil with
wear plates
Carbon steel
Fluid drive
1,250
4,000
720
61
-------
TABLE VI-8
REHEATERS
Operating Conditions
Wet flue gas flow rate
Temperature
Pressure
H20 Vapor
S02
Particulates
Temperature after reheat
Heater Requirements
For Flue gas
Radiation loss
Heater outlet temperature
Turndown
Heater outlet pressure
Fuel Data
Fuel type
Oil flow rate
Air Inlet Temperature
Winter
Summer
No. of Reheaters Required
436,500 acfm
126°F
+2 inch WG
2,475 Ibs/min
11.25 Ibs/min
200 ppm dry basis
2.48 Ibs/min
176°F
25,632,000 Btu/hr
1,282,000 Btu/hr
800°F max.
to 20% of the capacity
+7 inch WG
Number 2 fuel oil
171 gal/hr
0°F
100 °F
62
-------
TABLE VI-9
CT>
Number Required
Operating
Spare
Capacity
gpm
head, ft
Speed
Material of
Construction
Packing
Drive
Motor Mounting
Voltage, volts
Drip proof
BHP/IHP
Service Factor
Overall Size
Absorber
Recycle
Pump
2
2
4,600
130
Variable
RLCI
Yes
V belt
Overhead
4000
Yes
215/250
1.15
12x10x25
Reactor
Pump
2
1,965
85
Variable
RLCI
Yes
V belt
Overhead
460
Yes
62/75
1.15
10x8x21
PUMPS
Thickener
Hold Tank
Pump
1
1
4,185
105
Variable
RLCI
Yes
V belt
Overhead
4000
Yes
157/200
1.15
12x10x25
Thickener
Underflow
Pump
1
1
665
115
Variable
RLCI
Yes
V belt
Overhead
460
Yes
33/40
1.15
5x5x14
Lime
Slurry
Pump
1
1
340
115
Variable
NI-Hard
Yes
V belt
Overhead
460
Yes
30/30
1.15
3x1.5x16
Soda Ash
Pump
1
1
140
75
Variable
RLCI
Yes
V belt
Overhead
460
Yes
6/10
1.15
1x1.5x6
RLCI - Rubber lined cast iron
All pumps are centrifugal pumps.
a - All dimensions are in feet.
-------
TAB 1.1',__yi_:Jo
TANKS
Process Data
Liquor specific gravity
pH range
Chlorides, ppm
Operating pressure, in wg
Design pressure, in wg
Operating temperature, °F
Design temperature, °F
Specified data
Minimum thickness, Inches
Primary Reaction
Tank
1.1
5-11
12,000
Liquid head
Liquid head
126
Secondary Reaction
Tank
1.1
11-12.5
12,000
Liquid head
Liquid head
126
Thickener
Hold Tank
1.1
12
12,000
Liquid head
Liquid head
110
1/1
Lime Slurry
Storage Tank
1.2
12
Liquid head
Liquid head
70
100
1/4
Soda Ash
Tank
1.1
12
12,000
Liquid head
Liquid head
110
3/16
*- Seismic zone
Code
i
Tank shape
Dimensions, dia x height
Baffles
Agitator
Materials
Shell and head
Internal structure
Nozzles necks/flanges
Lining
Paint
Gaskets
Erection Weight, Ibs
Operating Weight, Ibs
1
API650
Cylindrical
11' x 14'
4
Yes
316L S.S.
316L S.S.
316L S.S.
None
Zinc chromate primer
Neoprene
75,000
97,500
1
API650
Cylindrical
20' x 331
4
Yes
A283 (C.S.)
C.S.
C.S. & 316L S.S.
Glass reinforced
polyester + 3/8"
thick rubber pad
on bottom
Zinc chromate primer
Neoprene
36,000
71,500
1
API650
Cylindrical
36'x 23'
None
No
A283 (C.S.)
C.S.
C.S. (, 316L S.S.
Class reinforced
polyester
Zinc chromate primer
Neoprene
39,000
1,183,000
1
API650
Cylindrical
24'6" x 24'6"
4
Yes
A283 (C.S.)
C.S.
C.S.
Zinc chromate
primer
Neoprene
39,000
785,000
1
API650
Cylindrical
6' x 8'
4
Yes
A283 (C.S.)
C.S.
C.S. & 316L S.S.
Glass reinforced
polyester
7.1nc chromate primer
Neoprene
2,500
17,500
C.S. = carbon steel; S.S =stainless steel; all tanks are closed nt top except thickener iiold t/ink.
-------
TABLE VI-11
SODA ASH SILO
Process Data
Specific gravity
Soda ash type
Specified Data
Minimum thickness
Wind Load at 30'
Seismic Zone
Code
Tank shape
Size
Thickness
Attachments
Materials
Shell and head
Internals
Nozzles Necks/flanges
Paint
Gaskets
Erection Weight
Operating Weight
65 lbs/ff
dense
1/4"
30 PSF
1
API650
Cylindrical plus conical bottom
12' diameter x 34' 6" height - cylinder
6' bottom diameter x 5'6" height cone
3/8" thick bottom of cylinder
5/16" thick middle of cylinder
1/4" thick top of cylinder
1/4" thick cone
Cone vibrator, baghouse at top, and
piping at top for pneumatic feed system
A36 (C.S.)
C.S.
C.S.
Zinc chromate primer
Neoprene
22,000 Ibs.
300,000 Ibs.
65
-------
TABLE VI-12
THICKENER
Design stream conditions
Reactor Bleed
Filter overflow
Filtrate
Soda ash solution
Thickener recycle
Thickener underflow
Operating temperature
Seismic zone
Thickener type
Diameter
Height
Feed well
Diameter
Height
No. of arms on rake
Cone scrapper
Overflow weir plate
Access walk way
Rake drive motor
Rake lifting device motor
1 Materials
Rake
Feed well
Shell
Bottom
Weir Plate
Shell and Bottom
Paint
3,570 gpm
148 gpm
500 gpm
50 gpm
155 gpm
605 gpm
110° F
1
Flat bottom
125'
23'
12'
11'
2
Yes
Notched
On one side of the superstructure
5 HP
3 HP
Rubber covered carbon steel
Rubber covered carbon steel
Concrete lined with carbon steel
Concrete
FRP
Lined with glass reinforced polyester
Zinc chromate primer
66
-------
TABLE VI-13
VACUUM FILTER
Process Data
Net slurry feed
Specific gravity
Temperature
pH
Wash water
Filter Requirements
% Solids in cake
Total flow
Filtrate
Flow rate
PH
Specific gravity
Cake wash rate
No. of filters required
Size
Cake discharge mechanism
Liquid level control in
filter tub
Cake wash assembly
Filter drum speed
Agitator type
Filtrate Receiver
Motor
Vacuum pump
Drum drive
Filter blow back pump
Agitator drive
Materials
Filter drum
Filter agitator
Filter scraper
Filtrate receiver
Drainage grid
Filter media
Design 3,147 Ibs/min.
302 gpm
Maximum 4,533 Ibs/min
448 gpm
1.25
140°F maximum
11-12.5
2,108 Ibs/min design
55% minimum
63% average
1,246 Ibs/min design
1,584 Ibs/min maximum
299-750 gpm
10.5-12.3
1.064
91 gpm normal
300 gpm maximum
3 including spare
8' diameter 10'face
Blower assisted scraper blade
Adjustable overflow weir
Drip wash nozzles with drag net
0.3-3.0 rpm
Counter weighted rocker arm
54" diameter x 54" height
100 HP
5 HP
2 HP
1.5 HP
317 ELC stainless steel
317 ELC stainless steel
317 stainless steel with rubber tip
FRP
Polypropylene
Polypropylene
67
-------
TABLE VI-14
ABSORBER
Process Data
Specific gravity 1.2
pH range 5-12
Chlorides, ppm 12,000
Operating Pressure, inch WG +11.5
Design Pressure, inch WG +12.5
Operating Temperature, °F 125
Design Temperature, °F 350
Upset Conditions
Temperature, °F 600
Time; minutes 5
Specified Data
Corrosion allowance
Wind Load at 30', PSF
Seismic zone
Code
Tank Shape
Size
Thickness, inch
Internals
Materials
Shell and head
Trays/supports
Spray nozzles
Internal piping/supports
Mist eliminator/supports
Nozzle necks/flanges
Internal fasteners
Gaskets
External paint
Lining
Erection
Erection weight, Ibs.
