CD A U.S. Environmental Protection Agency Industrial Environmental Research EPA-600/7-78'031 b
•"•• •• Off ice of Research and Development Laboratory __ . -|*%7Q
Research Triangle Park, North Carolina 27711 MSTCn iSjf O
THE EFFECT OF FLUE GAS
DESULFURIZATION
AVAILABILITY ON ELECTRIC
UTILITIES
Volume II. Technical Report
Interagency
Energy-Environment
Research and Development
Program Report
-------
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.
-------
EPA-600/7-78-031b
March 1978
THE EFFECT OF FLUE GAS
DESULFURIZATION AVAILABILITY ON
ELECTRIC UTILITIES
Volume II. Technical Report
by
R. D. Delleney
Radian Corporation
P.O. Box 9948
Austin, Texas 78766
Contract No. 68-02-2608
Task No. 7
Program Element No. EHE624
EPA Project Officers:
John E. Williams and Kenneth R. Durkee
Industrial Environmental Research Laboratory Emission Standards and Engineering Division
Office of Energy, Minerals, and Industry Office of Air Quality Planning and Standards
Research Triangle Park, N.C. 27711 Research Triangle Park, N.C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
and Office of Air and Waste Management
Washington, D.C. 20460
-------
TABLE OF CONTENTS
PAGE
TABLE OF CONTENTS- ii-iii
LIST OF TABLES iv-v
LIST OF FIGURES vi
1.0 INTRODUCTION-- 1
1.1 Program Objectives 2
1.2 Definition of Important Terms- 3
1.3 Approach 4
2.0 RESULTS AND CONCLUSIONS 6
2.1 Results 6
2.2 Conclusions 8
2.3 Summary 10
3.0 AVAILABILITY ASSESSMENT 11
3.1 Descriptions of Generating Unit Components
and Systems 11
3.1.1 Electric Generating Unit Component Descriptions- 11
3.1.1.1 Utility Boilers 14
3.1.1.2 Turbines 15
3.1.1.3 Generators 15
3.1.1.4 Condensers- 16
3.1.1.5 Other Components 16
3.1.2 Description of Utility Systems 17
3.2 Utility and Flue Gas Desulfurization Operating
Data — 20
3.2.1 Utility Operating Data 20
3.2.2 Flue Gas Desulfurization Operating Data 22
3.3 Analysis of Flue Gas Desulfurization
Availability 45
-------
TABLE OF CONTENTS (Continued)
PAGE
3.4 Effect of Flue Gas Desulfurization Availability
on an Individual Utility Generating Station 52
3.5 Effect of Flue Gas Desulfurization Availability
on Generating Systems- 56
4.0 IMPROVEMENTS TO FLUE GAS DESULFURIZATION
AVAILABILITY 64
4.1 Operating Experience for Existing Systems 64
4.2 Flue Gas Desulfurization Component Failures 68
4.3 Measures to Improve Flue Gas Desulfurization
Availability 69
APPENDIX A 73
APPENDIX B-- 81
BIBLIOGRAPHY 87
111
-------
LIST OF TABLES
TABLE PAGE
3-1 Percentage Breakdown of System Generating
By Primary Fuel and Equipment--1985 19
3-2 Operating Data for Mature Coal-Fired Units
(390-599 MW) 23
3-3 Operating Data for All Fossil-Fired Units
(Gas, Oil, Coal) 1965 - 1974 (390-599 MW,
111 Units) 24
3-4 FGD Operating Data Concerning Availability
and Utilization-- 27
3-5 FGD Module Performance Data - Average Values 28
3-6 Operating Characteristics of the Will County
Unit No. 1 Boiler-Scrubber System 29
3-7 Operating Characteristics of the La Cygne
Boiler-Scrubber System 30
3-8 Operating Characteristics of the Phillips
Boiler-Scrubber System 31
3-9 Operating Characteristics of the Cholla
Boiler-Scrubber System 32
3-10 Operating Characteristics of the Green River
Boiler'-Scrubber System 33
3-11 Operating Characteristics of the Sherburne
County No. 1 Boiler-Scrubber System 34
3-12 Operating Characteristics of the Bruce
Mansfield No. 1 Boiler-Scrubber System 35
3-13 The Initial Availability of Seven FGD Systems 44
3-14 Factors for Consideration in FGD Availability
Analysis 46
3-15 Estimated Effect of Flue Gas Desulfurization
Unit Availability on 1985 Systems 59
3-16 New Coal Generating Capacity in Each System -
1985----- 60
IV
-------
LIST OF TABLES (Continued)
TABLE PAGE
3-17 Summer Peak Loads - 1985 Projections by NERC 61
3-18 Estimate of Megawatts of Additional Generating
Capacity Required to Offset the Effect of FGD
in 1988 and 1998------ 63
4-1 Summary of Problems, Solutions, and Maintenance
at Existing FGD Systems 65
v
-------
LIST OF FIGUEES
FIGURE PAGE
3-1 Simplified flow diagram for an electric
power generating station- 13
3-2 Location of the nine Reliability Councils
(Systems 1 through 9) 18
3-3 Will County No. 1 FGD average modular
availability--^ *• 37
3-4 Phillips FGD average modular availability
(average all modules) 38
3-5 La Cygne FGD average modular availability
(average all modules)-^ 39
3-6 Green River FGD modular availability- 40
3-7 Sherburne County No. 1 FGD average modular
availability (average all modules) 41
3-8 Bruce Mansfield No. 1 FGD average modular
availability (average all modules) 42
3-9 Effect of flue gas desulfurization unit
availability on individual generating station
availability at maximum load 54
VI
-------
1.0 INTRODUCTION
This report presents the results of work performed by
Radian Corporation of Austin, Texas, for the Office of Air Qual-
ity Planning and Standards and the Industrial Environmental Re-
search Laboratory of the United States Environmental Protection
Agency. The purpose of this project was to assess the impact of
flue gas desulfurization (FGD) system availability on the ability
of individual coal-fired generating stations* and of generating
systems** to meet consumer demands. Operating information on
utilities and FGD systems from all known sources was analyzed with
the major emphasis on the Edison Electric Institute (EEI) data
base, PEDCo Environmental's Summary Report--Flue Gas Desulfurization
Systems, and contacting utilities with operating FGD systems of
interest to this study.
/
This project was originally to consider the subject of
reliability and availability. However, during the course of this
investigation it became evident that reliability was not a useful
measure of the ability of an individual unit or a generating sys-
tem to respond to consumer demands for electric power. Further-
more, the term "reliability" was not uniformly defined over the
data bases used in this study. As a result, this study is con-
cerned almost exclusively with the quantification and assessment
of availability, which was defined in a uniform manner.
Almost all commercial applications of flue gas desul-
furization on coal-fired boilers use either the Lime Process or
the Limestone Process. Of the other processes of interest in
this study, the Magnesium Oxide and Wellman-Lord Processes are
*Single steam generating plant
**Interconnected pool composed of a mix of numerous generating
plants
-------
each used at one site while the Double Alkali Process has not
been commercially applied to coal-fired boilers. As a result,
this study concentrates on the operating experience and data
for Lime/Limestone Processes.
At present, many of the measures that lead to a more
reliable FGD system include an economic penalty. An assessment
of these economic penalties was beyond the scope of this study
and is not addressed in this document. As operating experience
and technology developments solve some of the problems, these
economic penalties may be reduced or eliminated.
1.1 Program Objectives
The objectives of this program were identified in the
Work Plan as follows:
To assess the effect of flue gas desulfurization
(FGD) systems on the reliability/availability
of electric utility power generation. A compari-
son of the reliability/availability of existing
FGD units with power plant generating equipment
was included.
• To define and assess measures which have been or
can be used to maintain or improve FGD unit
reliability/availability. Emphasis was placed
on operating experience at specific installations.
To report the results of this study in support
of EPA's review of the new source performance
standards for coal-fired steam generators.
-------
1.2 Definition of Important Terms
Available - The status of a unit or major piece
of equipment which is capable of service, whether
or not it is actually in service.
Availability - The fraction of time that a unit
or major piece of equipment is capable of service,
whether or not it is actually in service.
Forced Outage - The occurrence of a component
failure or other condition which requires that
the unit be removed from service immediately or
up to and including the very next weekend.
Mean Time Between Full Forced Outage - The average
time between each occurrence of a component failure
or other condition which requires that the unit be
removed from service immediately or up to and in-
cluding the very next weekend. The average time
is calculated by dividing the service hours by the
number of forced outages.
Reliability - The probability that a device will
not fail or that service is continuous in a
specified time period. The term reliability
is not defined as a standard in the utility
industry. The Mean Time Between Full Forced
Outage (MTBFFO) and Loss-of-Load Probability
(LOLP) are sometimes used as measures of
reliability. The MTBFFO and LOLP can be
used to calculate numerical values for
reliability.
-------
These terms are commonly used in an examination of the
ability of a utility to meet consumer demand. Where possible
these terms are in accordance with the Edison Electric Institute
(EEI) standard definitions. A complete list of the definitions
used by the two primary sources of data for this study, EEI and
PEDCo Environmental Inc., is presented in Appendix A.
1.3 Approach
System reliability has been frequently used as an
important measure of the performance of that system. The con-
cept of a system being reliable or dependable is relatively
straightforward. However, the quantification and application
of this concept is relatively complex and is often poorly under-
stood. A reader usually has a preconceived idea of what reliable
or reliability means. These preconceived ideas often inhibit
communication of the results of a system reliability analysis.
\
As an exmple, assume a system has a reliability of
99 percent for a 1000 hour time period. This statement means
there is a probability of 99 percent that the system will oper-
ate for 1000 hours without a failure. This statement of reli-
ability has three elements: (1) a quality of performance,
(2) the performance is expected over a period of time, and
(3) reliability is expressed as a probability. No information
is provided as to how long the system does not operate when a
failure occurs. The statement of 99 percent reliability for
1000 hours does not mean that the system will operate 990 hours
out of every 1000 hours. Availability, on the other hand, pro-
vides information as to how often a system fails and how long it
does not operate as a result of a failure. Availability data
thus combine the effects of reliability, maintenance, and
repair time and are usually expressed as a percentage.
-------
Many different organizations reporting reliability/
availability type data use slightly different definitions for
these terms. PEDCo Environmental's measure of reliability in
their FGD status reports is not comparable to the parameters
used by EEI to quantify reliability. Therefore, an evaluation
based on the quantification of "reliabilities" is not possible
in this study. However, the definitions of "availability" used
by EEI and PEDCo are essentially the same. As a consequence of
the preceding discussion, availability was determined to be the
most useful measure of the ability of an individual station or
a generating system to respond to consumer demand.
The steps taken in the completion of this project were
Collect and analyze all available data for utility
and flue gas desulfurization systems.
Determine the effect of FGD units on the avail-
ability of individual generating stations and
generating systems. It was assumed that the
generating station cannot bypass the FGD unit.
The FGD unit availabilities are at the full load
operation of the generating station unless speci-
fied otherwise.
Survey of existing FGD units to determine how
they are meeting or can meet necessary avail-
ability levels.
Document the operating experience at specific
FGD installations.
Define and assess measures that have resulted
or can result in high levels of FGD unit
availability.
-------
The following items should be taken into account to
more completely evaluate the effect of FGD availability on
power systems:
• Unit use (base load, intermediate load, etc.)
Unit interactions
Coincident outages
• Partial outages (generating unit and scrubber)
FGD unit configurations
• Network configurations
Reserve policies
In particular, generating unit use and incidence of coincident
full and/or partial outage will strongly influence the effect
of FGD on system availability and adequacy. Also, in assessing
the effect of FGD on power systems, it is important to recognize
the requirement for excess generating capability above the maxi-
mum demand. Reserve policies, interconnections, and network
state would influence whether or not power was available to
offset these potential effects of FGD. Such an assessment was
beyond the scope of this study.
2.0 RESULTS AND CONCLUSIONS
The effect of FGD availability on power generation
was assessed. The results and conclusions of this study are
given in this section.
2.1 Results
The results of this project are:
1) Mature coal-fired generating unit components
(i.e. boilers, turbines, etc.) are reported to
have an average availability between 80 and 97
-------
percent. Mature coal-fired generating units are
reported to have an average availability between
70 and 77 percent.
2) The seven FGD units emphasized in this study
have reported average modular availabilities
between 44 and 95 percent. Five of these
have reported average modular availabilities
above 70 percent.
3) An individual base loaded generating station
with an FGD unit cannot meet consumer demand
without FGD module sparing.
4) Generating systems with FGD on new coal-fired
plants can meet a 1985 consumer demand equal
to about 89 percent of the capability without
FGD based on modeling the new coal capacity
in a system as a single generating station
with one FGD unit composed of one module.
However, the systems cannot maintain the
excess generating capability above maximum
demand that is required to insure the ability
to meet demand. Additional generating units
or improvements to the FGD unit availability
-would have to offset the reduction in gener-
ating capability due to FGD units.
5) The availability of existing FGD units is
maintained by various combinations of the
following: (a) use of trained operating
and maintenance crews, (b) bringing modules
-------
off-line each night for maintenance, and
(c) inclusion of spare modules.
6) FGD unit components subject to high
failure rates include slurry pumps,
packing gland water systems, nozzles,
valves, fans, mist eliminators, and
rcheaters.
7) Maintenance methods, operating tech-
niques, and design concepts were
identified that can or have been used
to produce high FGD availabilities.
8) A preliminary and rudimentary examination
of the relationship between the effect of
FGD and load duration curves was completed,
2. 2 Conelus ions
The conclusions for this study are:
1) FGD unit availability is a function of
the modular availability, the total
number of modules and the number of
spare modules. The FGD unit avail-
ability is associated with a specific
operating load (percent of capacity)
for the generating unit. The number
of effective spare modules varies
with the operating load since all
modules are not necessarily required
for loads of less than 100 percent
of capacity.
8
-------
2) The availability of FGD units has
a significant impact on the ability
of an individual generating station
and a generating system to meet
consumer demand. The reduction in
generating capability for a single
station varies depending on the FGD
unit availability. For a system the
effect of FGD largely depends on the
fraction of new coal plants in that
system. These reductions in capa-
bility must be offset by adding
generating units or by improving
the availability of the FGD units.
3) Use of spare FGD modules dramatically
improves total unit availability.
4) Significant progress has been made in
the last few years in solving the
problems experienced by the existing
FGD units. The problems which present
the greatest challenge to FGD avail-
ability are corrosion, erosion, deposits,
unstable chemistry, and instrumentation.