Operating weight, Ibs.
none
30
1
API 650
Cylindrical shell with conical head
32' diameter x 45' height_shell
10'6" height x 13' top diameter_cone
3/8
Sprays + 2 trays + chevron demister
A283 (carbon steel)
317L S.S.
316 S.S.
FRP
Polypropylene
C.S. and S.S.
C.S.
Neoprene
Zinc chromate
Glass reinforced polyester
108,000
475,000
68
-------
TABLE VI-15
PRELIMINARY LIST OF INSTRUMENTS FOR THE DUAL ALKALI SO-, CONTROL SYSTEM
Type of Instrument Number
Ammeters for motors 24
Density rieter 1
Flow control valves 50
Flow indicators for process solutions 18
Flow indicators for water 21
Flow indicators for purge air 34
Hand switches for manual operation 19
Level indicators 14
Manual indicating controller for damper 1
pH indicators 12
Pressure indicators 22
Soda ash weigh feed recorder 1
Solenoid valves for seal water 18
S02 monitors •*
Temperature indicators 14
69
-------
Gas Side
• SC>2 indicators and recorders monitoring S02 concentrations in the in-
let flue gas to the absorbers and the outlet flue gas concentration
before reheat.
• Temperature indicators for the flue gas at the inlet to the booster
fan, at the inlet of the absorber, absorber outlet, and reheated flue
gases.
• Pressure indicators on the gas side include pressure of the gas enter-
ing the booster fan, pressure at the downstream of the fan, pressure
at the absorber outlet, and pressure after the gases are reheated.
Pressure taps are provided in the absorber to measure pressure at
intermediate points.
• Instruments and controllers necessary for controlling the operation
of the fan and the dampers so that the flue gas desulfurization system
will not affect the operation of the boiler. The fan and the dampers
have been interlocked for emergency shutdown such as if the flue gas
temperature in the absorber rises above a specified limit.
Liquid Side
• Status indicators for motors on all pumps, agitators, fans and blowers,
filter drum and thickener rake drives, and solenoids operating control
valves. Green and red lights are used to indicate the status of motors
solenoid valves, etc. A green light is used to indicate the closed,
or off position; and a red light is used to indicate the open, or on
position.
• pH indicators for indicating pH in the reactor system bleed, absorber
bleed and top tray feed.
• Flow indicators and totalizers to measure feed chemicals, makeup water
and internal flows.
• Liquid level indicators for the absorber recycle tanks, secondary re-
actors and thickener hold tank.
2. Special Considerations
Two elements and two transmitters have been included at all critical con-
trol points in the system to provide spare instrumentation (on gas side tb
measure pressures and temperatures and on liquid side to measure levels and
pH's.) A selector switch in the control room is used to select the element
and the corresponding transmitter.
All the process lines are equipped with sufficient drain and flush valves.
The flush valve locations have been carefully selected where slurries are
present.
70
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All control valves with the exception of the lime slurry feed can be by-
passed so that the system can be operated in case of control valve failure.
Bypasses consist of three block valves, one on the bypass line and two
around the control valve. A control valve bypass is not provided on the
lime slurry line, since a bypass system here would be less useful due to
plugging problems. However, the reactor system can be operated at 100% of
the capacity with one reactor module for short durations while lime slurry
control valves are repaired.
All the pumps are individually connected with seal water supply lines.
Flow of seal water to each pump is adjusted locally using a hand control
valve and rotameter. Each seal water supply line is also equipped with
a solenoid valve interconnected with the pump start/stop switch to auto-
matically ensure a supply of seal water. When the pump is turned on, the
solenoid valve opens and the seal water is supplied to the pump. When the
pump is turned off, the solenoid valve closes and shuts off the seal water.
The solenoid valves are normally closed to prevent water leakage into the
system during pump downtime and power failures.
All the pumps are fitted with pressure gauges to indicate the pressures
developed by pumps. Similarly, the suction side of all vacuum pumps have
vacuum gauges to indicate the vacuum developed.
All pumps have check/block valves which open automatically when the pump
is turned on, and close when the pump is turned off. The digital logic
to control timings for the valves and pumps is not finalized. Pumps are
also equipped with hand switches so they can be operated in the field or
from remote location in the control room.
All the motors for the pumps, agitators, etc., have ammeters indicating
the current drawn by the motors. The current is indicated locally, but
if the current exceeds the preset value, an alarm in the control room is
activated.
3. Operating Philosophy
The liquid levels in the various tanks are controlled either by bleed or
feed stream flows to these tanks, or by overflow weir position. The control
of liquid levels in various tanks is shown in Table VI-16. The primary
reactors, thickener, and filter tubs are operated on overflow. The
absorber recycle tanks, secondary reactors, and soda ash tank are operated
on liquid level control with level maintained by the bleed streams from
these tanks. The liquid level in the lime slurry feed tank is maintained
by the lime slurry feed rate to the reactant feed tank, and the liquid
level in the thickener hold tank is maintained by the makeup water rate
to the system.
The feed forward flow rate from the thickener hold tank to absorber is
controlled for each absorber individually, to achieve the desired SC>2
removal in the system. The absorber bleed pH provides an indication of
the S02 concentration in the effluent gas stream and is used to adjust
71
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TABLE VI-16
CONTROL OF STREAM FLOW RATES TO MAINTAIN LIQUID LEVEL IN
VARIOUS TANKS IN THE DUAL ALKALI PROCESS
Tank Controlled Stream
Absorber Absorber bleed
Primary reactor Primary reactor overflow
Secondary reactor Reactor bleed and/or secondary reactor
overflow
Thickener Thickener overflow
Thickener hold tank Make-up water
Filter tub Slurry overflow
Soda ash tank Soda ash solution flow
Reactant feed tank Lime slurry feed to reactant feed tank
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the feed forward flow rate to the absorbers. The S02 concentration in
the effluent gas from the absorber will be controlled to less than 200 ppm.
The absorber liquor pH will be in the range of 5-6, corresponding to this
SC>2 concentration in the absorber effluent flue gas. The exact correlation
of outlet S0£ with bleed pH will be developed during system startup.
Liquor from the absorber tank is recycled to the sprays and the trays. The
feed forward from the thickener hold tank, controlled by the pH of the ab-
sorber bleed, is mixed with the absorber recycle liquor to the trays prior
to entering the absorber. The recycle is used for pH control and to main-
tain adequate liquor flow across the trays. The pH of the mixed liquor
stream is measured and is connected to an alarm system located on the con-
trol panel, so that if the pH drifts outside a preset range, the flow rates
can be adjusted accordingly.
The absorber bleed is fed to the primary reactor along with lime slurry.
The absorber bleed rate is controlled by liquid level in the absorber re-
cycle tank. The lime slurry feed rate to each primary reactor is con-
trolled by the pH of the secondary reactor liquor. The pH is a measure of
the extent of reaction in the reactor system.
Carbide lime slurry is supplied to the primary reactors from the lime hold
tank. The lime slurry is recycled around the slurry tank to maintain
sufficient velocity in the pipes to avoid solids deposition. A bleed from
the recycle is fed to the primary reactors and the excess lime slurry is
returned to the lime hold tank. A control valve on the return lime slurry
line is interconnected with the control valves on the lime slurry feed to
the individual reactors. The recycle valve is used to maintain enough
pressure in the feed lines to each primary reactor to ensure sufficient
slurry feed and adequate feed control. If the lime slurry feed to a re-
actor is less than desired and the control valve on the lime slurry feed
to this reactor is almost completely open, then the control valve on the
lime slurry return line will be closed slightly so that the flow to the re-
actor is increased.
Slurry from the primary reactors overflows by gravity to the secondary re-
actors where the regeneration reaction is completed. The liquor level in
the primary reactor is maintained by the height of the overflow weir. The
liquor level in the secondary reactor is maintained by controlling the
bleed rate from the reactor. The liquor level controls a valve on the dis-
charge of the secondary reactor pumps. The slurry from the reactor is fed
to the thickener center well.
The solids in the thickener are allowed to settle and the clear liquor over-
flows to the thickener hold tank. The underflow slurry from the thickener
is pumped to the filters. In order to maintain sufficient velocity of the
underflow slurry in the pipes to prevent deposition of solids, a constant
recycle of slurry around the thickener is maintained from which a bleed is
taken off to feed the filters. The recycled slurry is returned to the
solids zone in the thickener.
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The suspended solids concentration in the underflow slurry is a principal
factor affecting the cake thickness and the washability of the cake. The
slurry density is related to suspended solids concentration in the slurry
and, therefore, the slurry density is controlled by the use of dilution
liquor from the thickener hold tank and by the number of filters in service.
The underflow slurry density is measured by a density meter. If the slurry
is too thick, thickener hold tank liquor is added to dilute the slurry and/
or an additional filter put on line. If the slurry is thin, dilution liquor
is reduced or a filter shut down.
The slurry level in the filter tub is maintained by the position of the over-
flow weir. Excess slurry is fed to the filter to ensure the adequate level
in the tub. Slurry overflowing the tub is returned to the thickener center
well by gravity.
The filter cake is washed with makeup water to remove sodium salts in the
occluded liquor in the cake. Combined filtrate (recovered liquor and wash
water) is collected in the filtrate receiver and is returned to the thickener
center well.
Any sodium value lost in the cake is replaced by adding an equivalent amount
of the soda ash to the system. Process liquor from the thickener hold tank
is pumped to the soda ash solution tank at a constant rate of 50 gpm. The
soda ash is weighed on a weigh feeder and is fed to the soda ash solution
tank. The soda ash solution is pumped to the thickener at a rate to main-
tain a constant level in the soda ash solution tank.
The soda ash feed rate is controlled by the total lime slurry feed rate to
the two primary reactors. The lime slurry feed rate to each individual
reactor is measured and summed, and the soda ash feed rate is set in direct
proportion to the total lime slurry feed rate. The proportionality constant
may be changed, if desired. This type of control is based upon the fact
that the expected sodium loss varies proportional to the amount of lime fed
to the system, and the soluble sodium lost in the cake is a function of the
weight of the cake produced (for a constant wash ratio).
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VII. OFFSITES AND AUXILIARIES
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.
Since the system will use the same carbide lime as used in the existing
direct lime scrubbing systems at Cane Run, additional lime receiving,
storage and handling systems will not be required.
The offsites and services required for the Cane Run system are reviewed
in the following sections. Significant differences between the require-
ments for the system at the Cane Run Station and general applications of
dual alkali technology are indicated and alternative facilities or ser-
vices discussed.
A. ELECTRICAL POWER
Electrical power available at Cane Run Station for construction and opera-
tion of the system include the following:
4,160 V ac, three-phase, 60 hertz
480 V ac, three-phase, 60 hertz
120 V ac, single-phase, 60 hertz
A feed line will be taken from the existing 14 KV substation and the
voltage will be reduced in a step-down transformer to 4,160 volts. Step-
down transformers for further voltage reduction to 480 volts and from
480 volts to 120 volts will also be installed by LG&E. The cost of this
offsite (a feed line and the three step-down transformers) is included in
the capital investment for the system.
The power requirement for the system is estimated at about 1.0% of the
total power generated by the boiler at peak load. However, the design
gas flow rate for the dual alkali system at LG&E is higher than the maxi-
mum flow rate and therefore the estimated electrical energy requirement
should be conservative.
B. WATER SUPPLY
The maximum water requirement for the system is about 470 gpm, not includ-
ing the water associated with the slurried lime feed. Of this, approximately
250 gpm is required for the process and about 220 gpm for noncontract cooling
water.
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River water will be used for all water requirements. The river water is
available at the following conditions:
ii
Water Supply Pressure 50-100 psig
Water Temperature 35-95°F
Total Dissolved Solids 300-500 ppm
Suspended Solids 50-500 ppm
pH 6-8
Na2S04 20-200 ppm
Hardness 80-250 ppm
CaC03 50-250 ppm
Fe 0.1-30 ppm
Mn 0.15-2.5 ppm
NaCl 10-100 ppm
The water supply to the system will be filtered to prevent solids from
entering the pump seals and filter spray nozzles. An inline filter will
be used for this purpose, although the mesh size for the filter screen
has not been selected.
Liquid waste streams from a plant could also conceivably be used as process
makeup water for the dual alkali system. This offers the possibility of
reducing the fresh water requirement as well as reducing effluent waste
streams from the utility plant. Effects of chemicals present in the cool-
ing water blowdown on dual alkali process chemistry, materials of con-
struction, solids properties and raw material consumption have not been
evaluated.
C. INSTRUMENT AIR
Air is available at Cane Run Station at 60-125 psig. Air is used only for
instruments and air-operated controls. The total amount of air used for
the process is small and existing excess compressor capacity at the plant
should be adequate to supply the air. No new compressor capacity is antici-
pated.
D. OIL
No. 2 fuel oil will be used to reheat the wet exhaust gases from the
absorbers. LG&E is planning to convert a 15 Mw gas turbine to an oil
turbine and an oil tank with a 100,000 gallon capacity has been installed
for this purpose. A separate pump will be used to supply oil from this
tank to the dual alkali system. This same tank will also serve as the oil
storage tank for other S02 removal systems at the Cane Run Station. The
oil requirement for the dual alkali system to provide 50°F reheat at design
load is estimated to be 343 gal./hr.
In general, oil, steam or hot water may be used for reheat; or in some cases,
reheat may be supplied by bypassing part of the flue gas around the scrubber.
The latter possibility exists only with systems capable of high SO'2 removal
efficiencies (98 to 99% 862 removal) and thereby allowing reasonable overall
76
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efficiencies even though part of the flue gas is not treated. If steam
or hot water is used for reheat, no additional offsite equipment is re-
quired, since steam and hot water lines may be directly taken from the
utility plant. Use of oil requires a storage tank and an oil pump; al-
though in some cases, as in the system for Cane Run Station where oil is
used as a fuel for electricity generation, storage of oil for reheat can
be combined with the existing storage tanks at the plant.
E. CARBIDE LIME FACILITY
Carbide lime slurry will be used to regenerate the spent sodium solution.
Since receiving, handling and storage facilities for the carbide lime
slurry already exist at the plant, only a day tank to store lime slurry
for the process will be installed as a part of the dual alkali system.
Carbide lime is available as slurry containing 30% dry solids. The slurry
is shipped in the LG&E barges to the Cane Run Station. The slurry is
pumped from the barge to an agitated storage tank from which it is pumped
to a dual alkali day tank as required.
In general, calcined lime, hydrated lime, or carbide lime may be used to
regenerate the spent sodium solution. While carbide lime is cheaper than
commercial lime, it is not available at most locations. Normally, calcined
lime would be used. It would be slaked and fed to the system as a slurry, and
therefore would not be considered an offsite. It is included as an offsite here
because the carbide lime facility already exists. Although capital invest-
ment for this facility is not included in the total estimated capital re-
quirement for the dual alkali system at Cane Run, capital charges for the
facility are included in the estimated cost of the carbide lime delivered
to the system.
F. LABORATORY AND SHOP CAPABILITIES
The Cane Run Station has the necessary laboratory and shop capabilities for
the maintenance and operation of the dual alkali system and no additional
facilities are contemplated. The equipment required for wet chemical
analyses is small and can usually be incorporated in the existing plant
control lab.
1. Laboratory Capability
The laboratory equipment and materials for the chemical and physical testing
required during the operation and testing of the dual alkali system are as
follows:
• Analytical balances.
• Atomic absorption spectrophotometer.
• pH meter with electrodes for standard pH measurements and lead electrodes
for sulfate titration.
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• Forced draft-type oven with temperature control (+ 0.5°C).
• Automatic burets and magnetic stirrers. ,
• Distilled water and various reagents for wet analyses.
• Assorted glassware for sample preparations.
Much of this equipment may already be part of an existing control laboratory
at a power plant for use in monitoring and analysis of coal, cooling water,
boiler feed water, and waste streams; or can be easily included as a part
of the control laboratory equipment. In some cases, special analyses for
metal ions (calcium, sodium, and magnesium) requiring the use of an atomic
absorption spectrophotometer can be performed by outside testing laboratories.
2. Shop Capability
LG&E carries out their own plant construction. The Cane Run Station has
adequate shop facilities to operate and maintain the boilers and the exist-
ing direct lime scrubbing systems. The shops are equipped with tools and
equipment worth over $3.0 million, including a 175-ton capacity crane. No
additional shop capacity or capabilities are anticipated.
In general, the required shop capacity for dual alkali systems include the
following:
• Crane capacity to lift motor, pump, valves, etc., which need occasional
maintenance.
• Machine shop to machine relatively simple surfaces, thread pipes, etc.
• Welding equipment, both in shop and in field.
• Instrument shop to check out instruments.