5) A substantial committment on the part of
a utility to the operation and maintenance
of an FGD unit is required to maintain
high levels of FGD unit availability.
-------
2.3 Summary
The effect of the availability of flue gas desulfuri-
zation (FGD) on a generating unit and system was assessed. The
impact on the ability of an individual generating station or a
generating system to meet consumer demand was the parameter used
to measure the effect of FGD availability. Operating data for
generating and FGD units was gathered and analyzed as input to
this assessment. Existing FGD units were also surveyed to deter-
mine how they are meeting or can meet necessary availability levels
The problems encountered and solved by operating FGD
units were then documented and examined. Unit components with
high failure rates were identified and methods to enhance their
availability evaluated. Finally, maintenance methods, operating
techniques, and design concepts which have or can be used to
produce high levels of FGD unit availability were defined and
assessed.
10
-------
3.0 AVAILABILITY ASSESSMENT
An assessment of the effect of flue gas desulfurization
units on the availability of individual utility generating sta-
tions and utility systems was performed. The effect was quanti-
fied by determining the change in the ability of an individual
utility or utility system to meet consumer demand. This section
of the report includes a description of electric generating com-
ponents and generating systems (Section 3.1), a presentation of
electric generating and flue gas desulfurization operating data
(Section 3.2), an analysis of flue gas desulfurization availabil-
ity (Section 3.3), and an estimation of the effect of FGD avail-
ability on an individual generating station (Section 3.4) and on
generating systems (Section 3.5).
3.1 Descriptions of Generating Unit Components and Systems
In this section, brief descriptions are presented of
the electric generating unit components that were evaluated
during this study. These component descriptions are included
in order to provide an understanding of the function of each
of the equipment items and to illustrate how each item fits
into the overall electric generating unit or plant. The equip-
ment is grouped into components following the guidelines of the
Edison Electric Institute (ED-060). The systems described are
representative of the varying mixes of power plant generating
types (i.e., steam boilers, gas turbines, nuclear plants, etc.)
found in typical utilities in the United States.
3.1.1 Electric Generating Unit Component Descriptions
The five major utility equipment component groupings
of interest to this study are boilers, turbines, generators,
11
-------
condensers, and others (boiler feed water pumps, etc.)- These
items are currently used by virtually every utility in the
United States.
There are two basic reasons for selecting these
equipment items for study. First, each is generally accepted
by the electric power utility industry as being commercially
demonstrated technology. Second, data have been recorded and
in many cases are available concerning the reliability, avail-
ability, and failure rates of each of these equipment items.
Nuclear unit operating data are not included in this
study because nuclear units represent a portion of the electric
utility industry in which FGD systems will never be used.
Thus a comparison of nuclear unit with FGD system operating
parameters will not clarify any portion of the present program
objectives. Additionally, the nuclear unit operating data are
significantly affected by regulatory constraints. These
constraints have no counterpart for non-nuclear units or FGD
systems within the electric utility industry.
Modern electric power generating stations are com-
plex units which employ sophisticated mechanical, metallurgi-
cal, and electrical technology. Figure 3-1 presents a highly
simplified flow scheme which identifies the general equipment
categories important in the study. No attempt is made here
to distinguish between boiler types, equipment manufacturers,
or equipment design or quality. The primary reason for this
is because most of the reliability/availability data recorded
are also in general categories.
The three major flowpaths shown in Figure 3-1 are
water/steam, combustion gas, and electrical. Many design con-
straints are placed on the equipment which handle each of
12
-------
©-Q—<«
-------
these flows. Exceeding design limitations, insufficient
design safety, and metallurgical flaws can lead to premature
operational failure of any equipment item. In cases where
more than one stream is handled in one piece of equipment,
e.g., boilers and electrostatic precipitators, equipment
failures due to both streams have occurred. The following
five sections briefly describe the major components mentioned
above.
3.1.1.1 Utility Boilers
A modern water tube drum-type boiler consists of steel
drums or headers connected by a number of steel tubes, and
arranged in a furnace so that (1) radiant heat from the fire-
ball is transferred to the tubes, and (2) the hot gases also
pass through an additional bank of tubes on their way to the
stack. Hot combustion gases flow around the tubes, transferring
their heat to the water or steam within the tubes. The steam in
turn is collected and may be heated to a temperature well above
the saturation temperature (superheated) before being used. In
other separate portions of the boiler, steam which has been
partially expanded through a turbine may be reheated to a tempera-
ture very near the original superheat temperature.
As steam flows out of the boiler it becomes necessary
to replenish the water that was evaporated. For this reason
feed pumps are necessary to supply water to the boiler. These
pumps must operate at a pressure high enough to overcome the
pressure in the boiler. In the operation of any boiler, it is
essential always to keep water in the boiler. If the boiler
should run low on water, the tube metal would become hot,
soften, and rupture. At the same time, the boiler should not
be filled to a point where there is insufficient room for the
steam to collect. Typically, level control devices or steam
14
-------
and water flow devices are used to insure that the amount of
water entering the boiler equals the amount of steam leaving.
Boiler feed water is usually heated before being de-
livered to the boiler. A steam preheater (using low pressure
exhaust steam) and an economizer are used to do this. An eco-
nomizer is a separate bank of boiler tubes through which the
feed water passes before it enters the main boiler tubes. This
bank of tubes is usually placed in the convective section of the
boiler ahead of the air preheater to absorb some additional heat
from the combustion gases and thus improve the economy of the boiler,
3.1.1.2 Turbines
Turbines provide a means for converting energy in
the steam into useful shaft work. Simply stated, a turbine
is a shaft mounted on two or more sets of bearings. Attached
to the shaft are a set of wheels or stages which have blades
attached to the rim. These blades, or buckets as they are
commonly called, are shaped such that the passage of steam
forces the wheel to turn thus turning the shaft. Stationary
nozzles set between the rotating stages direct the steam so
that it continually drives the buckets.
Turbines are designed to turn at a fixed speed and
are equipped with automatic controls to accomplish this. The
rotating turbine shaft is coupled to an electric generator
rotor which is the means for converting shaft work into
electricity.
3.1.1.3 Generators
A generator consists of wire coils turning through
the lines of flux from a magnet. As the wire coil interrupts
15
-------
the magnetic flux lines a voltage is produced in the wire,
thus generating electricity. A central station generator
consists principally of a magnetic circuit, d-c field winding,
a-c armature, and mechanical structure including cooling and
lubricating systems. The steam turbine, coupled to the
generator rotor, provides the shaft power necessary to turn
either the coil through the magnetic flux or to turn the mag-
net within the coil.
3.1.1.4 Condensers
The steam exiting the turbine is condensed to create
a vacuum at the turbine exhaust. The efficiency of the tur-
bine is improved by allowing it to exhaust into a vacuum
rather than to the atmosphere. The condensed steam is then
returned to the boiler as feed water.
The condenser uses cooling water passing through a
bank of tubes to cool and condense the turbine exhaust steam.
The steam condensate collects in a "hot well" which serves as
a reservoir for a pump returning condensate to the boiler feed
water heaters and boiler feed pump.
3.1.1.5 Other Components
Some of the major items included in this classifica-
tion are the boiler feedwater pumps, pump drives, feedwater
heaters, and water treatment facilities. The boiler feedwater
pumps supply water to the boiler to replace the water converted
to steam. Large high pressure pumps are required due to the
quantity of water required and the pressure in the boiler that
must be overcome. These pumps are typically driven by steam tur-
bines. The feedwater heaters take steam from various points on
the turbines to heat the boiler feedwater. The steam is usually
16
-------
injected directly into the feedwater. Water treatment is
necessary to provide makeup water of an adequate quality.
Impurities in the water are deposited in the boiler when
steam is generated. Makeup water is usually a very small
percentage of the total feed to the boiler.
3.1.2 Description of Utility Systems
Systems of varying mixes of power plant generating
types were identified. The 1985 projections by the National
Electric Reliability Council (NA-325) were the basis for the
mix of generating types specified in these systems. The
National Electric Reliability Council (NERC) consists of
nine Regional Reliability Councils and encompasses essentially
all of the power systems of the United States. A map of the
U.S. indicating the geographical bounds for the nine Reliability
Councils is presented in Figure 3-2. The ten systems shown in
Table 3-1 represent the projected generation mixes for the nine
regional councils and the total projected mix for the nation
for 1985.
A varying mix of generating equipment and fuels is
presented. The 1985 system projections (Table 3-1) range from
predominantly gas-fired or oil-fired steam turbine systems
(Systems 2 and 6); to a primarily coal-fired steam turbine
system (System 1); to a predominantly hydro system (System 9);
to a more balanced system (System 3).
The column titled New Coal under Fossil-Fired Steam
Turbines is of particular interest. These numbers state the
percentage of total capacity resulting from coal-fired steam
turbines completed between 1976 and 1985. Some of this New
17
-------
Figure 3-2. Location of the nine Reliability Councils (Systems 1 through 9).
Source: NA-325
-------
I-1
VO
TABLE 3-1. PERCENTAGE BREAKDOWN OF SYSTEM GENERATING CAPABILITY
BY PRIMARY FUEL AND EQUIPMENT--1985
Fossil-Fired
System
Number New Coal
1
2
3
4
5
6
7
8
9
10
18.
33.
3.
14.
29.
4.
11.
30.
13.
(Nation)16.
4
6
5
5
2
4
7
0
5
0
- By Type of Primary Fuel
Steam Turbines
Total
72.
37.
26.
52.
58.
9.
42.
36.
24.
40.
Coal
5
8
4
7
7
9
0
1
5
1
Oil Gas
5.
10.
22.
6.
2.
37.
11.
11.
16.
13.
0 0.5
6 38.1
3 0
7 0.2
0 0.5
7 0
7 0
4 28.4
6 1.2
8 5.7
Combust.
Turb.
3.4
1.8
14.0
8.1
8.9
8.4
6.5
5.5
5.1
6.4
Comb.
Cycle
0.3
1.3
0.4
0
0.2
0.9
0.6
1.6
2.1
0.9
Nuclear
14.7
8.5
31.5
30.5
21.1
30.0
30.4
13.5
14.9
21.8
Hydro
0.8
0.5
1.5
0.9
8.6
7.8
5.8
3.2
30.6
8.4
Pump
Storage
and
Other
2.8
1.4
3.9
0.9
0
5.3
3.0
0.3
5.0
2.9
Source: NA-325
-------
Coal capacity will come under EPA's New Source Performance
Standards. For this study, all of this New Coal generating
capacity is assumed to be required to use flue gas desulfuri-
zation as the method of S02 control. As a result, the effect
of FGD on each system follows directly from its effect on the
New Coal steam generators in that system.
3.2 Utility and Flue Gas Desulfurization Operating Data
A significant disparity exists between the quality
and quantity of data available for utility systems as compared
to flue gas desulfurization systems. Detailed performance data
for equipment used in the electric utility industry have been
collected on a continuing basis since 1965. There are at least
four data banks for utility systems in the United States. Per-
formance data for operating FGD systems, however, is sparse.
At persent the PEDCo Summary Report—Flue Gas Desulfurization
Systems (PE-259) is the primary source. The PEDCo report,
which is prepared under EPA contract, provides a continual
update of the status and performance of operational FGD systems.
In addition, the report summarizes the status of FGD systems in
the construction or planning stages. The PEDCo report which is
primarily a status report does not contain the detailed data
which are available for the utility industry.
3.2.1 Utility Operating Data
There are four primary systems in operation in the
United States which collect and report utility system perfor-
mance data. These systems are the Edison Electric Institute
(EEI) Prime Movers Committee; the Nuclear Plant Reliability
Data System (NPRDS) under the direction of the American National
20
-------
Standards Institute (ANSI) subcommittee N18-20; the Gray Book I,
issued by the Nuclear Regulatory Commission (NRC Gray Book);
and the Federal Power Commission (FPC). The FPC publishes
special reports on many different facets of the electric utility
industry but does not issue routine reports on equipment com-
ponents. The NRC Gray Book publishes performance data on the
reactor systems for nuclear plants.
The NPRDS System is concerned with reliability-type
data for the components in the nuclear safety systems of nuclear
central station electric units. The EEI data is the only major
data bank which is directly applicable to this study (i.e.,
major utility equipment performance data). These data are
published in the EEI Prime Movers Committee Reports (ED-043, ED-059)
In addition to the four data sources previously men-
tioned, equipment performance data are scattered throughout the
open literature, in many different journals, and in government
reports. Most notable of the latter is WASH 1400, Reactor
Safety Study—An Assessment of Accident Risks in U.S. Commercial
Nuclear Power Plants (US-391). Additional data are recorded
and maintained by many individual utilities, and by insurance
companies. Much of the data in the open literature were not
applicable to this study because of the short time spans
reported or because of incomplete data sets. Insurance company
data cover only major outages above the policy deductibles
and do not contain operating time, and thus are not particularly
useful to this study.
The EEI reports were found to be the best sources of
data that are relevant to this study. Particularly useful was
a special report issued in October 1976 on mature* fossil units
* A mature unit has completed the breakin period and has operated
long enough to have a known incidence of outage.
21
-------
categorized by fuel (ED-059), Data from this report are pre-
sented in Table 3-2. Other EEI reports combine all fossil-fired
units as one category preventing any distinction between coal-
fired and gas- and oil-fired units. Data from the most recent
summary report are shown in Table 3-3. The major differences be-
tween the coal-fired and other fossil-fired units are for the
boiler and the entire unit (including the boiler). The other
components which do not vary with the type of fuel have compara-
ble values for availability. Coal-fired units require more
equipment for fuel preparation and transporting and for ash
disposal. They also experience more erosion and corrosion in
the boiler and in equipment in the flue gas path due to the ash
and sulfur in the coal.
The range of component availabilities for coal-fired
units is of primary interest. Average availabilities vary
from a low of about 80 percent for boilers to a high of about
97 percent for condensers. The average availability of a coal-
fired generating unit which results from the combined availabil-
ities of the components varies from about 70 to 77 percent.
These ranges are important in the comparison of utility compon-
ent and unit operation with that of flue gas desulfurization
units.
3.2.2 Flue Gas Desulfurization Operating Data
As previously stated, operating data for FGD systems
are limited. The PEDCo summary reports are the only industry
inclusive source of information. Reports on operating experi-
ence at a few specific installations are also available. How-
ever, none of these sources is comparable in scope to the EEI
data base. Specifically, the type of information which has
22
-------
TABLE 3-2.
OPERATING DATA FOR MATURE COAL-FIRED UNITS
(390-599 MW)
Unit
Coal Only
Coal Primary
Boilers
Coal Only
Coal Primary
Turb ir.es
Coal Only
Coal Primary
Condensers
Coal Only-
Coal Primary
Generators
Coal Only
Coal Primary
Other
Coal Only
Coal Primary
Year
1972
1973
1974
1972
1973
1974
1972
1973
1974
1972
1973
1974
1972
1973
1974
1972
1973
1974
1972
1973
1974
1972
1973
1974
1972
1973
1974
1972
1973
1974
1972
1973
1974
1972
1973
1974
Units in
Service
32
19
20
26
30
35
32
19
20
36
30
35
32
19
20
36
30
35
32
19
20
36
30
35
32
19
20
36
30
35
32
19
20
35
30
35
Operacing
Availability
(%)
75.1
74.3
69.9
74.2
77.3
71.5
79.6
83.0
76.7
79.0
84.0
77.6
86.3
88.4
39.7
86.4
90.6
39.5
96.7
97.4
97.3
96.0
97.6
97.7
91.0
96.3
94.0
90.2
96.1
94.4
95.0
93.3
96.2
94.3
98.0
97.0
Source:
:D-059
23
-------
TABLE 3-3. OPERATING DATA FOR ALL FOSSIL-FIRED UNITS
(GAS, OIL, COAL) 1965 - 1974
(390-599 MW, 111 UNITS)
Operating
Availability
Component (%)
Boiler 84.6
Turbine 89.2
Condenser 95.3
Generator 93.4
Other 95.1
Total Unit 78.9
Source: ED-043
24
-------
traditionally been collected by EEI for boilers, turbines,
condensers, etc., has not been gathered for FGD systems.
However, EEI's 1976 revised Equipment Availability Data Report-
ing Instruction (ED-060) has been modified to include FGD
systems.
There are four parameters used by PEDCo in their
bi-monthly FGD status reports which are commonly used in repor-
ting FGD system operating data. These four parameters as used
by PEDCo are defined below:
1) Availability = Hours the FGD system was available
for operation
Hours in the period
2) Reliability = Hours the FGD system was operated
Hours the system was required to
operate
3) Operability = Hours the FGD system was operated
Hours the boiler was operated
4) Utilization = Hours the FGD system was operated
Hours in the period
Of these parameters, availability is the only one which can be
compared with utility data and which is relevant to this study.
As stated in Section 1.2, reliability is not defined by the utility
industry. The term used as a measure of reliability in the utility
industry, Mean Time Between Full Forced Outage, is not comparable
to PEDCo's reliability. Furthermore, since PEDCo's definition
is inconsistent with traditional scientific definitions of
reliability, the usefulness is still more limited. Operability,
which is a measure of the degree to which the FGD system is
25
-------
actually used relative to boiler operating time, has no counter-
part in the utility data bases. Although utilization, a rela-
tive stress factor for the FGD system, is comparable to EEI's
Service Factor, a comparison of these parameters is not useful
in this study. However, Utilization Factors will be reported
for FGD systems to provide some indication of the operating
duty on these systems.
An initial screening of PEDCo's Summary Report--Flue
Gas Desulfurization Systems (PE-259) for the January to March,
1977, period identified 16 operational lime/limestone wet scrub-
bing systems and 1 operational system using magnesium oxide.
No sites using double alkali or Wellman-Lord were listed. The
criteria for selecting units for inclusion in this study were:
(1) the system treats flue gas from a utility generating station
greater than 50 MWe in size, (2) the system has been operating
approximately one year or more, and (3) the system is not a test
or demonstration unit. After application of these criteria to
the operating systems, only 12 lime/limestone units remained for
analysis.
The average modular availabilities and the utilizations
were determined for 7 of these 12 systems for the time periods
shown in Table 3-4. The average modular availability is the
average of the availabilities of each module in an FGD system.
Table 3-5 illustrates average modular availabilities for the
units for which these performance indicators were available.
A brief description of each of these seven boiler-scrubber sys-
tems is presented in Tables 3-6 through 3-12.
These availability data represent a total of about 13
unit-years of experience for the 7 systems with data reported.
This compares with about 173 unit-years of experience behind the
26
-------
TABLE 3-4. FGD OPERATING DATA CONCERNING
AVAILABILITY AND UTILIZATION
Lime/Limestone Systems
Will County No. 1
Commonwealth Edison
La Cygne No. 1
Kansas City Power & Light
Paddy's Run No. 6
Louisville Gas & Electric
Phillips
Duquesne Light
Cholla No. 1
Arizona Public Service
Green River
Kentucky Utilities
Colstrip No. 1
Montana Power
Elrama
Duquesne Light
Sherburne County No. 1
Northern States Power
Bruce Mansfield No. 1
Pennsylvania Power
Colstrip No. 2
Montana Power
Cane Run No. 4
Louisville Gas & Electric
Start-up
Date
2/27
2/73
4/73
7/73
10/73
9/75
10/75
10/75
3/76
4/76
7/76
8/76
Dates of
Availability
3/75-1/77
1/74-3/77
a
N.A.
8/73-10/76
12/73-5/75
12/75-3/77
N.A.a
N.A.b
5/76-3/77
5/76-8/77
N.A.a
N.A.a
Dates of
Utilization
3/75-1/77
N.A.S
a
N.A.
8/73-10/76
N.A.3
12/75-3/77
N.A.a
,
N.A.b
5/76-3/77
5/76-12/76
N.A.a
8/76-3/77
N.A. - Not Available
a
System is operational, but data were not reported.
Only 2 of 4 boilers have been connected to FGD system.
Sources: DI-R-161, HE-258, KR-115, PE-250, PE-267, PE-288.
27
-------
TABLE 3-5. FGD MODULE PERFORMANCE DATA - AVERAGE VALUES
ho
CO
System
Will County No. 1
La Cygne No. 1
Phillips
Cholla No. 1
Green River
Sherburne County No. 1
Bruce Mansfield No. 1
MW
167
874
413
126
64
720
825
No. of Average Modular
Modules Availability
(%)
2
7
4
2
1
11 (+1 spare)
6
44.2
88.6
60.6
91.5
72. 6b
90.9
77. 8C
Utilization3
(%)
33.6
N.A.
49.7
N.A.
62.1
70.9
76.8
Utilization is the hours the FGD unit operated divided by the hours in the
period expressed as a percentage.
Includes two-month outage in March-April, 1977, to reline stack.
clncluding reduction to half-load from March-July, 1977, due to repairs to
stack lining. Bruce Mansfield reports that the repairs were necessary due
to the improper installation of the original lining.
Sources: AN-184, BE-478, HE-258, KR-115, MU-155, PE-259, PE-267, PE-287, PE-288
-------
TABLE 3-6.
OPERATING CHARACTERISTICS OF THE WILL COUNTY
UNIT NO. 1 BOILER-SCRUBBER SYSTEM
Item
Descript ion
Parameter
Value
1. Bniler
2. Fuel
3. Participate Control
4. Absorbent Preparation
5. S02 Control
6. FGD System
7. Demister
8. Fan
9. Reheater
10. Sludge Disposal
11. Water Make-up
Unit No. 1 of the Will County Power Generating Station
Is a wet-bottom, coal-fired boiler which has been retro-
fitted with an FGD system. The boiler was manufactured
by Babcock and Wilcox and installed in 1955.
Medium Sulfur Coal
The FGD system is used as the primary means of control-
ling particulates. An electrostatic precipltator-(ESP)
manufactured by Joy Western Precipitation Division Is
used when the FGD system is inoperable,
Limestone slurry absorbs SO? from the flue gas. The
limestone milling facilities consist of a limestone
rock conveyer, two 260-ton limestone bunkers, two wet
ball mills, and a slurry storage tank.
The FGD system is used to control SOa emissions in
order to meet air quality regulations.
The FGD system consists of two identical modules, each
capable of processing 50 percent of the maximum flue
gas flow from the boiler. The FGD modules are com-
prised of a venturi prescrubber in series with a two-
stage perforated tray absorber.
A two-stage, chevron-type demister is located 7 feet
above tbe second absorber-tray. The demister Is
washed continuously from below and intermittently
from above. Demisters are constructed of fiber rein-
forced plastic.
There is an induced draft (ID) fan located at the
reheater outlet on each module. These ID fans are
in series with the boiler ID fans.
The gas exiting the absorber is rehated by a bare
tube reheater comprised of 9 sections. The bottom
three sections are stainless steel and the other
six sections are of corten steel construction. Each
rebeater has four soot blowers. Heat is supplied by
saturated steam at 350 PSTfl pressure.
Sludge is fixed bv mixing with .1 i.mp and flu ash.
Approximately 200 ]bs. of lime and 400 Ibs. of
fly ash are requested to stabilize 1 ton of sludge
(dry basis).
Both fresh water and recycle pond water are used in
the open-loop system.
Power Rating
Gross 167 Mw
Net Without FGD 153 Mw
Net With FGD 146 Mw
Average Capacity Factor
Sulfur Content
Ash Content
Heating Value
Removal Efficiency
FGD System
ESP
Composition
Silica
Calcium Carbonate
Magnesium Carbonate
Other
Stoichiometry
Removal Efficiency
System Vendor
Type
Start-up Date
Module A
Module B
Prescrubber Type
Module Size
L/C
Demister Wash
Top
Bottom
System Pressure Drop
Flue Gas Temperature
Inlet
Outlet
Pond/Landfill
Requirements
Fresh Water Make-up
2.14
10.0 Percent
9463 Btu/lb
98.0 Percent Removal
79.0 Percent Removal
0.5 Percent
97.5 Percent
1.0 Percent
1.0 Percent
1.3 - 1.5
82-90 Percent
Babcock and Wilcox
Retrofit
4/72
2/72
Variable Throat Venturi
385,000 acfm (3 355°F
34 gal/1000 cf
3,000 gpm Pond Supernatant/
40 sec. every hr.
120 gpm Fresh Water/Continuous
25 in. H20
128"F
165°F
150 Acre - ft/yr
300 gpm
Source: DI-R-161, PE-259
-------
TABLE 3-7.
OPERATING CHARACTERISTICS OF THE
LA CYGNE BOILER-SCRUBBER SYSTEM
Item
Description
Parameter
Value
1. Boiler The La Cygne Power Generating Station has a single
coal-fired boiler integrated with an FGD system.
Both are of Babcock and Wilcox design and construction.
The boiler Is a wet-bottom cyclone-fired unit which
began commercial operation on 6/1/73.
2. Fuel Low-grade, high-sulfur, sub-bituminous coal.
Power Rating
Gross
Net Without FGD
Net With FGD
Average Capacity Factor
Sulfur Content
Ash Content
Heating Value
874 Mw
844 Mw
820 Mw
42 Percent (1976)
5.4 Percent
24.4 Percent
9420 Btu/lb
3. Particulate Control
4. Absorbent Preparation
5. SO? Control
6. FGD System
7. Demister
8. Fan
9. Reheater
10. Sludge Disposal
11. Make-up Water
The FGD system is the particulate control device for
the La Cygne boiler. The venturl scrubber which precedes
each of the seven absorbers removes most of the partic-
ulates from the flue gas.
Limestone slurry absorbs SO; from the flue gas. The
limestone milling facilities consist of two wet ball
mills rated at 108 ton/br and two limestone holding
tanks. -.
The FGD system is used to control SO? emissions.
The FGD system consists of seven identical modules,
each capable of processing approximately one-seventh
of the maximum flue gas flow from the boiler. The
FGD modules are comprised of a venturi prescrubber
in series with a two-stage sieve tray absorber.
A single stage Chevron type demister is located
above a third sieve tray in each absorber. Two of
the modules have a second demister. The demisters are
washed continuously from below and Intermittently from
above. Demisters are constructed of fiberglass.
There are 6 ID fans located between the reheaters and
the stack. The suction side of these fans draws gas
from a common header connecting all seven FGD modules.
Flue gas exiting the absorber is reheated by heat
exchange with steam coils. This is supplemented by
injection of hot air into the flue gas stream.
Limestone slurry is removed continuously from the
absorber recirculatlon tank and pumped directly to
the sludge pond. This slurry is about 20 wt. percent
solid and no treatment is used.
La Cygne operates as a npen-loop system. Fresh water
is added to make up for evaporative losses and water
retained in the sludge.
Removal Efficiency
Composition
Silicates
Calcium Carbonate
Magnesium Carbonate
Stoichiometry
Removal Efficiency
System Vendor
Type
Start-up Date
Prescrubber Type
Module Size
L/G
Demister Wash
Top
Bottom
System Pressure Drop
Flue Gas Temperature
Inlet
Outlet
Pond/Landfill Require-
ments
Make-up Rate
97 to 99 Percent
5-7 Percent
85-93 Percent
2.5 Percent
1.7
70-83 Percent
Babcock and Wilcox
New
6/1/76
Variable Throat Venturi
394,300 Acfm
-------
TABLE 3^8. OPERATING CHARACTERISTICS OF THE
PHILLIPS BOILER-SCRUBBER SYSTEM
Item
Description
Parameter
Value
1. Boiler
2. Fuel
3. Particulate Control
4. Absorbent Preparation
3. Sf>2 Control
6. FGD System
7. Demister
8. Fan
9. Reheater
30. Sludge Disposal
11. Water Make-up
The Phillips Station consists of six dry-bottom,
pulverized coal-fired boilers. The entire station
has been retrofitted with an FGD system. The boilers
were manufactured by Foster-Wheeler and installed during
the period 1942 to 1956.
Medium-sulfur coal is burned in the boiler.
Particulates are controlled by Research-Cottrell
Mechanical Collectors in series with electrostatic
precipitators. The FGD system also removes particulates
from the flue gas.
Lime is used to absorb the SOj. Lime is fed from a storage
silo at a controlled rate to a lime slaker where it is mixed
with fresh make-up water. The slaked lime overflows to a
slaker transfer tank where make-up water is added to pro-
vide a constant flow of lime slurry with a 15-percent solids
concentration.
Only one of the four scrubber trains is used exclusively
for S02 from processed flue gas.
The FGD system consists of four modules of wet venturi-
type scrubbers. Three of the trains are single-stage
venturi scrubbers originally intended for particulate
removal. The fourth train is a dual-stage venturi
scrubber-absorber and is the prototype for determining
the feasibility of two-stage scrubbing for compliance
with SO; emission limits.
Two single-stage, horizontal chevron demlsters remove
entrained mist. One is an integral part of the Chemico
venturi scrubbers. The second Is downstream of the in-
duced draft fan.