• Electrical shop.
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VIII. CAPITAL AND OPERATING COSTS — DUAL ALKALI SYSTEMS
The capital and operating costs for the dual alkali system are developed
in this chapter. The estimated capital and operating costs are presented
both for the dual alkali system installed on Cane Run Unit No. 6 and for
generalized dual alkali systems for new 500 and 1,000 megawatt systems.
A. 300 Mw RETROFIT SYSTEM FOR LG&E CANE RUN NO. 6
1. Design Basis
The dual alkali system for Louisville Gas and Electric Company's Cane Run
Station is a retrofit system installed on Unit No. 6, an existing boiler
equipped with an electrostatic precipitator for particulate removal. The
design basis for the system is given in Table VIII-1. The system is de-
sighed to handle the flue gas produced with the boiler operating at a
gross peak load of 300 megawatts, and the design gas flow rate of 1,065,000
acfm at the scrubber inlet is about 10% higher than that estimated by
McGlamary, et al. (1975) for an existing boiler having 300 Mw capacity.
For coal containing 5.0% sulfur and 0.04% chloride (dry basis), the design
S02 removal efficiency is 94.2%.
The SC>2 removal system will have two booster fans, two absorbers, two re-
actor modules, one thickener, and three filters. The system will be capable
of operating in the range of 60 to 300 Mw boiler load. The waste exhaust
gas from the absorber will be reheated by a direct oil fired reheater. The
reheat is equivalent to 50°F. The system will have a bypass and appropriate
spare capacity, as shown in Table VIII-1. The sludge will be disposed in an
existing onsite pond after treatment. The cost of the pond is not included
in the capital cost estimate.
Carbide lime will be used as a raw material to regenerate the sodium solu-
tion in the dual alkali process. Carbide lime is available from a local
supplier. The use of carbide lime is expected to result in savings in the
operating cost compared to the system based on commercial lime. The carbide
lime will be supplied in a slurry form on a barge. An existing barge handling
facility including a slurry storage tank will be used for the dual alkali sys-
tem. At present, the carbide lime facility supplies lime for the two existing
S0~ removal systems installed at the Cane Run Station.
.2. Capital Investment
The capital investment for the dual alkali demonstration system is shown in
Table VIII-2. The capital costs are broken down into total materials,
erection, engineering, spare parts and working capital. The overall project
schedule is two years, with design starting in the latter part of 1976 and
construction scheduled for completion in the latter part of 1978. The costs
shown in Table VIII-2 are as incurred and therefore represent costs 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).
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TABLE VIII-1
DESIGN BASIS FOR THE DUAL ALKALI SYSTEM AT THE CANE RUN 6
LOUISVILLE GAS AND ELECTRIC COMPANY
Boiler Gross Peak Capacity, Mw
Boiler Gross Net Capacity, Mw
Annual Load Factor, %
Btu/kwhr (basis-input heat/gross peak
electricity generated)
S in Coal, %
Cl in Coal, %
Ash, %
Moisture, %
Btu/lb of Coal
Gas Flow Rate @ Scrubber Inlet, acfm
Temperature, °F
SO-, Ibs/min.
Fly Ash, Ibs/min.
S02 @ Scrubber Inlet, lb/106 Btu
Land Cost
SO2 Removal System;
S02 @ Scrubber Outlet, lb/106 Btu
S0£ Removal in Scrubber, %
Particulate Removal
Bypass
Turndown
Number of Absorber/Reactor Modules
Number of Filter Units
Thickeners
Carbide Lime Feed System
Soda Ash Silo Capacity
Reheat
Sludge Disposal
Spare Capacity,3 %
Filters
Pumps
Necessary Instruments to Run Process
300
277
60 (of gross peak capacity)
9,960
5.0
0.04
17
9
11,000
1,065,000
300
390
4.0
8.55
Not included
Retrofit
0.50
94.2
None
Yes
to 20% of Capacity
2
3
1
Existing (new day tank)
14 days
Direct Reheat with Oil-Fired
Reheater
Onsite Pond with Treatment
50
100
100
The system can be operated with one reactor system at full load and
one absorber system at less than 60% load.
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TABLE VIII-2
ESTIMATED CAPITAL COSTS FOR DUAL ALKALI SYSTEM AT THE CANE RUN 6
LOUISVILLE GAS AND ELECTRIC COMPANY
Dollars
Total Materials Cost:
Major Equipment Cost (Table VIII-3) 7,037,000
Other Materials Costa(Table VII-4) 2,525,000
Sludge Disposal Equipment 900,000
Additive Slurry Systemb 700.000
Total Materials Cost 11,162,000
Erection:°
Direct Labor (252,800 hrs. @ $12/hr)C 3,034,000
Field Supervision 273,000
Total Erection Cost 3,307,000
Engineering Costs:
System Supplier Engineering 1,323,000
Owner's Engineering Expenses 303,000
Owner's Consulting Engineer 852»000
Total Engineering Cost 2,478,000
Spare Parts, 2% of the Total Materials Cost 232,000
Working Capital 200.000
Total Capital Investment6 17,379,000
$/kw (Based on 300 Mw gross peak load)
(Based on 277 Mw gross net load)
57.9
62.7
Basis: .300 Mw gross peak load existing coal fired boiler (277 Mw net peak load)
S in coal, 5.0%
SO™ removal efficiency in scrubber, 94.2%
Stack gas reheat, 50% - direct oil fired reheater
Disposal of sludge after treatment to onsite pond
Project beginning mid 1976, ending late 1978, Avg. 1977 dollars
Necessary parts in storage and reasonable spare capacity
a
Sludge disposal equipment cost ($900,000) is shown separately. The $900,000
is the 3/7 portion of the total sludge disposal cost for Cane Run 4, 5 and 6.
bAdditive supply system cost ($700,000) is shown separately. The $700,000 is
the 3/7 portion of the total additive supply system for SOX removal systems
for Cane Run 4, 5 and 6.
°Includes plant overhead.
dErection equipment cost is included in plant overhead.
:The capital investment for the above system in 1976 dollars is equivalent to
$15.95 million or 53.15 $/kw (based on gross peak capacity).
81
e
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The total materials costs include major equipment (including sludge dis-
posal equipment), other materials (for offsites, foundations, etc.), and
cost of the additive slurry system. The materials costs represent the
delivered cost to the plant site including freight, insurance, taxes, and
profit.
The breakdown of the cost of major equipment is shown in Table VIII-3.
Major equipment includes absorbers, agitators, dampers, ductwork, expansion
joints, fans, fluid drives, instrumentation, lining, motors, pumps, reheaters,
structural steel, tanks, thickener shell and mechanism, vacuum filters, valves
and piping, soda ash silo and auxiliaries. The cost of the major equipment
is $6.2 million in January 1976 dollars. It is expected that most of the
items will be delivered in mid-1977. The total, escalated cost at 13.5%
per 1-1/2 years (to September 1977) is $7.03 million.
The breakdown of the other materials cost is given in Table VIII-4. These
costs include materials for buildings, land improvement, insulation, and
foundation for major equipment, and materials requirements for offsites.
Also, costs for the chimney liner, breeching, and accessories, and waste
disposal equipment are included as a part of additional materials. The
total cost of the purchased parts is $3.4 million. This is in addition to
the cost of major equipment. Again, the freight charges, taxes, insurance,
startup and modifications have been included in the other materials cost
and are not shown separately. The costs are escalated to the estimated
dates of delivery of materials.
Chimney liner coating and breeching and accessories represent a direct
retrofit cost. The total cost for these items as shown in Table VIII-4
is $400,000. The electrical offsite cost is $774,900 and includes station
control, feedline for 14 KV, appropriate stepdown transformers to reduce
voltage to 4160 V, 480 V and 120V, and grounding connections.
The waste disposal cost of $900,000 represents 3/7 of the total estimated
capital investment for the waste disposal system for all three scrubbing
systems at the Cane Run Station. The 3/7 factor is equal to the capacity
ratio for the Cane Run Unit No. 6 and the combined capacities of Cane
Run Units Nos. 4, 5, and 6. Similarly, the additive slurry system cost of
$700,000 represents 3/7 of the total estimated capital investment for the
total additive slurry system for all three scrubbing systems at the Cane Run
Station.
The cost of land for the sludge disposal pond or for the S02 removal system
is not included in the capital cost, as the system represents retrofit situa-
tion and, at present, no expenses are incurred.