There is a booster fan downstream of each of the pre-
scrubbers. The fans are equipped with fresh water
sprays to remove any accumulation of solids from scrubber
carryover.
A 316-C stainless steel section of the duct preceeding
the stack is equipped with a direct oil-fired reheater
unit that can raise stack gas temperatures as much as
30°F. Normal reheat is about 20°F.
The waste sludge is stabilized by the addition of 200
pounds of calcilox per ton of dry solids in the sludge.
The fixed sludge is transported to experimental plastic-
lined ponds located about one mile from the station,
where the material solidifies.
Both fresh water and recycle clarifier overflow are used
in the system. The system operates open-loop with 300 gpm
of the thickener overflow diverted.
Power Rating
Gross
Net Without FGD
Net With FGD
Average Capacity Factor
Sulfur Content
Ash Content
Heating Value
Removal Efficiency
Mechanical Collector-
ESP
FGD system
Composition
Calcium Oxide
Other
Stoichiometry
Removal Efficiency
Module 1
Module 2, 3 & 4
System Vendor
Type
Start-up Date
Prescrubber Type
Module Size
L/G
Demister Wash
System Pressure Drop
Module 1
Module 2, 3S'>
Flue Gas Temperature
Inlet
Outlet
Pond/Landfill Require-
ment?
Fresh Water Make-tip
413 MW
367 MW
373 MW
66 Percent (1976)
2.03 Percent
16.6 Percent
11,375 Btu/lb
80.0
95.0
Percent
Percent
95.0 Percent
5.0 Percent
1.3
90 Percent
50 Percent
Chemico
Retrofit
7/73
Variable-Throat Venturi
547,000 acfm @ 340°F
30 gal/1000 cf
Internal Automatic Spray
16 in. JbO
10 in. H20
110-120 F
140°F
635 gpm
Source: CO-596, DI-R-161, PE-258, PE-281, RO-243
-------
TABLE 3-9.
OPERATING CHARACTERISTICS OF THE
CHOLLA BOILER-SCRUBBER SYSTEM
Item
Description
Parameter
Value
1. Boiler
2. Fuel
3. Particulate Control
4. Absorbent/Preparation
5. S02 Control
6. FGD System
7. Demister
8. Fan
9. Reheater
10. Sludge Disposal
.11. Water Make-Up
A low-sulfur coal is burned at the power plant.
A Research-Cottrell multicyclone-type collector pro-
vides primary control of particulate emissions. The
FGD system also removes participates from the gas
stream.
Limestone is used to absorb S0a from the gas. Finely
ground limestone is purchased from a mine near Kingman,
Arizona. No milling facilities are at the Cholla
station. An additive containing a minimum of 52.5% CaO
and a maximum of 2.0% MgO is used.
The FGD system is used to control S02 emissions in order
to comply with air quality regulations.
The FGD system consists of two scrubbing modules (A and
B), each handling 50 percent of the boiler's flue gas
load. Module A is packed and circulates limestone slurry.
Module B is a spray-tower which circulates make-up water.
A two-stage, polypropylene slat deraister is located
12-15 feet above the absorption section of both A and
B absorbers. The first stage demister is washed inter-
mittently from above with fresh water sprays.
A forced-draft booster fan is located upstream of the
venturi prescrubber on each module.
The desulfurized flue gas is reheated as It passes through
two shell-and-tube heat exchangers. Heat is supplied by
200 psig steam.
The plant has no sludge treatment or fixation systems.
The sludge is pumped to the fly ash disposal pond on an
intermittent basis. Because of light rainfall and a
high evaporation rate in this area, no liquor is recircu-
lated from the pond.
No water is recycled from the sludge disposal pond to the
FGD system. Make-up water for the system is boiler water
blowdown.
Power Rating
Gross
Net Without FGD
Net With FGD
Average Capacity Factor
Sulfur Content
Ash Content
Heating Value
Removal Efficiency
Multicyclone
FGD system
Composition
Stoichiometry
Removal Efficiency
System Vendor
Type
Start-up Date
Prescrubber Type
Module Size
L/C
Demister wash
System Pressure Drop
Flue Gas Temperature
Inlet
Outlet
Pond/Landfill Require-
ments
Fresh Water Make-Up
126 Mw
115 Mw
112 Mw
85.3 Percent (1976)
0.60 Percent
12.0 Percent
10,000 Btu/lb
75 Percent
99.2 Percent
1.1
58.5 Percent
Research-Cottrell
Retrofit
7/73
Flooded-Disc, Variable
Throat Venturi
260,000 acfm @ 276°F
49 gal/1000 cf
25 in. H20
121"F
285 gpm
Source: CO-596, DI-R-161, MU-155, PE-259, RO-243
-------
TABLE 3-10.
OPERATING CHARACTERISTICS OF THE
GREEN RIVER BOILER-SCRUBBER SYSTEM
Ite
Description
Parameter
Value
OJ
1. Boiler
2. Fuel
3. Partlculate Control
4. Absorbent/Preparation
5. SOz Control
6. FGD System
7. Demlster
8. Fan
9. Reheater
10. Sludge Disposal
11. Water Make-Up
The Green River Station has four coal-fired boilers
which have been retrofitted with an FGD system. Green
River is a peak load station which normally operates
five days a week.
A high-sulfur, western Kentucky coal is burned in the
boilers.
The FGD system is used in conjunction with mechanical
collectors.
Lime slurry is used to absorb SOj from the flue gas.
Pebble lime is purchased and stored in a 500-ton capacity
bin. Lime is slaked in an agitated tank to produce a 20
percent solids slurry.
The FGD system controls SO; emissions in order to meet
air quality regulations.
The FGD system consists of a single module capable of
treating all of the flue gas from boilers 1, 2, and 3.
The module consists of a venturi prescrubber in series
with a mobile-bed absorber.
A centrifugal vane type demister is used to remove
entrained mist from the flue gas stream leaving the
absorber. The demister is of coated mild steel and
stainless steel construction and is 10-15 feet above
the absorber bed.
A forced draft booster fan is located upstream of the
venturi prescrubber.
There was no reheater on the original system. AAF
has been authorized to design and install a reheater
using exchange with external steam coils.
Sludge is pumped to an unlined pond. Clear pond over-
flow is returned from the pond to the reactant tank.
Make-up water is added to the open-loop system to replace
evaporative losses and water which is retained in the
sludge.
Power Rating
Net with FGD
Average Capacity Factor
Sulfur Content
Ash Content
Heating Value
Removal Efficiency
Mechanical Collectors
FGD System
Composition
Stolchiometry
Removal Efficiency
System Vendor
Type
Start-Up Date
Prescrubber Type
Module Size
L/G
Demister Wash
Top
System Pressure Drop
Pond Landfill Require-
ments
Fresh water make-up Rate
64 Hw
44.2 Percent (1976)
3.7 Percent
12.7 Percent
11,154 Btu/lb
99.7 Percent
1.1 - 1.2
80 Percent
American Air Filter Co.
Retrofit
9/75
VentuTi
360,000 acfm
-------
TABLE 3-11.
OPERATING CHARACTERISTICS OF THE SHERBURNE COUNTY
NO. 1 BOILER-SCRUBBER SYSTEM
Item
Description
Parameter
Value
LO
-P-
1. Boiler
2. Fuel
3. Partlculate Control
4. Absorbent/Preparation
5. SOj Control
6. FGD System
7. Demlster
8. Fan
9. Reheater
10. Sludge Disposal
11. Water Make-Up
Unit No. I of the Sherburne County (SherCo) generating
plant is a pulverized coal-fired-boiler manufactured
by Combustion Engineering. The FGD system was constructed
concurrently with the generating plant.
Low sulfur sub-bituminous coal from the Colstrip area of
Montana is fired.
The FGD system is also the particulate control device for
the SherCo No. 1 boiler. The venturi scrubber which pre-
cedes each of the 12 absorbers removes most of the partlcu-
lates from the flue gas.
Limestone is ground in two wet ball mills with a combined
rating of 48 tons/hr and delivered as a 4 percent slurry
to each module's reaction tank. SOj removal is achieved
by using two additive sources: calcium oxide in the fly
ash and tail-end addition of limestone. The allcalinty
of the ash is depended upon for the bulk of the SOj removal.
The FGD system is used to control SOz emissions to meet
state air quality regulations.
The FGD system consists of 12 identical modules, each
capable of treating 200,000 ACFH of flue gas. Each
module is comprised of a venturi prescrubber and a
single-stage marble bed absorber.
A two-stage chevron slanted (v-shape) demister is located
10.5 feet above the marble bed. Demisters are molded from
a fiberglass reinforced polyester material. Intermittent
wash of top and bottom of first stage and bottom of second
stage with a mixture of thickener overflow and cooling
tower blowdown.
An induced draft (ID) fan is located downstream of the
reheater on each module.
The gas leaving the absorber is reheated by four rows of
finned carbon steel tubes. Heat is supplied by water at
358°F.
Unstabilized sludge of about 30 wt. percent solids is
transferred to a lined pond for disposal.
Both fresh water and recycle pond water are used as make-
lip in the open-loop system.
Power Rating
Gross
Net With FGD
Average Capacity Factor
Sulfur Content
Ash Content
Heating Value
Removal Efficiency
FGD System
Composition
Stoichlometry
Removal Efficiency
System Vendor
Type
Start-Up Date
Prescrubber Type
Module Size
L/G
Demister Wash
Top & Bottom
System Pressure Drop
Flue Gas Temperatures
Inlet
Outlet
Pond/Land fill Require-
ments
Fresh Water Make-Up
720 Hw
663 Hw
69 Percent (1976)
0.8 Percent
9 Percent
8,500 Btu/lb
98-99 Percent
1.25
50-55 Percent
Combustion Engineering
New
6/76
Venturi Rod
200,000 acfm @ 310°F
27 gal/1000 cf
2 min. every 24 hr.
17 in. H20
131"F
171°F
2,000 gpm
Source: CO-596, KR-115, PE-259, RO-243
-------
TABLE 3-12.
OPERATING CHARACTERISTICS OF THE BRUCE MANSFIELD
NO. 1 BOILER-SCRUBBER SYSTEM
Item
Description
Parameter
Value
(jO
Ul
1. Boiler
2. Fuel
3. Particulate Control
4. Absorbent/Preparation
5. SOa Control
6. FGD System
7. Demister
8. Fan
9. Reheater
10. Sludge Disposal
11. Water Make-Up
Unit No. 1 is a coaJ-fired, once-through, supercritical
steam generator.
Medium to high sulfur coal is burned.
A Chemico variable-throat venturi provides primary partic.u-
late control on Unit No. 1. This venturi is the first
stage of the FGD system.
A thiosorbic lime slurry is used to absorb SOz from the
flue gas. The lime Is slaked before being fed to the
absorber.
The FGD system is used to control SOj emissions to meet
state air quality regulations.
The FGD system consists of 6 identical modules. Each
module is composed of a variable-throat venturi in
series with a fixed throat venturi.
A four-stage horizontal Chevron mist eliminator is
located downstream of the absorber. The bottom is
washed by a sequence, of nozzle, continuously with
clarifier overflow and fresh water while the top
is washed once per shift with clarifier overflow.
An induced draft fan is located between the venturi
scrubber and the venturi absorber.
Not Available.
Scrubber-recycle bleed is combined with fly ash
and fed to a thickener. Sludge from the thickener
is pumped to a waste disposal system and mixed with
Calcilox, a stabilizing agent. The sludge is then
pumped to an offsite disposal area.
Both fresh water and thickener overflow are used as
make-up in the open-loop system.
Power Rating
Net
Average Capacity Factor
Sulfur Content
Ash Content
Heating Value
Removal Efficiency
Composition
Calcium Oxide
Magnesium Oxide
Acid insoluble
Stoichiometry
Removal Efficiency
System Pressure Drop
Scrubber
Absorber
Flue Gas Temperature
Inlet
Outlet
Pond/Landfill Require-
ments
Fresh Water Make-up
825 Mw
36 Percent (1977)
3.3 Percent
16.8 Percent
86-89 Percent
2.8-5.7 Percent
4-8 Percent
1.58 Percent
85-93 Percent
System Vendor
Type
Start-Up Date
Prescrubber Type
Module Size
L/G
Demister Wash
Top
Chemico
New
4/76
Venturi
560,000 acfm
56 (total)
I/shift
40 min/hr clarifier
overflow and 20 min/hr
fresh water
20 in. H?0
4 in. H20
Source: FL-090, PE-259, PE-288
-------
performance data previously reported for coal-fired units in
Table 3-2 and about 555 unit-years for the utility operating
data in Table 3-3. The disparity between FGD and utility data
is again evident in the unit-years of operating experience which
serve as the basis for an availability determination. The FGD
data were previously determined to not yet represent a statis-
tically valid sample that would allow extrapolation to new Lime
or Limestone FGD systems (DI-R-161).
The average modular availabilities vary from one unit
to the next. However, five of the seven units have average mod-
ular availabilities greater than 70 percent. Furthermore, three
are greater than 88 percent. Four units also have utilization
of about 50 percent or more. These utilizations indicate the
load on the FGD units has been large enough to reasonably quan-
tify the operating history of the specific individual units.
One factor of importance is the change in the modular
availability of an FGD unit as experience operating the system
is acquired. The Will County unit, which is the oldest of the
seven, has experienced rather erratic performance including 10
one-month periods in which the FGD unit was not available at
all. The availability data for Will County are plotted in
Figure 3-3. The five other units for which data were available
have shown a more consistent and successful operating experience.
The modular availability of the Phillips unit has improved to an
average of about 73 percent for the last 2 years with relatively
consistent operation in the high 60 to high 80 percent range
(Figure 3-4). The remaining units: La Cygne, Green River,
Sherburne County, and Bruce Mansfield have experienced relatively
stable operation with modular availabilities consistently between
80 and 100 percent (Figures 3-5 to 3-8). In particular, La Cygne
No. 1 and Sherburne County No. 1 have increased their average
36
-------
16
20 25 30 35 40
TIME FROM START-UP (MONTHS)
45
50
55
60
Figure 3-3. Will County No. 1 FGD average modular availability.
-------
OJ
00
100
90-
80-
70-
« 60
t 50-
5
5 40
>
30
20-
10
i
10
15 20 25 30 35
TIME FROM START-UP (MONTHS)
40
45
50
i
55
Figure 3-4. Phillips FGD average modular availability (average all modules)
-------
OJ
100 H
90-
80-
70-
m
50-
40-
30-
20-
10
5 10 15 20 25 30 35 40 45 50
TIME FROM START-UP (MONTHS)
55
Figure 3-5. La Cygne FGD average modular availability (average all modules)
-------
-p-
o
100-.
90 -
80 -
70 -
60-
50 -
CO
< 40 -
30 -
20 -
10 .
10 15 20 25 30 35 40
TIME FROM START-UP (MONTHS)
45 50
55
Figure 3-6. Green River FGD modular availability.
-------
100-
90-
80
70n
~ 60
<£
^^
>•
t 50-
_i
5
5 40-
<
>
<
30-
20
10
10 15 20 25 30 35
TIME FROM START-UP (MONTHS)
40
45
50
55
Figure 3-7. Sherburne County No. 1 FGD average modular
availability (average all modules).
-------
100
90
80
70
* 60
5 50 .
5
I"
30
20
10
i
5
i
10
i
15
i i i i i
20 25 30 35 40
TIME FROM START-UP (MONTHS)
45
50
i
55
Figure 3-8. Bruce Mansfield No. 1 FGD average modular
availability (average all modules).
-------
modular availability to consistently greater than 90 percent
after the start-up phase of operation. Green River and Bruce
Mansfield No. 1 have also reported several monthly average mod-
ular availabilities above 90 percent but repairs to the stacks
at these plants have resulted in the total unavailability of
some modules during the stack repairs. A reduction in the av-
erage modular availability thus resulted (PE-288). It should
be noted that these modular availabilities do not reflect the
performance of the FGD system as a whole; no data were reported
as to whether the modules failed singly or in groups, or whether
the generating unit was experiencing a coincident outage.
For this study, an average modular availability in the
range of 70 to 90 percent was assumed for a mature FGD unit.
This 70 to 90 percent modular availability range will receive
primary emphasis in evaluating the effect of the availability
of FGD systems on individual generating stations and on genera-
ting systems in Sections 3.4 and 3.5, respectively. It should
be noted again that this is a modular and not an FGD unit avail-
ability.
One comparison of interest is that of the availability
for the initial operating period for older units with the avail-
ability for the initial operating period for newer units. This
comparison is particularly interesting for units by the same
vendor. Table 3-13 presents the first year average modular
availabilities for the seven FGD units emphasized in this study.
This table points out the substantial improvements in the initial
operating experience of units installed by the same vendor. The
newer B&W and Chemico units show significant improvements rela-
tive to the older units by the same vendor. Furthermore, the
newer units in general show improved average modular availabili-
ties during the initial operating period. These improvements
43
-------
TABLE 3-13. THE INITIAL AVAILABILITY OF SEVEN FGD SYSTEMS
System
Will County No. 1
La Cygne No. 1
Phillips
Bruce Mansfield No. 1
Cholla No. i
Green River
Sherburne County No.- 1
Start-up
2/72
2/73
7/73
4/76
10/73
9/75
3/76
First Year Modular
Vendor Availability (70)
B & Wa
B & Wa
Chemico
Chemico
R - Cb
AAFC
CEd
-49
-87*
-36
-80
N.A.
-85
-90
N.A. - Not Available
* - Second year availability is reported because data for
the first year were not available.
•a
Babcock and Wilcox
Research Cottrell
Q
American Air Filter
Combustion Engineering
44
-------
might be expected as a result of general advances in the state-
of-the-art and particularly due to increased design and operating
experience in the FGD industry. Radian has previously examined
this "learning curve" effect in a study for EPA (DI-R-116).
3.3 Analysis of Flue Gas Desulfurization Availability
Numerical parameters that measure the performance of
an FGD system must be carefully analyzed prior to any general
application. The possible existence of factors that might in-
fluence general application must be considered. Some of these
factors of interest for an FGD system include the size of the
unit, the boiler load, the type of FGD process, the number of
scrubber modules and of spare modules, the water balance, the
sulfur content of the coal, the SO2 removal efficiency, the
maintenance effort, and the capability to bypass the FGD unit.
Table 3-14 summarizes this information for the seven
systems identified in the previous section for which data was
obtained. Consideration of additional items such as scrubber
design, type of scrubber, mist eliminator design and operation,
reheater design and operation, scrubber operation and control,
etc., would be necessary for a detailed analysis of the operating
data. However, that is beyond the time frame established for
this study. The operating seven systems will be analyzed indi-
vidually with a general discussion at the conclusion of this
section. The problems which caused system failures initially
and the actions taken which improved the modular availability
as shown in Figures 3-3 through 3-8 are also addressed. Further
discussion of operating problems and solutions is presented in
Section 4.1.
45
-------
TABLE 3-14. FACTORS FOR CONSIDERATION IN FGD AVAILABILITY ANALYSIS
Boilers
System No./MWea
Will County 1/167
No. 1
La Cygne No. 1 1/874
Phillips 6/413
Cholla No. 1 1/126
Green River 3/64e
No. 1 & 2
Sherburne County 1/720
No. 1
Bruce Mansfield 1/8256
No. 1
Total
FGD Modules
Load Process (B-Bypass)
Intermediate0 Limestone 2-B
or Cycling
Intermediate0 Limestone 7
or Cycling
Peakingd Lime 4-B
Baseb Limestone 2-B
Peakingd Lime 1-B
Intermediate0 Limestone 12
or Cycling
Intermediate0 Lime 6s
or Cycling
Water Coal
Spares Balance .7. S
0 Open Loop- 0.4-4.0
with recycle
0 Open Loop- 5.3
with recycle
0 Open Loop- 2.2
with recycle
0 Open Loop- 0.5
no recycle
0 Open Loop- 2.5-3.0
with recycle
1 Open Loop- 0 . 8
with recycle
0 Open Loop- 4.0
with recycle
7. S02
Removal Maintenance
80-85 N.A.
80 Special crew. Clean
1 module per night.
50 Special crew for
FGD unit.
50f Separate crew for
FGD unit.
Up to Utility mainten-
90 ance.
50 Special crew. Clean
2 modules per night
N.A. N.A.
aGross MWe; does not include FGD.
bBase load: Unit operation at high capacity factor and high output factor throughout the daily period. Average annual
service hours normally exceed 5500. (CO-RF-700)
clntermediate Load: Unit synchronized during the daily period but at moderate to low capacity and output factor due to
generation following daily load requirement cycles. Average annual service hours are normally in the range
1500-5500. (CO-RF-700)
dPeak Load: Unit startup, operation, and shutdown determined by daily load cycle. Average annual service hours are
normally less than 1500. (CO-RF-700)
SNet MWe with FGD.
fModule A scrubs about 927. S02 from 50% of the flue gas; Module B scrubs about 257. S02 from 50% of the flue gas
BSix total modules with 1 being a spare were planned. However, all 6 modules are required for satisfactory operation at
full load. Another module is being added to serve as a spare. '
N.A. - Not Available.
Sources: AN-184, HE-258, KN-039, KR-115, KR-116, MC-293, MC-295, MU-155, PE-259, PE-287, PE-288, WO-130.
-------
Will County No. 1, the oldest system, started up in
1972 about one year before La Cygne No. 1, the next oldest. The
system was designed for high sulfur coal but has never operated
very successfully on high sulfur coal. However, operation with
low sulfur coal has been satisfactory. The stage of development
of flue gas desulfurization technology at the time this system
was designed and constructed is a major contribution to the
relatively low availability and to the limited success operating
with high sulfur coal. In the future, Will County No. 1 is
expected to use only low sulfur coal to make the FGD system op-
erate more reliably. Some of the initial problems included
buildup on demisters, reheater vibration, and corrosion. The
demister was modified and an overspray added to reduce buildup.
Rebracing the reheater solved the vibration problem. Reheater
corrosion declined after installation of a second stage mist
eliminator to reduce the deposits on the reheaters.
La Cygne No. 1 has had a successful operating exper-
ience. The system has had stable operation with no major fail-
ures (massive scaling, etc.). There were some initial problems,
however. These problems included vibration of the I.D. fans,
plugging in demisters and strainers, nozzle wear, corrosion of
reheater tubes, and restriction of the mobility of the Turbulent
Contact Absorber (TCA) balls. Fan vibration was a fabrication
defect corrected by the vendor. Demister and strainer plugging
and nozzle wear were reduced by installing a hydrodome in the
slurry recirculation line. Hot air from the preheater was injec-
ted upstream of the reheater to reduce condensation on reheater
tubes. The TCA was replaced with a sieve tray to eliminate the
ball mobility concerns.(PE-259, RO-243).
47
-------
The FGD system for La Cygne No. 1 is on an intermediate
load boiler burning high sulfur coal. An important factor which
is not considered in determining availability for La Cygne is the
maintenance effort. Current operating practice is to shut down
one module each night and have a maintenance crew inspect and
clean the module. A large well-trained operating crew is used.
The high system availability is partly attributable to this
maintenance and operating effort and to establishment of a
separate well-trained crew (47 operation, 15 maintenance) for the
FGD system. Better control of the chemistry may result in a
manpower reduction in the future. Experience at La Cygne in-
dicates that a scrubber can be operated reliably with sufficient
expenditure of money and effort.
Phillips has experienced lower availabilities than
most of the other systems. Some of the initial problems inclu-
ded plugging of absorbers, acid condensation in the stack, corro-
sion and erosion in I.D. fans and scrubbers, and inadequate pond
capacity. Absorber plugging has required a complete cleaning
of a scrubber vessel about every 1400 service hours. Each clean-
ing with minor maintenance requires 1400-1700 man-hours. The
cleaning is required due to deposits that increase the pressure
drop to levels such that the scrubber cannot treat flue gas from
all six boilers. In the past, one or more boilers have been
routed around the FGD system when this occurred. The corroded
steel bands around the inner stack were repaired. Corrosion and
erosion were reduced by operation at a higher pH and by use of
resistant materials. More pond capacity was installed to handle
the increased sludge.
More recently, testing at Phillips has included the
use of magnesium modified lime rather than high calcium lime.
The results of this testing indicate reduced deposits and,
therefore, more reliable operation are achievable. Further
48
-------
modifications include addition of a redundant lime feed system
and automatic pH control with the redundancy required for con-
tinuous control. Boilers at the Phillips unit burn a medium
sulfur coal.
Cholla No. 1 is somewhat unique compared to the other
systems in that low sulfur coal is burned and the water balance
is open loop with no recycle. The use of 0.5 percent sulfur
coal with only 50 percent S02 removal results in Cholla scrub-
bing a much lower quantity of S02 per ton of coal than most of
the other systems. The open loop operation with no recycle vir-
tually eliminates the chemical scaling and plugging problems that
have plagued many other systems. The success of Cholla seems to
indicate that control of the process chemistry is of foremost
importance to insure the reliable operation of an FGD system.
Problems which occurred during initial operation at
Cholla No. 1 include reheater vibration and corrosion, solids
buildup in the gland boxes, plugged lines, fan vibration due to
buildup, solids settling out in standby pumps, and demister plug-
ging. Baffles reduced reheater vibration while insulation upstream
of the reheater and a baffle to divert acid condensation from
the tubes reduced corrosion. The packing gland was installed
upside down to stop solids buildup. Fans were sandblasted to
remove the buildup. Standby pumps were flushed after removal
from service to remove solids. Finally, the demisters required
redesigning (MU-074, PE-259, RO-243).
Green River is another system that has been relatively
successful. The availability from startup averaged about 82 per-
cent until a two month outage in March-April, 1977, was necessary
to reline the stack. This system was reportedly overdesigned and
given an abnormal amount of attention since it was the vendor's
first system. System design was 4 to 5 percent sulfur while the
49
-------
unit averages 2.5 to 3 percent sulfur. Onsite chemical work was
also emphasized including the use of extensive monitoring;. . Green
River is normally a peaking unit which would allow maintenance
when the unit was down but the unit has been maintained at a higher
load to test the scrubber. At present the system has no reheat.
Addition of reheat is planned due to corrosion problems downstream
from the scrubber. A separate operating crew operates the
scrubber but the utility maintenance crew is used to service the
scrubber.
Initial problems included erosion of fan blades and
pump linings, scale downstream of the mist eliminator, and plug-
ging of recycle pumps. Resistant materials were installed in
the pumps and fans to reduce erosion. The area downstream of
the mist eliminator is cleaned of scald semi-annually. Backup
screens were placed in recycle pump lines to stop plugging
(PE-259, BE-478).
Sherburne County No. 1 (Sherco No. 1) uses an approach
to successful operation that is similar to that at La Cygne. A
separate operating and maintenance crew was set up for the FGD
system. Each night when the load drops, two of the twelve mod-
ules are inspected and cleaned. The crew at Sherburne County
is smaller than at La Cygne, 35 men for Sherco No. 1 and No. 2
versus La Cygne's 51 for one unit. However, reliable operation
is enhanced at Sherco No. 1 due to use of low sulfur coal (0.8
percent S) , low S02 removal (50 percent) , and the presence of a
spare module.
The major initial problems were spray nozzles and plug-
ging in the scrubber. Plastic nozzles were changed to a ceramic
spinner vane type to overcome the nozzle problem. Plugging in
the scrubber was reduced by modifying the strainer system and
nozzle configuration (KR-115, PE-259).
50
-------
Bruce Mansfield No. 1 is a system that apparently has
been very successful on high sulfur coal, without a spare module3,
and without a special operating and maintenance crew. Operating
experience has not been as trouble-free as the system's reported
modular availability might indicate, however. As previously re-
ported, the unit will be at half load for about three months in
March-July 1977, while half of the stack is relined. Another
three-month load reduction will be required later in 1977 to
reline the other half of the stack. When the first reduction
in load was included in the Bruce Mansfield data, availability
for the system dropped to about 78 percent.
Some of the initial problem areas were the excessive
maintenance for the fan housings, excessive carryover causing
an acid rain problem, reheat burner problems, and failure of
the stack liner. Fan housing maintenance has not been reduced.
Additional mist eliminators were installed to reduce acid rain
but the gas velocity was too great destroying the mist elimina-
tor. The reheater is still not working well and the stack liner
is being replaced.
Analysis of the FGD availability data in Table 3-4 and
Figures 3-3 through 3-8 leads to several conclusions. No corre-
lation between FGD availability and the size of the generating
unit, the type of FGD process, the size of the FGD modules, or
the ability to bypass was observed. Three systems examined in
this study which have a large number of modules and/or a spare
module (La Cygne No. 1, Sherburne County No. 1, and Bruce Mans-
field No. 1) all have reasonably high modular availabilities.