The capital requirement for the carbide lime handling facility and the
storage facility is not included in Table VIII-2. However, the capital
investment for the day tank for storage of carbide lime slurry used in the
dual alkali system is included in the total cost shown in Table VIII-2.
Similarly, the initial cost of additional capacities for compressor pump to
supply instrument air, service water pump to supply makeup water, oil storage
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TABLE VIII-3
COST OF MAJOR EQUIPMENT COMPONENTS FOR DUAL ALKALI SYSTEM
AT THE LOUISVILLE GAS AND ELECTRIC COMPANY
a
Equipment Cost
Absorbers 778,165
Agitators 82,783
Dampers 310,986
Ductwork 437.471
Expansion Joints 139,497
Fans 367,770
Fluid Drives 124,457
Instrumentation 240,898
Lining 366,626
Motors 516,969
Pumps 204,058
Reheaters 144,739
Structural Steel 279,276
Tanks 526,198
Thickener Mechanism 171,093
Thickener Shell 122,553
Vacuum Filters 838,404
Valves and Piping 505,364
Weigh Feeder 43'082
6,200,389
Escalation cost for 13 1/2% for 1 1/2 year
period 837.052
Total 7,037,441
The equipment cost includes freight, insurance, taxes, etc.
and is delivered cost to Louisville Gas and Electric Company.
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TABLE VIII-4
ADDITIONAL PURCHASED PARTS COST FOR DUAL ALKALI SYSTEM
AT THE LOUISVILLE GAS AND ELECTRIC COMPANY
Pump and Filter Buildings 141,125
Equipment for Land Improvements 24,500
Insulation and Foundation for Fan 40,900
Foundation, etc. for Major Components 703,400
Instrumentation and Test Equipment 20,000
Concrete Ducts 18,400
Chimney Liner Coating3 288,000
Breeching and Accessories3 112,000
Waste Disposal Equipment 900,000
Electrical Offsite
Station Controlb 206,900
14KV OCB and Equipment13 45,500
4160V Auxiliary13 370,000
460V Auxiliary13 145,100
Station Grounding13 7.400
Piping for Services 300,900
Indirect Materials 93,000
Taxes . 8,300
TOTAL 3,425,425
Note: Purchased parts cost does not include cost of major equipment
components shown in Table VIII-3. The purchased parts cost includes
freight, etc. and is delivered cost to Louisville Gas and Electric
Company.
aCosts directly related to retrofit - $400,000.
bElectrical utilities - $774,900.
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tank, and switch gear building are not included in the estimated capital
investment.
The erection labor shown in Table VIII-2 includes electricians, boiler-
makers, pipefitters, carpenters, welders, etc., and covers the erection of
major equipment, temporary facilities, and plant startup and modifications.
Because of the low labor rates at this plant, the average escalated labor
cost including the overhead is $12 per hour. Including field supervision,
the total erection cost is expected to be $3.3 million.
The engineering costs include: engineering by system supplier, covering
selection of major equipment and design of the dual alkali process; con-
sulting engineering to provide the remainder of the engineering not covered
by system supplier; and local engineering and expenses representing owner's
cost. The total engineering cost is approximately $2.5 million and is equal
to 17% of the total material and erection costs.
The cost of spare parts is assumed to be 2% of the total materials cost.
Startup and modification costs are included in equipment and labor costs
and are not broken out as a separate cost item. Working capital is assumed
to be $200,000.
3. Annual Operating Costs
The system is expected to start up in late 1978, and therefore 1979 will be
the first full year of operation. The estimated annual operating costs for
the dual alkali system in 1979 dollars are shown in Table VIII-5.
The estimated annual operating costs in 1976 dollars have also been developed,
since these represent more well-defined costs using recent unit cost data.
Costs in 1976 dollars are shown in Table VIII-6.
Operating costs are based on an average sulfur content in the coal of 3.8%.
The average sulfur dioxide removal rate is assumed to be 297 Ibs/mi'nute
(94.2% S02 removal efficiency) at 300 Mw boiler load. 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 disposal 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/
kwhr (23.OC per 106 Btu) without reheat system to 2.7 mills/kwhr (26.70 per
106 Btu) with 50 F° reheat. The cost estimates for the year 1979 are about
20% higher.
The estimated cost of carbide lime in 1979 is $13.29/ton. This includes:
(a) cost of liir.e at $2.00/ton; (b) handling cost to barges at $5.53/ton;
(c) transportation in barge to Cane Run at $1.21/ton; (d) cost to unload
barge and supply lime slurry to dual alkali system at $4.55/ton. These
costs include capital charges and depreciation on capital investment.
85
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TABLE VIII-5
ESTIMATED AVERAGE ANNUAL OPERATING COSTS
FOR DUAL ALKALI AT THE LOUISVILLE GAS AND ELECTRIC COMPANY
(1979 $)
Quantity
oo
Direct Costs;
Carbide Lime
Soda Ash
Fuel Oila
Electricity
Water
Sludge Removal
Maintenance Materials
Labor
Operation
Maintenance
Analysis
Supervision
Total Direct Costs
58,728 tons
1,912 tons
1,802,808 gals.
16,188,480 kwhrs
126,100,000 gals.
185,280 tons
Unit Cost, $
13.29/ton
78.65/ton
0.43/gal.
0.01/kwhr
0.05/1,000 gals.
2.01/wet ton
2.5% of total materials cost
26,280 hrs
26,280 hrs
2,080 hrs
2,080 hrs
8.18/hr
8.28/hr
10.00/hr
Various
Total
Ctosts, $
780,500
150,400
775,200
161,900
6,300
372,400
279,000
215,000
217,600
20,800
40.000
3,019,100
No Reheata 2,243,900
Indirect Costs:
Overhead
Interest
Depreciation
Total Indirect Costs
Total Annual Operating Costs
Mills/kwh
C/106 Btu
$/Ton of S Removed
59.4% of 493,368 (Total Labor)
6.125% of 17,379,000
4.17% of 17,379,000
With Reheat
5,101,400
3.24
32.5
217.9
293,100
1,064,500
724,700
2,082,300
aNo Reheat
4,326,200
2.74
27.6
184.7
Basis: 300 Mw (gross peak capacity) existing coal fired plant, 60% load factor, 9,960 Btu/kwhr, 3.
in coal 94.2% S02 removal, average S02 removed - 297 Ibs/min. at 300 Mw (gross peak) load,
on-site solids disposal by trucking after treatment, stack gas reheat 50°F.
-------
ESTIMATED AVERAGE ANNUAL OPERATING COSTS FOR DUAL ALKALI SYSTEM
AT THE LOUISVILLE GAS AND ELECTRIC COMPANY
oo
(1976 Dollars)
Quantity
Direct Costs;
Carbide Lime (30% slurry)
Soda Ash
Fuel Oila
Electricity
Water
Sludge Removal
Maintenance Materials
Labor
Operation
Maintenance
Analysis
Supervision
Total Direct Costs
Indirect Costs:
Overhead
Interest
Depreciation
Total Indirect Costs
58,728 tons
1,912 tons
1,802,808 gals.
16,188,480 kwhrs
126,100 000 gals.
185,280 tons
Unit Cost, $
9.91/ton
65.00/ton
0.32/gal.
0.01/kwhr
0.05/1,000 gals.
1.51/wet ton
2.5% of total materials cost'
26,280 hrs
26,280 hrs
2,080 hrs
2,080 hrs
6.00/hr
6.00/hr
8.00/hr
12.00/hr
Total Costs, $
582,000
124,300
576,900
161,900
6,300
279,800
256,000
157,700
157,700
16,600
25,000
aNo Reheat
55.8% of 356,960 (Total Labor)
6.125%.of 15,950,000
4.17% of 15,950,000
2,344,200
1,767,300
199,200
976,900
665,100
1,841,200
With Reheat aNo Reheat
Total Annual Operating Cost, $
Mills/kwhr
C/106 Btu
$/Ton of S Removed
Basis: 300 Mw (gross peak load) existing coal fired plant
60% load factor
9,960 Btu/kwhr
3.8% S in coal
94.2% S02 removal
Average §02 removal - 297 Ibs/min. at 300 Mw.