Application on a peaking or intermediate unit rather than base
load allows maintenance to be performed on a more routine basis,
and, therefore, enhances reliable operation. Since FGD units
aThe FGD unit was to have 6 total modules with 1 being a spare.
However, all 6 modules are required for satisfactory operation
at full load. Another module is therefore being added to serve
as a spare.
51
-------
have operated successfully on low sulfur coal (e.g. Sherburne
County No. 1) and high sulfur coal (e.g. La Cygne), the proper
design and operation of the system were determined to be more
important than the sulfur content of the coal. Historically,
inclusion of spare modules and an open water balance without
recycle are additional factors that have contributed to more
reliable operation. The establishment of a separate operating
and maintenance crew that is specifically trained to work with
the FGD unit is a final important factor in reliable operation.
All of these factors are important considerations in any analy-
sis of system availability.
3.4 Effect of Flue Gas Desulfurization Availability
on an Individual Utility Generating Station
Application of a flue gas desulfurization system to
an electric utility generating station will have a direct effect
on an individual generating station since the availability of the
FGD unit has a direct impact on the ability of the station to meet
demands for power. The individual utility generating station case
for this study was assumed to be a base loaded station operating
at or near full capacity. Base loading means that a unit is
generally run at a constant or nearly constant output of electric
power except during times when system economics dictate reductions
in load to avoid shutting other units down. In general, base load
units are the most economic units on a system. Edison Electric
Institute (ED-043) defines base loading as "when a unit is
generally run at or near rated output."
One way to estimate the effect of FGD on a utility
generating unit is to take the product of the average estimated
FGD unit availability and the average generating unit avail-
ability. This product is the resultant estimated average plant
52
-------
availability including the FGD system. The FGD unit availability
is the availability of the entire FGD unit and is the probability
that the FGD unit will operate a certain percentage of the time
at a specific fraction of full capacity. In other words, an FGD
unit availability is associated directly with some specific level
of operation of the FGD unit and, therefore, some specific level
of operation of the generating station to which the FGD unit is
connected. This method of analysis does not consider partial
outages or individual module failures.
Based on the data in Table 3-2 in Section 3.2.1, mature
coal-fired units have an average operating availability of about
75 percent. This means that on the average the generating station
would be capable of operation at its rated output 75 percent of
the time.
A parametric study of the effect of FGD unit avail-
ability on an individual utility generating station was performed.
Generating unit availability was assumed to be 75 percent while
FGD unit availability was varied from 0 to 100 percent. The re-
sults of this parametric study are shown m Figure 3-9. As can
be seen, the FGD unit availability has a dramatic effect on
generating station availability and, therefore, on the ability
of the generating station to respond to demands for power. It
follows, then, that the results of an assessment of FGD impact
rest heavily on the FGD unit's availability.
From the presentation and discussion of FGD operating
experience in Section 3.2.2, an FGD modular availability in the
70 to 90 percent range was chosen for a mature FGD system in
this study. The FGD unit availability at full capacity can be
calculated using the modular availability, the number of modules
in the FGD unit, and the number of modules required for operation
at full capacity. Assume a five module FGD unit with identical
53
-------
Individual
Generating
Station
Availability
00
Ul
-p-
100 -I
90-
80
75%
70
66%
60
50 H
40
32%
30-
20-
13%
10
0
D /
/ \
/ 1
X ;
v/ '
'"""/* |
/ !
X ! '
/ ' i
1 1 7^ ' * '42% ' SQ5
10 20 30 40 50 "j-
r i i
i i
i i
i i
i i
' 1
i i
i i
i i
. i
i
i |
i i
i i
•>0 70 80 88790 10(
A - No FGD
B - 6 Modules/I Spare
90% Availability
per Module
G - 5 Modules/No Spares
90% Availability
per Module
D - 6 Modules/1 Spare
70% Availability
per Module
E - 5 Modules/No Spares
70% Availability
per Module
1-igur
FGD Unit Availability (%)
3-9 . Effect of flue gas desulfurization unit availability on
individual generating station availability at maximum load.
-------
modules and no spares. With a 70 percent modular availability,
the FGD unit availability at full capacity would be 17 percent.
With a 90 percent modular availability, the FGD unit avail-
ability at full capacity would be 59 percent. The resultant
plant availability for an individual generating station with an
FGD system would then range from about 13 to 44 percent. These
availabilities correspond to a significant reduction in the
amount of time a station could operate at its rated output
unless the station were allowed by bypass the FGD unit. For the
13 percent plant availability (70 percent FGD availability), a
reduction of about 62 percent results. With a plant availability
of 44 percent (90 percent FGD availability) , the reduction is
about 31 percent.
As a result, the ability of an individual generating
station to meet consumer demands would be reduced by 31 to 62
percent due to the use of an FGD unit. This comparison is
relative to a coal-fired unit with an availability of 75 percent.
Since the unit considered in this section operates at rated
output, the 31 to 62 percent reduction in availability would have
to be offset in some manner. One solution would be to build
additional generating capacity that can supply the power that is
no longer generated by the individual station due to the appli-
cation of the FGD unit. Another alternative is the sparing
of selected FGD equipment and/or modules.
Assume a spare module is added to the FGD unit such
that five of the six modules can treat the flue gas generated
at full capacity operation of the boiler. The spare module re-
sults in a full capacity availability of 42 percent for the unit
with a modular availability of 70 percent. The unit with a 90
percent modular availability has a full capacity availability
of 88 percent with a spare module. The resultant plant avail-
ability for an individual station with an FGD unit would then
55
-------
range from about 32 to 66 percent. The use of a spare module,
therefore, improves the availability of the unit dramatically.
Unit availability improves still more with each spare module
added but the economics become less favorable with each spare
added. A preliminary examination of the impact of a spare
module was completed for the individual utility generating
station case. This examination is presented in Appendix B.
Previously, the discussion has been limited to
operation of the utility generating station at full capacity.
During periods of reduced load on the generating station an FGD
module might be down but the FGD unit could possibly still treat
all of the flue gas. For this reason, the availability of the
unit for a range of boiler loads including partial outages and
the load duration curve for the system are both important consid-
erations. However, a comprehensive incorporation of this factor
into this study was beyond the constraints of this study. The ef-
fect of a load duration curve was considered in a rudimentary
manner in this study. A method which could be used to incorporate
a load duration curve is also presented in Appendix B.
3.5 Effect of Flue Gas Desulfurization Availability on
Generating Systems
This study considers the effect of FGD on the nine
NERC regions and on the nation as a whole. The approach to
this examination is the same as that used for an individual
utility generating station in the preceding section. For the
generating systems, however, the FGD units will only affect
56
-------
the new coal-fired capacity that comes under EPA's New Source
Performance Standards. As previously stated, all of this new
coal-fired capacity is assumed to use flue gas desulfurization
as the method of S02 control. Therefore, the effect of FGD on
each system is proportional to the new coal-fired steam turbine
generating capacity in that system.
A parametric study of the effect of FGD availability
on 10 utility systems was performed for the year 1985. FGD
unit availability was varied from 0 to 100 percent. The effect
of this availability on the new coal-fired capacity then deter-
mined the overall effect on the system. The new coal-fired
capacity was represented as a single generating plant with one
FGD unit composed of one module. FGD unit availabilities of
70, 80, and 90 percent are emphasized in estimating the impact
of FGD availability on electric generation.
The effect of flue gas desulfurization on a utility
system was estimated as shown below:
% Capacity With FGD = (1007c Capacity Without FGD) -
(% New Coal) x (1-FGD Availability)
The system is assumed to be at 100 percent capacity prior to
application of FGD. The reduction in capacity due to the use
of FGD was approximated as the product of the fraction of new
coal capacity in a system and the reduction in availability of
this new coal capacity due to FGD. The fraction of new coal
represents coal-fired plants coming on line between 1976 and 1985
57
-------
For example, in 1985 System 4 has 14.5 percent new
coal capacity (Table 3-1). If an FGD availability of 80 percent
is assumed, the effect of FGD is estimated by
100% - (14.5%)(l-.8) =
100% - (14.5%)(.2) =
100% - 2.9% = 97.1%
Therefore, the estimated effect of the use of FGD is a reduction
of generating capacity to 97.1 percent of the capacity without
FGD. The impact of FGD on each system examined using the method
above is shown in Table 3-15 for 1985, Projections were not car-
ried beyond 1985 because data for the systems examined was not
readily available beyond 1985. Additional follow-on work will
be done to carry the projections through 1998 and to also con-
sider other factors such as load demand curves.
The effect of FGD varies from system to system depending
on the amount of new coal capacity and the FGD availability that
is assumed. System 2 shows the greatest impact while System 3 is
the least affected. The percent new coal for each system is shown
in Table 3-16.
The effect of FGD availability on a generating system
is observed to be less dramatic than for an individual station.
This would be expected due to the diluting effect of power genera-
tion with fuels other than coal or with coal units that do not have
FGD systems for S02 control. For a single new coal station the
entire station was affected by FGD availability. Conversely,
only the new coal capacity of a generating system is affected
.by FGD.
58
-------
Table 3-15. ESTIMATED EFFECT OF FLUE GAS DESULFURIZATION
UNIT AVAILABILITY ON 1985 SYSTEMSa
FGD Unit Availability (%)b
System
1
2
3
4
5
6
7
8
9
10
70
94
90
99
95
91
99
97
91
96
95
80
96
93
99+
97
94
99+
98
94
97
97
90
98
96
99+
99
97
99+
99
97
98
98+
a
Effect is determined by the ratio of system generating
capability with FGD units over system generating capa-
bility without- FGD units expressed as a percentage.
One FGD unit composed of one module on a single gener-
ating station representing all new coal capacity.
59
-------
TABLE 3-16. NEW COAL GENERATING CAPACITY
IN EACH SYSTEM - 1985a
System 7. of 1985 Total Capacity
1
2
3
4
5
6
7
8
9
10
18.4
33.6
3.5
14.5
29.2
4.4
11.7
30.0
13.5
16.0
a
Fraction of 1985 total capacity repre-
sented by coal-fired units coming
on-line between 1976 and 1985.
60
-------
The significance of the 1985 impacts shown in Table
3-15 is difficult to put into perspective until a comparison is
made with consumer demand. The National Electric Reliability
Council (NERC) has projected the 1985 summer total resources
and peak loads in megawatts for the systems examined in this
study (NA-325) . The summer peak demand as a fraction of the
total summer resources for each system is presented in Table 3-17
TABLE 3-17. SUMMER PEAK LOADS -
1985 PROJECTIONS BY NERC
System Summer
1
2
3
4
5
6
7
8
9
10 (Nation)
Peak Load (%)a
89
82
78
85
80
71
85
88
76
81
aExpressed as a percentage of the
total summer resources (MW) pro-
jected for 1985 by NERC.
Source: NA-325
Each of the cases presented for 1985 in Table 3-15 can
potentially meet the highest summer peak load projected by the
NERC for 1985 (Table 3-17). However, it is critical to understand
that the primary reason consumer demand can be met in these 1985
example systems is the excess capability above peak loads that
61
-------
is built into the utility systems. The maximum summer peak load
projected for 1985 is not greater than 89 percent of total re-
sources due to the presence of excess capacity. Table 3-17 indi-
cates that the excess capability above the peak load varies from
11 to 24 percent. The utility industry is required to maintain
these types of excess capabilities to insure their ability to
meet consumer demand, to allow for growth of demand, and to pro-
vide emergency power if a generating unit or units, a transmission
line, or an interconnection should fail.
To maintain this generating capability above maximum
demand, a general reduction in generating capability that occurs
for any reason including the application of FGD must be offset.
The effect of the reduction in generating capability due to FGD
unit availability was estimated assuming that reductions would
be offset by the addition of more generating capacity.
It is important to note that the data in Table 3-15 are
for 1985. Because lead times for construction of new coal gener-
ating units range from 7 to 10 years, 1985 is probably the first
year that the effects of the NSPS would be seen. Because of the
projected rapid growth in requirements for new coal units brought
on by the energy crisis, it is important to estimate the effects
of a revised NSPS in years beyond 1985. The amount of new coal
generating capability beyond 1985 that would be subject to any
revised new source performance standards has been estimated as
133,800 Mw in 1988 and 386,800 Mw in 1998 (WO-139). The 1988
estimate includes the 1980-1988 projects while the 1998 estimate
includes 1980-1998. The additional generating capacity required
to offset the reduction in generating capability caused by FGD
is thus expected to increase significantly between 1985 and 2000
due to this threefold increase in new coal capacity. Consequently,
62
-------
the effects of FGD on reliability will probably increase in mag-
nitude in the future. Rough estimates of this effect, obtained
by analyzing all new coal as a single unit with a single scrubber
unit composed of one module, are given in Table 3-18. Average FGD
availabilities of 70, 80, and 90 percent were assumed. These
additional generating requirements are estimates for the entire
United States. They cannot be apportioned or extrapolated to
any specific generating system.
TABLE 3-18.
ESTIMATE OF MEGAWATTS OF ADDITIONAL
GENERATING CAPACITY REQUIRED TO
OFFSET THE EFFECT OF FGD IN 1988
AND 1998
Year
1988
1998
FGD Availability3
707c
40,100 Mw
116,000 Mw
80%
26,800 Mw
77,400 Mw
90%
13,400 Mw
38,700 Mw
*0ne FGD unit composed of one module on a single generating
unit representing all new coal capacity.
63
-------
4.0 IMPROVEMENTS TO FLUE GAS DESULFURIZATION
AVAILABILITY
Solutions to some of the problems encountered by lime/
limestone FGD systems have been found. The system components
which are subject to high failure rates have also been identi-
fied. Methods to overcome these high failure rates such as
sparing or maintenance have subsequently been examined. Certain
measures that have resulted or can result in high levels of
system availability have also been defined by the FGD industry.
A discussion of each system operating experience as to problems
and solutions follows in Section 4.1. Component failures are
then examined in Section 4.2. Finally, measures to improve
availability are presented in Section 4.3.
4.1 Operating Experience for Existing Systems
The problems which have been encountered and solved
at seven existing FGD systems were documented. The applicability
of the solutions at one site to other sites was also examined.
The seven systems surveyed were Will County No. 1, La Cygne No. 1,
Phillips, Cholla No. 1, Green River, Sherburne County No. 1,
and Bruce Mansfield No. 1. The operating problems, solutions
or approaches to solutions, and unit maintenance are given in
Table 4-1.
A similarity in the problems from system to system
is observed. These problems can be generally grouped as fol-
lows: (1) erosion of pumps, seals, and control valves; (2) de-
posits, plugging, or scaling on scrubber internals, nozzles,
strainers, mist eliminators, and in-line reheaters; (3) corro-
sion of fans, reheaters, ducts, and stacks; and (4) vibration
and poor thermal mixing with direct-fired reheaters. Solutions
64
-------
TABLE 4-1.
SUMMARY OF PROBLEMS, SOLUTIONS, AND MAINTENANCE
AT EXISTING FGD SYSTEMS
Unit
Wi11 County
No. 1
(Commonwealth
Edison)
Operating Problems
Unit Maintenance
Nuking and scaling in demister aad
occasional ly the reheater.
Corrosion and erosion of reheater tubes.
Vibration of and deposition on reheater tubes.
Limestone blinding.
Erosion and plugging of spray nozzles.
internal a,nd external buildup of deposits
on venturi nozzles.
Fan vib rat ions.
Operation with high S coal resulted in high
slurry carryover, demidter plugging, reheater
coil fouling and leaks, massive absorber
scale, fan rotor scale.
Convert to mor^ open dusi^u mlsr el ituin.iLor. Kupank ing pumps,
Change constant demisl IT uiidurspr^y to 1 ru^h plugged siuriy feed
water and install intermittent overspray. lines, wash reheater
Improved mist elimination. Repair in tubes. dou° fery I'3 T"?'
1 wash fans when unit is
baffles and rebracing stopped vibration. Im- down, repair corrosion
proved 2-stage demister reduced deposition. areas.
Remove scrubber from service.
Change nozzles.
Clean nozzles.
Clean and rebalance fans.
References
RO-243
1S-021
PE-259
CO-596
CH-393
RO-314
RE-26 3
Ul
I, a Cygne No. 1
Power
s City
& Light)
Corrosion of reheat tubes.
Deposits on induced draft fan blades.
Corrosion of induced draft fans.
Corrosion of duct works after ID fans.
Ei'osion in Venturi nozzles .
Corrosion of carbon steel lances for demister
undcrwash.
Rubber lining flaking off recycle blurry system.
Hard scale, especially in absorber trays.
Deposits in reheaters , deniisters , sumps , ven-
turi walls, nozzles, strainers.
Sludge deposits in elevated duct work between
fans and stack.
Instability of I.D. fans develops at full power
and trips boiler safety controls.
Erosion and corrosion uf nil at eliminators.
Corrosion of stack
ac id condensation.
structure due to
Replace some tubes with resistant materials
and remove some tubes. Inject hot air from
combustion ai r preheater at. reheater inlet.
Results in 70 MW derating of boiler due to
limiting fan capacity.
Shut down fan for high pressure washing.
Test coatings and corrosion resistant metals.
Replace expansion joints and some duct panels.
Install hydroclone in Blurry recycle line-
Closely control pll to reduce scale.
Large maintenance crew.
Derate plant to avoid activation of safety
controls.
Replace with thick, corrosion resistant, re-
inforced plastic assemblies.
Coat stack wiLli resistant material.
Clean one moduJe each CH-393
night on a rotating CO-596
basis. Cleaning re- KO-243
quires 3 men 10-12 RO-314
hours for each module. PE-259
Areas requiring atten- MC-293
tion: reheater pluggage, MC-289
demistet pluggage, ven- MC-295
turi well and nozzle
deposits, sump accumula-
t i on. Fa u.s a re shut down
4-10 houru every 4-5 days.
Scrubber operating and
maintenance force: 33 op-
erating, 16 maintenance,
2 adniinistiutive. Total-51.
-------
TABLE 4-1 (Continued).
SUMMARY OF PROBLEMS, SOLUTIONS, AND MAINTENANCE
AT EXISTING FGD SYSTEMS
Unit Operating Problems
I'titlJlps Solids buildup on Induced draft fans.
Corrosion resistant coatings on fans broke off
(l)ii(iuesn" causing fan intoalance.
'•i^hO Acid condensation near the base of the brick-
lined stack penetrated the mortar.
Corrosion and erosion at the fan welds.
Solutions
Reduced by redesign of spray washers.
Adherent coatings have not been found.
Mortar In the brick-lining was repaired.
Automatic washing is not solution. Use
resistant materials.
Unit Maintenance
General operation has
one of four trains
out continually for
repairs, cleaning,
and preventive main-
tenance.
References
RO-243
KN-039
CO-596
CH-393
RO-314
PE-107
PE-265
PE-266
PE-267
Erosion of slurry recirculatlon pump impellers.
Pump seals also erode.
Solids buildup in scrubber Icop have prevented
closed loop operation.
Rubber-lined plug-type bleed valves eroded.
Solids deposition in scrubber restricts gas
flow.
In-line fuel-oil rehcnter is not operational.
Corrosion in burner and chamber. Poor thermal
mixing resulted in hot spots in ducts down-
stream of reheater.
Alternate designs and materials were tested.
Not solution as yet.
Blowdown a bleed stream until solution is
found.
Replace with pinch-type valves.
Vessel must be completely cleaned about every
1400 service hours. Cleaning requires
1400-1700 man-hours. One boiler was routed
through the scrubber bypass to prevent loss
of boiler capacity (Aug 75-Jan 77).
Operating solutions have not been successful.
Every 3,000-5,000 ser-
vice hours shut a train
down for one month in-
spection, cleaning, and
repairs. Every 6 months
isolate a thickener for
Inspection, cleaning, and
repairs. 8 maintenance
and 13 operators full-time.
Also average 7.7 men per
day from craft union.
Chul hi Nn. I
Public
Si- rv i ce)
Cor ros inn n I rohe.'it or t ubt-'s tmd due L expnns I on
joints due to acid runnff from chtrr walls.
Impeller corrosion on punips.
Plugging of packed tower and mist eliminators
when system is brought down.
Vibration of reheater tubes.
Scaling and plugging first stage demister.
Plug nozzles.
Solids buildup in pump seal water.
Plugged process lines.
Erosion in pumps.
r
-------
TABLE 4-1 (Continued).
SUMMARY OF PROBLEMS, SOLUTIONS, AND MAINTENANCE
AT EXISTING FGD SYSTEMS
Un f t
Green River
(Kentucky
Utilities)
Ope rat LHJJ; Pmb It-tus
Failure ol ruc.yc It*, puni|>y and feed tank
agitator.
Frozen lines.
Deposition in pumps and tanks.
Failure of rubber-lined pump impel lers.
Vibration in ID booster fan.
Deterioration of stack liner.
Plugging of contactor bed.
Failure of gland packing in slurry recycle
pumps.
So LtiL i
Repair.
Thaw and repair.
Clean out pumpa and tanks.
Replace with unlined impellers.
Repair.
Repair and replace liner.
Wash out manually when unit is down.
Uul t Mtii utemmce
References
Areas requiring atten- PE-259
Lit.n: recycJe pumps, AW-184
pond pumps, contactor SI-174
bed, deuJ&turs, agitators.
Maintenance represents
about 23% of total scrub-
ber operating costs.
Work force includes 4 op-
erators and 1 instrument
man. Utility maintenance
crews are presently used
but scrubber maintenance
personnel may be added in
the future.
County No, 1
(Northern
States Power
Co.)
Slurry bypassing strainers ahead of recycle
pumps and plugging nozzles.
Soot blower not operating properly.
Erosion of spray nozzles.
Erosion of sidewalls of reaction tank.
Erosion of valves.
Mud/scale in marble bed.
Deposition of soft solids in mist eliminators
and reheater.
External corrosion of reheater tubes.
Instrumentation problems.
Failure of rubber lining. Subsequent plugging
of downstream nozzles and headers.
Wear and sealing problems wlLti spray water pump.
Possible solution is replacement wiih perfor-
ated plate and soot blower. Presently clean
nozzles during maintenance.
Replace with ceramic nozzles.
Use stainless steel wear-plate as temporary
solution.
Breakup and wash manually.
Modifications have been attempted Lo resolve
stress problem.
Two technicians to maintain instruments.
Remove rubber lining. Carbon steel has now
failed from erosion.
Evaluate new materials for pump internals and
rubber-lined pump.
Two modules are checked PE-25J*
and cleaned each night. RO-243
Areas requiring atten- KR-115
tlon: nozzles, venturi, KR-116
marble bed, demisters.
reheater, valves, pumps.
Each module requires 2-8
hours for maintenance.
Maintenance1, crews-12 men:
6 days/week fur #1 and 2.
A crew of 35 is required
to maintain scrubber oper-
ations for Sherco #1 and
12.
Bruce Mans-
field NO. 1
(Pennsylvania
Power Co.)
Inadequate mist elimination.
Demister plugging.
Vibration in reheater.
Corrosion of rubber-lined booster fan linings.
Erosion of first stage venturi lining followed
by corrosion.
bubbling of stack lining resulting in corrosion
of meLai beneath.
Plugging of strainers.
Erosion of control valves.
Erosion of pumps.
Attempt to increase capacity with little success. Not available.
Repair rubber linings.
Install wear plates.
Repair lining.
Test materials of construction.
WO-130
-------
are also often similar and, therefore, often applicable from
one system to the other. However, any application must be ex-
amined on a case-by-case basis. Resistant materials or coatings
have generally been used in attempts to overcome erosion and
corrosion problems. Careful control of the scrubber operation
and the prevention of solids entrainment in the gas have been
partially successful in ,preventing deposits buildup, plugging,
or scale. The use of large operating and maintenance crews
in addition to control of the chemistry appears to be the most
dependable solution to plugging and scaling at this time, how-
ever. This approach also applies to erosion and corrosion prob-
lems in some instances. Workable solutions for the direct-
fired reheater problems have not been reported.
4.2 Flue Gas Desulfurization Component Failures
The system components with high failure rates were
found to be primarily the same items identified in the previous
section on operating problems. These items include the slurry
pumps, pump gland water system, nozzles, control valves, fans,
mist eliminators, and reheaters.
The slurry pumps, gland water system, and control
valves can be readily spared in any system to a sufficient
degree that the effect of high failure rates for these items
can be reduced. On the other hand, the nozzles, fans, mist
eliminators, and reheaters are unique to each module and, there-
fore, cannot be readily spared within a module. As a result,
the only way these items can be spared is to spare the entire
module. This is much more expensive than the internal sparing
of pumps, gland water systems, or control valves. Nevertheless,
the costs can be justified if sparing a module can significantly
reduce the effect of the high failure rates of these components.
68
-------
Rotating maintenance, such as that performed at La
Cygne and Sherburne County, can also significantly reduce the
failure rates of these components. Frequent inspection and
maintenance by a crew associated exclusively with the FGD
system has proven very successful at both La Cygne and Sher-
burne County. Use of a separate crew trained to operate the
FGD system and an instrumentation maintenance crew can also
help to reduce failure rates in general.
4.3 Measures to"Improve Flue Gas Desulfurization
Availability
Various measures have been or can be used to main-
tain high levels of FGD availability. These measures can be
grouped into maintenance methods, operating techniques, and
design concepts. These three types of measures are defined
and assessed in this section.
Maintenance Methods
The extensive maintenance programs applied at La Cygne
and Sherburne County have successfully maintained a high system
availability. The important factors in these maintenance
programs are: (1) taking one or more modules off-line each
night for inspection and cleaning, (2) use of a separate
maintenance crew trained to work on the FGD system, and (3)
a general dedication to gaining a better understanding of the
system and how to maintain it better.
The areas or components in the system that should
be given the most attention vary somewhat depending on the
design. For most systems they will include the nozzles,
69
-------
headers, strainers, scrubber internals, pump packing and im-
pellers, mist eliminators, fans downstream of the scrubber,
reheaters, agitators, valves, and slurry lines.
Operating; Techniques
There are several operating techniques that have
been or can be used to contribute to maintaining a high FGD
system availability. Over and underspray of mist eliminators
(demisters) removes deposits from the mist eliminators. Open
loop oepration of the demister wash cycle is more effective
than the use of only recycle water. Fresh water is used to
dilute the recycle water to reduce the potential for scale
formation on the demister. Increased utilization of the lime
or limestone also improves demister operation by reducing the
quantity of calcium ion entrained in the gas which in turn
reduces the scaling potential.
Operating with an open loop water balance has also
benefited FGD systems. The discharge of water from the system
reduces the chloride and dissolved solids concentrations in the
process water. The chlorides promote corrosion while the dis-
solved solids enhance the potential for scaling and plugging.
However, discharged water quality considerations must be con-
sidered. Operating the system subsaturated with respect to
sulfates also reduces sulfate scaling potential.
Automatic pH and process control result in more
stable operation and tend to prevent major failures such as
massive scaling. On-site routine chemical monitoring of rel-
ative saturations of sulfite and sulfate can aid in the detec-
tion of scaling conditions.
70
-------
Finally, a staff of operators and technicians to work
with the FGD system on a daily basis is very important. As in
the maintenance area, the quality of the operating crew can sig-
nificantly affect availability.
Design Concepts
Each of the FGD systems examined in this study dif-
fers somewhat in design concept. Some of the concepts that
have been or potentially can be successful in enhancing avail-
ability are: (1) dry particulate removal before the FGD system
with an electrostatic precipitator (ESP), (2) dry flue gas
booster fan between the ESP and scrubber rather than a wet fan
after the scrubber, (3) adequate redundancy of pumps, valves,
lime/limestone feed systems, packing gland water systems, etc.,
(4) spray tower scrubber configuration, (5) adequate instrumen-
tation for pH, S02, additive use, etc. with automatic controls,
(6) indirect reheat of flue gas, and (7) adequate particle
dropout area to reduce solids carryover to the mist eliminators.
Dry particulate removal overcomes the erosion and
corrosion problems of wet particulate removal. A dry fan that
is upstream of the scrubber is not subject to the deposits, ero-
sion, and corrosion that a wet fan encounters. The wet fan is
moving a wet gas that: (1) has entrained solids that will stick
to the fans, and (2) contains acid that can condense on the fan
or be picked up by deposits on the fan. An example is Bruce
Mansfield. Units No. 1 and No. 2 have wet particulate removal
and wet fans. The problems associated with No. 1 were presen-
ted in Section 4.1. Unit No. 3 will have an ESP and a dry fan.
A spray tower scrubber is another concept being con-
sidered. Spray towers can reduce the erosion and plugging
problems associated with some other types of contactors. Bruce
71
-------
Mansfield and Sherburne County are examples. Bruce Mansfield
No. 1 and No. 2 have two-stage Venturis. No. 3 will have a
horizontal spray tower. Sherburne County No. 1 and No. 2, which
use a marble bed contactor, is examining substitution of a spray
tower for the marble bed.