On-site solids disposal by trucking after treatment
Stack gas reheat - 50°F
4,185,400
2.65
26.7
178.8
3,608,500
2.29
23.0
154.1
aTotal materials cost of $11.16 million in 1977 dollars is equivalent to $10.24 million in 1976 dolJars,
-------
The delivered cost of the dense soda ash to the silo is estimated to be
$65/ton in 1976 and $78.65/ton in 1979. The fuel oil cost is estimated
at $0.32/gal. in 1976 and $0.43/gal. in 1979. The cost of electricity
for internal use at LG&E is $0.0l/kwhr. The water cost is estimated to
be $0.05/1,000 gals, for pumping river water.
The cost for disposal of filter cake is estimated to be $1.51/ton (wet
basis) in 1976 and $2.01/ton (wet basis) in 1979, assuming 55% solids in
the cake. The disposal cost is estimated based on trucking the filter
cake to the onsite pond. The estimated manpower requirement for the dis-
posal operation is 5 men/shift.
The system operating and maintenance requirements are estimated to be on
the average 3 men/shift for each; the materials cost for maintenance is
estimated to be 2.5% of the total materials cost. The analysis and super-
vision is estimated to be 1 shift/day of effort for each.
The indirect costs include overhead, interest, and depreciation. Current
overhead rate of 55.8% for LG&E is used for the operating cost estimate
in 1976 and the expected overhead rate of 59.4% is used for the operating
cost estimate in the year 1979. The overhead rate is applicable to all
labor charges only. Based on the interest rate of 6.125% on the nontaxable
bonds floated by the LG&E, interest cost is estimated at about $1.06 million
in 1979 and $0.976 million in 1976. Depreciation is estimated based.on the
straight line method using an estimated life of 24 years for the flue gas
desulfurization system. For estimating capital charges in the year 1979,
1977 dollars are used"because LG&E does not capitalize interest cost.
B. GENERALIZED CAPITAL AND OPERATING COSTS
1. Description of Systems
In this section, generalized costs are developed for dual alkali systems
operating in the concentrated mode using lime for regeneration. The costs
are estimated for applications to new 500 and 1,000 megawatt boilers.
Sufficient detail is provided to allow estimates of other size systems and
for comparisons with costs of other S02 removal systems.
The process consists of: an S02 scrubbing system including fans and bypass
ducting with appropriate controls for reheating the wet flue gas with a
bypassed gas stream; a reactor system; a thickener and filter system for
solids separation; filter cake handling equipment and disposal pond; lime
and soda ash receiving, handling and feed preparation equipment, including
lime slaking; and required offsites. Particle removal may be incorporated
in the dual alkali system; however, it is not included here. Flue gas from
the electrostatic precipitator passes through booster fans and then either
to the scrubbers or via a bypass to the stack. The booster fans for the
dual alkali system also serve as induced draft fans for the boiler. In the
S0£ scrubber system, the flue gas passes through the absorption section and
a demister. The wet flue gas is then mixed with bypass gas before being
discharged to the stack.
88
-------
Liquid is recycled in the absorbers to maintain the required L/G ratio and
a bleed stream consisting of spent absorber solution is sent to the reactor
system. Hydrated lime slurry is used to regenerate the spent sodium solu-
tion. The reactor bleed is a slurry containing calcium solids and a re-
generated solution of sodium salts. The slurry is thickened in the thickener
and the thickener underflow slurry is filtered to separate the calcium sulfur
salts. The cake is washed to recover the sodium salts in the entrained solu-
tion and the combined filtrate (recovered liquor and wash water) is returned
to the thickener. The cake is trucked to an onsite disposal pond one mile
from the plant. Clear, regenerated liquor overflows the thickener to the
thickener hold tank from which it is fed to the absorber where it is mixed
with the absorber recycle stream.
Calcined lime is received and stored in silos having 15 days' storage capac-
ity (design basis). The lime is slaked and the slurry stored in a day tank
from which slurry is supplied to the reactor system. Dry soda ash added to
the system to replace sodium value lost in the washed cake, is stored in a
silo having a 15-day capacity. The soda ash is added directly to the process
liquor in a soda ash solution tank from which it is pumped to the thickener.
In order to provide a common basis for comparison of generalized 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. Three cases have
been considered: (1) a new 500 megawatt boiler with S02 removal necessary
to meet current Federal New Source Performance Standards (NSPS); (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.
The design bases for the three cases are shown in Table VIII-7. The systems
are assumed to be modular in nature. There are three scrubber/reactor trains
in the 500 Mw system and six scrubber/reactor trains in the 1,000 Mw system.
As previously indicated, the systems are equipped with flue gas bypass, and
reheat for the wet gas is provided by a bypass gas stream. The S02 removal
efficiencies indicated in Table VIII-7 are the overall S02 removal efficien-
cies. Removal efficiencies for the flue gas passing through the absorber
may be 98% or higher. In the cases where the overall S02 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 cases where overall S02 removal is 90%, the
amount of flue gas bypassed is 8% and the reheat provided is 14°F.
While reheat is provided with bypassed gas, absorbers are designed to handle
100% of the boiler flue gas. Therefore, the 1,000 system designed to meet
NSPS should be able to operate at full load with one absorber shut down,
and the 500 Mw systems should be able to operate at 75-80% load with one
absorber out of operation.
89
-------
TABLE VIII-7
DESIGN BASIS FOR THE GENERALIZED DUAL ALKALI SYSTEM
Boiler Capacity, Mw
Boiler Location
Boiler Status
Coal Heating Value, Btu/lb
Btu/kwhr
Boiler Operating Time, hrs/yr
Coal Burned, tons/yr
S in Coal, %
Cl in Coal, %
SO, in Flue Gas (94% of S in coal), Ib/hr
SO, @ Scrubber Inlet, lb/106 Btu
SO^ @ Stack, lb/106 Btu
SOy Removal
Ibs/hr
tons/yr
Gas Flow Rate @ Scrubber Inlet, acfm
Temperature, °F Scrubber Inlet, acfm
Flue Gas Oxygen, %
Oxidation in Dual Alkali System, %
Boiler I.D. Fan and Scrubber F.D. Fan
Bypass
Flue Gas Bypassed for Reheat, %
Reheat Provided by Bypass Flue Gas, °F
Base Year for Cost Estimation
Scrubber/Reactor Trains
Spare Capacity
Absorbers, %
Filters, %
Pumps , %
Instruments, Necessary for
Operation, %
Turndown to % of capacity
Sludge Disposal
Available CaO in Raw Lime, %
Lime Utilization, %
Lime Silo Capacity, days
Soda Ash Silo Capacity, days
500
Midwest
New
12,000
9,000
7,000
1,312,500
3.5
0.10
24,675
5.48
1.2 (NSPS)
78.1%
19,270
67,450
1,540,000
310
6
10
Common
Yes
20
35
1977
3
25
50
100
100
20
Onsite
92.5
98
15
15
500
Midwest
New
12,000
9,000
7,000
1,312,500
3.5
0.10
24,675
5.48
0.548
90%
22,200
77,725
1,540,000
310
6
10
Common
Yes
8
14
1977
3
9
50
100
100
20
Onsite
92.5
98
15
15
1,000
Midwest
New
12,000
9,000
7,000
2,625,000
3.5
0.10
49,350
5.48
1.2 (NSPS)
7.8.1%
38,540
134,900
3,080,000
310
6
10
Common
Yes
20
35
1977
6
25
25
100
100
20
Onsite
92.5
98
15
15
90
-------
Each system can be operated at 100% load with one reactor system out of
operation. Similarly, each filter can be operated independently of the
others, and the number of filters in operation will therefore depend on
the system load. Due to the modular nature of the filters, 50% spare
filter capacity is provided for the 500 megawatt systems, and 25% spare
capacity is provided for the 1,000 megawatt system. In all cases, one
spare filter is provided.
The location selected to estimate labor costs is the Midwest. The project
is assumed to start in mid-1976 and end in late 1978. Therefore, it is on
the same basis as the dual alkali project at LG&E, and the capital costs
can be assumed to be in September 1977 dollars.
2. Capital Investment
The capital costs for the three cases are shown in Table VIII-8. The costs
are developed in parallel with the LG&E costs. The major equipment cost
was obtained by using the costs shown in Table VIII-3 for the LG&E system
and applying cost factors shown in Table VIII-9. Due to the modular nature
of the system, the sizes of the various pieces of equipment do not vary
significantly, and, therefore, application of cost factors results in
minimal error. The cost of lining was assumed to vary directly with the
cost of tanks, thickener, etc., which are lined. The cost of instruments
was assumed to be proportional to the number of modules. The cost of the
remaining equipment was assumed to vary accordingly to the average size
cost factor.
Common fans are used for the dual alkali system and the boiler. One fan
is provided for each absorber. The fan cost is the incremental cost over
that for the induced draft fan required for the operation of the boilers.
The incremental cost is equal to the difference in the costs of the fans
having pressure drops of 27" WG and 15" WG.
The cost of lime handling and preparation facility includes: storage silos
(eight silos having a total of 15-day storage capacity); two slakers; and
the necessary equipment and instrumentation for conveying dry lime, filter-
ing exhaust air from bins, vibrating silo bottoms, weighing and feeding,
and pumping lime slurry. These costs were obtained from the TVA report by
McGlamery, et al., prepared in 1975, and costs are updated to 1977 dollars.
Other equipment costs include materials for building, land improvements,
insulation, and foundations, and materials required for offsites and
auxiliaries. The costs of chimney liners and breeching, which are included
in the LG&E system because of the retrofit situation, are not included here.
The costs of the onsite sludge disposal ponds shown in Table VIII-8 include
the cost of land, construction of ponds and roads and accessways. The land
required for the sludge pond and the flue gas desulfurization system is
assumed to be 175 and 200 acres for the 500 megawatt systems having 78.1%
and 90% S02 removal efficiency, respectively; and 350 acres for the 1,000
megawatt system. A cost of land equal to $3,000/acre is used. The cost of
91
-------
TABLE VIII-8
ESTIMATED CAPITAL
Boiler Capacity
SO. Removal Efficiency
Direct Costs
Major Equipment Cost
Other Materials Cost
Erection Labor
Total Direct Costs
INVESTMENT FOR GENERALIZED
500 Mw
78.1%
Dollars
9,970,000
3,002,000
6,486,000
19,458,000
DUAL ALKALI
500 Mw
90%
Dollars
10,488,000
3,159,000
6,823,000
20,470,000
SYSTEM
1000 Mw
78.1%
Dollars
17,397,000
5,240,000
11,319,000
33,956,000
Indirect Costs
Engineering Design (9% & 8%) 1,751,000 1,842,000 2,716,000
Construction Field Expense
(11% & 10%) 2,140,000 2,252,000 3,396,000
Contractor's Fee (5%) 973,000 1,024,000 1,698,000
Contingency (10%) 1,946,000 2.047,000 3.396,000
Total Indirect Costs 6,810,000 7,165,000 11,206,000
Total Direct and Indirect Costs 26,268,000 27,635,000 45,162,000
Allowance for Spare Parts (2%
of Equipment Cost) 259,000 273,000 453,000
Land 525,000 600,000 1,050,000
Working Capital 300,000 300,000 500,000
Total Capital Investment3 27,352,000 28,808,000 47,165,000
$/kwa 54.7 57.6 47.2
Basis: New coal fired boiler
3.5% S and 0.1% Cl in coal
Stack gas reheat by bypassing the flue gas
Sludge disposal by trucking to onsite pond (included in
operating costs)
Midwest plant location, project beginning mid-1976 and ending
late 1978, Sept. 1977 dollars ,
Necessary spare parts in storage, working capital included and ,
reasonable spare capacity
Construction labor shortage with accompanying overtime pay
incentive not considered
aThe total capital investment for the above three systems in 1976 dollars
is equivalent to $27,491,000, $29,207,000 and $47,977,000. These costs
reported as $/kw in 1976 dollars are 54.98, 58.41 and 47.98, respectively.
92
-------
TABLE VIII-9
SIZE COST FACTORS USED TO ESTIMATE CAPITAL COSTS
Size Cost Scale Factor3
Absorbers 0.60
Agitators 0.50
Conveyor Belts 0.65
Conveyor Elevator 0.65
Dampers 0.65
Expansion Joints 0.65
Fans 0.68
Feeder Bin 0.58
Fluid Drives 0.68
Reheaters 0.80
Slaker 0.57
Storage Bins 0.68
Tanks 0.68
Thickener Mechanism 0.50
Thickener Shell 0.68
Vacuum Filters 0.65
Weigh Feeder 0.58
aCost factors are applied as follows:
Cost for Size A equipment .Size A.Cost factor
Cost for Size B equipment Size B
93
-------
a general contractor to construct the sludge ponds, the access roads, and
related dirt-moving tasks is estimated at $1.00/cubic yard in 1973 (Rossoff
and Rossi, 1974) and escalated to $1.80/cubic yard for 1977 ($2.64/wet ton).
The ponds are 40-feet deep and are assumed to be clay lined (McGlamery,
1975). Pond construction is assumed to proceed in conjunction with plant
operation and is included as a part of operating costs.
The direct labor cost for erection of the dual alkali equipment is assumed
to be proportional to the cost of equipment plus other materials. Since
the erection labor at LG&E is low (only 32% of the equipment and materials
costs) , a higher value is assumed for generalized cost estimates (50% of
the equipment and materials cost) consistent with the estimates given by
McGlamery, et al., (1975). The erection labor includes labor requirements
for temporary field construction and startup and modifications.
The total direct costs are $19.5-20.5 million for the 500 megawatt systems
and $34.0 million for the 1,000 megawatt system. The engineering design
costs are estimated at 9% of direct cost for the 500 megawatt systems and
8% of direct cost for the 1,000 megawatt system, and construction field
expense is estimated at 11% for the 500 megawatt systems and 10% for a
1,000 megawatt system. The slightly lower relative engineering and field
expenses for the 1,000 megawatt system reflect the modular nature of the
systems and normal capacity factor cost savings.
Contractor's fees and contingency are taken at 5% and 10% of direct costs,
respectively. Other costs are allowance for spare parts at 2% of equipment
and materials cost, and working capital at $300,000 for the ,500 Mw systems
and at $500,000 for 1,000 Mw system.
The total capital costs in September 1977 dollars for the 500 megawatt
systems are about $27.3 and $28.8 million, and about $47.2 million for the
1,000 megawatt system. The costs are equivalent to a range of $47-58/kw.
3. Operating Costs
The operating costs for the generalized systems are estimated in 1976 dollars
and are shown in Tables VIII-10 to VIII-12. The costs are developed in a
manner similar to those for the system at Cane Run Station. The differences
between the LG&E system and generalized system are: (1) commercial lime is
used instead of the carbide lime (the cost of lime delivered in the silo is
assumed to be $40/ton); (2) the cost of electricity is estimated at $0.02/kWh,
instead of $0.01/kwhr used for the LG&E system; (3) the fuel cost is elimi-
nated, since reheat is provided by flue gas bypassed; (4) the labor costs are
assumed to be higher, because of the lower labor rates at the LG&E; and (5)
capital charges are assumed to be 14.6% of the capital investment consistent
with accounting practices in the industry.
94
-------
TABLE VIII-10
ESTIMATED ANNUAL OPERATING COSTS FOR DUAL ALKALI SYSTEM (1976 Dollars)
500 Mw Boiler, SCL Removal to Meet NSPS (78.1% Removal Efficiency)
Annual Quantity
Direct Costs
Raw Materials
Lime
Soda Ash
Subtotal Raw Materials
Conversion Costs
Operating Labor
Analysis
Supervision
Utilities:
Electricity
Water
a
Sludge Disposal
Maintenance
Subtotal Conversion Costs
Subtotal Direct Costs
Indirect Costs
Capital Charges
Overhead
Plant
Adminis trat ive
Subtotal Indirect Costs
Total Annual Operating Cost
Mills/kwh
C/106 Btu
$/ton of Sulfur Removed
Basis: Operating time - 7,000 hrs/yr
9,000 Btu/kwh
3.5% S in coal
65,224 tons
3,039 tons
26,280 hrs
2,080 hrs
2,080 hrs
38,900,000 kwh
420 x 106 gal
227,700 wet tons
5% of direct investment"3
Unit Cost, $
40.00/ton
65.00/ton
8.00/hr
10.00/hr
12.00/hr
0.02/kwh
0.05/1,000 gal
4.25/tona
14.6% of fixed plant investment0
50% of conversion costs less utilities
10% of operating labor
Total Cost, $
2,609,000
198,000
2,807,000
210,200
20,800
25,000
778,000
21,000
967,700
892,600
2.915.300
5,722,300
3,553,200
1,058,200
21,000
4,632,400
10,354,700
2.96
32.9
307
Average S02 removal - 321 Ibs/min
Onsite solids disposal by trucking
Reheat 35°F
3Sludge disposal costs in 1976 dollars (per ton of wet sludge) = $2.75 for pond construction (including
engineering, permits, contingency, etc. @ 14%) + $1.50 for sludge transport and placement.
Direct investment of $19,458,000 in 1977 dollars is equivalent to $17,851,000 in 1976 dollars.
°Fixed plant investment of $26,527,000 in 1977 dollars is equivalent to $24,337,000 in .1976 dollars.
-------
TABLE VIII-11
ESTIMATED ANNUAL OPERATING COSTS FOR DUAL ALKALI SYSTEM (1976 Dollars)
500 Mw Boiler, 90% S02 Removal
Annual Quantity
vD
Direct Costs
Raw Materials
Lime
Soda Ash
Subtotal Raw Materials
Conversion Costs
Operating Labor
Analysis
Supervision
Utilities:
Electricity
Water
Sludge Disposal
Maintenance
Subtotal Conversion Costs
Subtotal Direct Costs
Indirect Costs
Capital Charges
Overhead
Plant
Administrative
Subtotal Indirect Costs
Total Annual Operating Cost
Mills/kwh
C/106 Btu
$/ton of Sulfur Removed
Basis: Operating time - 7,000 hrs/yr
9,000 Btu/kwh
3.5% S in coal
75,550 tons
3,368 tons
26,280 hrs
2,080 hrs
2,080 hrs
38.9 x 106 kwh
420 x 106 gals
263,750 wet tons
5% of direct investment°
Unit Cost, $
40.00/ton
65.OO/ton
8.00/hr
10.00/hr
12.00/hr
0.02/kwh
0.05/1,000 gal
4.25/wet tona
14.6% of fixed plant investment0
50% of conversion costs less utilities
10% of operating labor
Total Cost. $
3,022,000
218.900
3,240,900
210,200
20,800
25,000
778,000
21,000
1,120,900
939.000
3.114,900
6,355,800
3,738,200
1,158,000
21.000
4,917.200
11,273,000
3.22
35.8
290
Average S02 removal - 370 Ibs/min
Onsite solids disposal by trucking
Reheat 18°F
Sludge disposal costs in 1976 dollars (per ton of wet sludge) = $2.75 for pond construction
, (including engineering, permits, contingency, etc. @ 14%) + $1.50 for sludge transport and placement.
Direct investment of $20,470,000 in 1977 dollars is equvalent to $18,780,000 in 1976 dollars.
C?ixed plant investment of $27,908,000 in 1977 dollars is equivalent to $25,604,000 in 1976 dollars.
-------
JSJL.JS -v x x j:— 3. a
ESTIMATED ANNUAL OPERATING COSTS FOR DUAL ALKALI SYSTEM (1976 Dollars)
1,000 Mw Boiler, S02 Removal to Meet NSPS (78.1% Removal Efficiency)
Annual Quantity
Unit Cost, $
Total Cost. $
Direct Costs
Raw Materials
Lime
Soda Ash
Subtotal Raw Materials
Conversion Costs
Operating Labor
Analysis
Supervision
Utilities:
Electricity
Water
Sludge Disposal
Maintenance
Subtotal Conversion Costs
Subtotal Direct Costs
Indirect Costs
Capital Charges
Overhead
Plant
Administrative
Subtotal Indirect Costs
Total Annual Operating Costs
Mills/kwh
-------
The average labor is estimated at three operators/shift and four maintenance
personnel/shift for the 500 megawatt systems and five operators/shift and
six maintenance personnel/shift for the 1,000 megawatt system. It is ex-
pected that maintenance will be heavy on weekdays and light on evenings,
nights and weekends. In addition, the cost of one analyst and one super-
visor is included. The plant overhead rate is estimated to be 50% of the
conversion costs less utilities. Capital charges, including interest,
depreciation, taxes, insurance, and return on investment, are assumed to
be 14.6% of the total capital investment.
The annual operating costs are $10.4 and $11.3 million for the 500 megawatt
systems and $19.1 million for the 1,000 megawatt system. These costs are
equivalent to a range of 30
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IX. REFERENCES
1. Alrco Catalog, Technical Data and Process Bulletin on Carbide Lime,
April 1969.
2. LaMantia, C.R., et al. , "Final Report: Dual Alkali Test and Evalua-
tion Program," Volumes I-III, EPA Contract 600/7-77-050a,b ,c, May 1977.
3. McGlamery, G.G., et al., "Detailed Cost Estimates for Advanced
Effluent Desulfurization Process," EPA Contract 600/2-75-006,
January 1975.
4. Guthrie, K.M., "Capital Cost Estimating," Chemical Engineering,
Volume 76, No. 6., March 24, 1969, pp. 114-142.
5. Rossoff, J. and Rossi, R.C., "Disposal of By-products from Non-regenerable
Flue Gas Desulfurization Systems," Initial Report, EPA Contract
650/2-74-037A.
99
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X. GLOSSARY
Active Sodium - Sodium associated with anions involved in S02 absorption
reactions and includes sulfite, bisulfite, hydroxide and carbonate/
bicarbonate. Total active sodium concentration is calculated as
follows:
[Na+]active = 2 x ([Na2SO ] + [Na CO ]) = [NaHSO ] + [NaOH] +
Available Alkali - The percentage of the calcium hydroxide in the raw
hydrated lime, or in the insoluble solids in the carbide lime slurry.
Calcium Utilization - The percentage of the calcium in the lime or limestone
which is present in the solid product as a calcium-sulfur salt.
Calcium utilization is defined as :
mo Is (CaSO + CaSO ) generated
Calcium Utilization = - - . _ — ~ - x 100%
mol Ca fed
Concentrated Dual Alkali Modes - Modes of operation of the dual alkali
process in which regeneration reactions produce solids containing
CaSC-3 • 1/2 H20 or a mixed crystal containing calcium sulfite and
calcium sulfate hemihydrates , but not containing gypsum. Active
sodium concentrations are usually higher than 0.15M Na+ in concen-
trated mode solutions.
Dilute Dual Alkali Modes - Modes of operation of the dual alkali process
in which regeneration reactions produce solids containing gypsum
(CaS04 • 2 H20) . Active sodium concentrations are usually lower
than 0.15M Na+ in dilute mode solutions.
Sulfate Formation - The oxidation of sulfur (IV)-sulfite and bisulfate.
The level of sulfate formation relative to S02 absorption is given
by:
„ -, f T, . mols S(IV) oxidized
Sulfate Formation = mol removed
Sulfate Precipitation - The formation of CaS04 • XI^O insoluble solids.
The level of sulfate precipitation in the overall scheme is given
by the ratio of calcium sulfate to the total calcium-sulfur salts
produced:
mols CaSO produced
Sulfate Precipitation = mols (CaS03 + CaS04) produced
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TECHNICAL REPORT DATA
(Please read Instructions on llie reverse before
1 REPORT NO.
EPA-600/7-78-01Q
2.
,3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE project Manual for Full-Scale Dual-
alkali Demonstration at Louisville Gas and Electric
lo. —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.Luit, and **C.R.
LaMaatia
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING OROANIZATION NAME AND ADDRESS
Louisville Gas and Electric Company
311 West Chestnut Street
Loaisville, 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
Project manual; 10/76-12/77
14. SPONSORING AGENCY CODE
EPA/600/13
is.SUPPLEMENTARY NOTES IERL-RTP project officer is Norman Kaplan,MD-61, 919/541-2556.
(*)Combustion Equipment Associates. (**)A. D. Little, Inc.
16. ABSTRACT
The report is the project manual for the dual-alkali system, designed by
Combustion Equipment Associates, Inc./Arthur D. Little, Inc. and being installed
to control SO2 emissions from Loaisville Gas and Electric Company's Cane Run Unit
No. 8 boiler. The project consists of four phases: I--preliminary design and cost
estimates; II--engineering design, construction, and mechanical testing; in--startup
and performance testing; and IV--1 year operation and testing. Developed as part of
Phase I, the project manual includes a detailed description of the dual-alkali process
chemistry, the design of the demonstration system at LG and E, material and energy
balances for the system, specifications of major equipment items and offsites, and
capital and operating costs. Costs for this application have been generalized for new
applications on 500 and 1000 MW high-sulfur coal-fired boilers.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
13B
07A
07D
07B
21D
13A
Air Pollution
Scrubbers
Alkalies
Sulfur Dioxide
Coil
Boilers
Chemistry
Operating Costs
Capitalized Costs
Air Pollution Control
Stationary Sources
Dual Alkali System
14A
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF I
11R
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
103
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