Automatic controls are being installed by Sherburne
County No. 1 and No. 2 and by Phillips to improve operation of
these systems. Phillips is also installing a redundant lime
feed system.
Indirect reheat is more reliable than other types of
reheat. Indirect reheat is accomplished by heating air by steam
or hot water heat transfer, direct combustion, etc. outside the
flue gas duct and, then, combining this hot air with the flue
gas in the duct. Indirect reheat avoids the placement of a
heat exchanger in the flue gas stream or firing a direct combus-
tion unit in the duct.
An adequate particle dropout area before the mist
eliminator reduces the carryover of large particles to the mist
eliminators by the flue gas. The distance between the top of
the contacting zone and the mist eliminator and the velocity
of the gas are two factors that affect the dropout area. A
turn in the duct between the scrubber and the mist eliminator
also reduces the quantity of particles in the gas.
72
-------
APPENDIX A
RELIABILITY/AVAILABILITY
DEFINITIONS USED BY EEI AND PEDCo
73
-------
DEFINITIONS USED BY EDISON ELECTRIC INSTITUTE (ED-043)
A. EQUIPMENT DEFINITIONS
1. Non-header Unit
2. Header Unit
3. Major Equipment
4. Component
5. Maximum Dependable
Capacity (MDC)
Unit in which a single boiler is
connected solely and independently
to a given turbine-generator.
Unit in which the turbine-generator
is not solely and independently
connected to single boiler.
Major group of equipment within a
unit, such as: boiler, reactor,
generator, steam turbine, condenser,
Part within a "major equipment"
group, such as: superheater tube,
governor, buckets, boiler feed
pump.
The dependable main-unit capacity
winter or summer, whichever is
smaller.
B. OPERATION AND OUTAGE DEFINITIONS
1. Available
2. Base Loading
3. Cranking Loading
4. Cycling Loading
5. Economy Outage
6. Forced Outage
The status of a unit or major piece of
equipment which is capable of ser-
vice, whether or not it is actually
in service.
When a unit is generally run at
or near rated output.
When a unit is generally shut down
on standby for auxiliary power
during emergency.
When a unit is generally run but
at a load which varies widely with
system demand.
(See Reserve Shutdown)
The occurrence of a component failure
or other condition which requires
that the unit be removed from service
immediately or up to and including
the very next weekend.
74
-------
Forced Partial Outage
8. Maintenance Outage
10,
Non-curtailing Equip-
ment Outage
Non-operating Equip-
ment Test
11. Outage Cause
12. Peaking Loading
13. Planned Outage
14. Reserve Shutdown
The occurrence of a component
failure or other condition which
requires that the load on the unit
be reduced 2% or more immediately
or up to and including the very
next weekend.
The removal of a unit from service
to perform work on specific com-
ponents xvhich could have been post-
poned past the very next weekend.
This is work done to prevent a
potential forced outage and which
could not be postponed from season
to season.
The removal of a specific component
from service for repair, which
causes no reduction in unit load
or a reduction of less than 2%.
A scheduled test or required oper-
ation of a back-up system which is
not normally operating.
A component failure, preventive
maintenance, or other condition
which requires that the unit or
a component be taken out of service
or run at reduced capacity.
When a unit is generally shut down
and is run only during high demand
periods.
The removal of a unit from service
for inspection and/or general over-
haul of one or more major equipment
groups. This is work which is
usually scheduled well in advance
(e.g., annual boiler overhaul, five-
year turbine overhaul).
The removal of a unit from service
for economy or similar reasons.
This status continues as long as
the unit is out but available for
operation.
75
-------
15. Scheduled Partial
Outage
16. Unavailable
The occurrence of a component
failure or other condition which
requires that the load on the
unit be reduced 2% or more but
where this reduction could be
postponed past the very next weekend.
The status of any major piece of
equipment which renders it inoper-
able because of the failure of a
component, work being performed
or other adverse condition.
C. TIME DEFINITIONS
1. Available Hours (AH)
2. Demand Period
3. Economy Outage Hours
(See Reserve Shutdown
Hours) (TEOE)
Forced Outage Hours
(FOH)
Forced Partial
Outage Hours (FPOH)
The time in hours during which a unit
or major eauipment is available;
SH + RSH.
The time interval each day which
is the period of maximum demand on
a particular system.
The theoretical value of Economy Outage
Hours (TEOH) is the difference between
Available Hours and Service Hours.
If the TEOH differs by less than 1%
with the Economy Outage Hours reported
at the end of the year, they are
considered equal and flagged with
Code 1. If the difference is more
than 1%, but less than 10%, they are
flagged with Code 3; but the
reported Economy Outage Hours are
still used. However, if the difference
is greater than 10%, the calculated
value TEOH is used, and Code 2 is a
flag that Economy Outage Hours have
been derived.
The time in hours during which a unit
or major equipment was unavailable due
to a Forced Outage.
The time in hours during which a
unit or major equipment is unavailable
for full load due to a forced partial
outage.
76
-------
6. Hours Waiting (HW)
Maintenance Outage
Hours (MOH)
8. Period Hours
(PH)
9. Planned Outage Hours
(POH)
10. Reserve Shutdown
Hours (RSH)
11. Schedule Partial
Outage Hours (SPOH)
12. Service Hours (SH)
13. Unit Years (UY)
14. Work (Manhours Worked)
(MH)
That portion of time for any outage
during which no work could be
performed. This includes time for
cooling down equipment and shipment
of parts. This is time that could
not be affected by a change in work
schedule or the number of men worked.
The time in hours during which a
unit or major equipment is unavailable
due to a maintenance outage.
The clock hours in the period under
consideration. (Generally one year)
The time in hours during which a
unit or major equipment is unavailable
due to a planned outage.
Reserve shutdown duration in hours.
The-time in hours during which a unit
or major equipment is unavailable
for full load due to a scheduled
partial outage.
The total number of hours the unit
was actually operated with breakers
closed to the station bus.
This term is the common denominator
used to normalize data from units of
the same type with different lengths
of service. The following example
contains 20 UY of experience from
4 units.
Unit A B C D 4
Years in Service 8372 20
The total number of manhours worked on
or off site to accomplish repairs.
D. EQUATIONS
1. Average Forced Outage
Duration
2. Capacity Factor
3. Component Outage
Severity Index
77
(Summation of FOE)/(Number of
Forced Outages)
[(Total Generation in MW-Hr)/(PH x MDC)"j 10
The average number of forced outage
hours of a specific component per
incident.
-------
Equivalent Forced
Outage Rate (EFOR)
(for each forced
partial outage, an
equivalent full load
outage duration is
calculated to include
the effect of partial
as well as full forced
outages on the forced
outage rate)
5. Forced Outage Incident
Rate
6. Forced Outage Rate
7. Forced Outage Ratio
8. Operating Availability
9. Output Factor
10. Service Factor
EFOR is calculated as follows:
TE = FPOH ( CR/CF )
WHERE:
TE is equivalent forced outage
time
CR is size of reduction or derating
from full load
CF is rated capacity
THEN:
EFOR =100 ((TF + TES)/(TO + TF +
TAS + TPS))
WHERE:
TF is total full forced outage
time
TO is total operation time at 100%
availability
TAS is sum of actual forced partial
outage times
TES is sum of equivalent forced
outage times
TPS is sum of equivalent scheduled
partial operating times
(Forced Incidents)/(Forced +
Maintenance + Planned Incidents) I 100
[FOR / (SH + FOH)] 100
FFOH/(Total Unavailable Hours)"] 100
[AH/PH] 100
(Total generation in MW-Hr) x 100/
(SH x HDC)
100
78
-------
11. Relative Mechanical Relative Mechanical Availability
Availability (RMA) is a form of Operating Availability
adjusted to show relative effort.
The prime assumption is that most
outage time is affected by work
schedules and crew sizes. Relative
Mechanical Availability uses an
Adjusted Outage Time (AOT) based
on effort. Manhours worked is a
measure of effort which is reasonably
independent of work schedules and
crew sizes. Manhours worked (MH)
divided by a standard work force
(SWF) gives a derived time worked
based on effort. If we assume a
round-the-clock schedule, then this
derived time worked is almost a
derived outage time based on effort.
The difference is the amount of
outage time which is independent
of effort called Hours Waiting (HW),
See Appendix C-6. An arbitrary
assumption of ten men for the
standard work force gives:
AOT = HW + MH/10
Then substituting AOT for outage
time in the equation for operating
availability gives:
RMA = [(PH-AOT)/PH] 100
= f(PH-(HW + MH/10) )/PH] 100
79
-------
DEFINITIONS USED BY PEDCo ENVIRONMENTAL
oo
o
Boiler Capacity Factor
Boiler Utilization Parameter
Efficiency,
Particulates
SO;
FGD Availability Factor
FGD Reliability Factor
FGD Operability Factor
(kWh generation in year)/(maximum continuous generat-
ing capacity in kW x 8760 hr/yr).
Hours boiler operated/hours in period, expressed as a
percentage.
Operational - The actual percentage of particulates
removed by the FGD system and the particulate control
devices from the untreated flue gas. All others - The
design efficiency (percentage) of particulate removed
by the FGD system and the particulate control devices.
Operational - The actual percentage of S02 removed
from the flue gas. All others - The design efficiency.
Hours the FGD system was available for operation
(whether operated or not)/hours in period, expressed
as a percentage.
Hours the FGD system operated/hours FGD system was
called upon to operate, expressed as a percentage.
Hours the FGD system was operated/boiler operating
hours in period, expressed as a percentage.
FGD Utilization Factor
Hours FGD system operated/hours in period, expressed
as a percentage.
-------
APPENDIX B
INTERACTION OF SPARE MODULES AND UTILITY
LOAD CURVES WITH THE ABILITY TO MEET CONSUMER DEMAND
81
-------
Two aspects of the assessment of the effect of FGD
availability on electric utilities have been examined in only
a preliminary manner in this study. These aspects are:
(1) use of spare modules in an FGD unit to improve the avail-
ability of the unit, and (2) the interaction of outage rates with
the load duration curve to assess the ability to meet consumer
demand. Each of these aspects will be discussed in more detail
in this Appendix.
The results of the use of spare modules were deter-
mined by calculating the probability of the various numbers
of modules being available for FGD units with and without a
spare module. It was assumed that the demand on the utility
plant was always equal to the available capacity. Also the
availability of different plants and different modules is
independent .
The three equations used to calculate these proba-
bilities are:
£ (B-l)
(B-2)
L
P = 1 - S P. (B-3)
0 a
P = probability that generating station with
FGD can operate at full capacity
P = probability that generating station with
FGD can operate at &/L of full capacity
82
-------
PQ - probability that generating station with
FGD is not available
A = availability of generating station
B = availability of each FGD module
S, = number of FGD modules available
L = number of FGD modules required at
full capacity
K = number of spare FGD modules at full
capacity
The availability for a single generating plant without
FGD was assumed to be 75 percent. A five module FGD unit was
selected for examination. The four cases examined were: (1) FGD
modular availability of 70 percent with no spare module, (2) FGD
modular availability of 70 percent with one spare module, (3) FGD
modular availability of 90 percent with no spare module, and
(4) FGD modular availability of 90 percent with one spare module.
The results of the probability calculations are shown in
Table B-l.
A spare module is particularly important at full
capacity. For a 90 percent modular availability, the generating
station availability increases from 44 to 66 percent due to the
presence of a spare module. The impact of the spare module is
lessened as the load on the FGD unit is reduced. For example, a
generating station at 80 percent capacity would require four
modules. The availability of the FGD unit with 90 percent modular
availability increases from 69 percent to 73 percent (P* plus P5)
due to the spare module. This difference is obviously not as
significant as for operation of the generating unit at full capacity,
83
-------
P5
Pi
P3
P2
Pi
p
Table B-l. Probability Determination for
a Generating Station with FGD
A = .75 and L = 5
B = .70
K=0 K=l
B =
K=0
.90
K=l
.13
.27
.23
.10
.02
.25
32
24
,14
04
01
25
.44
.25
.05
.01
.00
.25
.66
.07
.01
.01
.00
.25
Next, consider the interaction of the outage rate with
a unit load duration curve to assess the ability to meet consumer
demand. An example load duration curve is shown in Figure B-l.
The load is observed to be greater than 90 percent of capacity
only about 5 percent of the time. Furthermore, the load is above
80 percent of capacity about 35 percent of the time. In other
words, the demand on the utility is less than or equal to 80
percent of capacity for 65 percent of the time.
Again, assume five modules must be available for
operation of the generating unit at full capacity. At 80
percent of capacity, four modules would then be required.
Therefore, the load can be met about 69 percent of the time
with a modular availability of 90 percent and no spare module
(Pij plus P5 in Table B-l). A spare module allows load to be
met about 73 percent of the time.
84
-------
oo
Ui
100
90
80
70
~ 60
>-
t
O 50
a.
< 40
30
20
10
10
20 30 40 50 60
TIME (%)
70
80
90
100
Figure B-l. Example Load Duration Curve
SOURCE: HA-697
-------
This brief example merely serves to point out the
importance of the load duration curve in any evaluation of the
ability of a utility to meet consumer demand. The curve in
Figure B-l is only an example and should not be applied to any
specific generating unit. Further study is necessary to apply
this theory to actual systems.
86
-------
BIBLIOGRAPHY
87
-------
BIBLIOGRAPHY
AN-184 Anderson, Andy, Private communications. Kentucky
Utilities, 12 May 1977.
BE-478 Beard, J. B. , Private communications, Kentucky
Utilities Co., Lexington, KY, 21 July 1977.
CH-393 Choi, P. S. K. , et al., Stack gas reheat for wet flue
gas desulfurization systems. final report. EPRI FR-
361, RP 209-2. Columbus, OH, Battelle Columbus Lab.,
Feb. 1977.
CO-596 Conkle, H. N. , H. S. Rosenberg, and S. T. DiNovo,
Guidelines for the desjLgn of mist eliminators for
lime/limestone scrubbing systems, final report.
EPRI FR-327, RP 209. Columbus, OH, Battelle Columbus
Lab. , Dec. 1976.
CO-RF-700 Cook, V. M. , R. J. Ringlee, and J. P. Whooley,
"Suggested Definitions Associated with the Status of
Generating Station Equipment and Useful in the Appli-
cation of Probability Methods for System Planning and
Operation," IEEE Conference Paper C-72-599-9, Sponsored
by IEEE Application of Probability Methods Subcommittee -
Ad Hoc Working Group on Definitions, IEEE Power Engineer-
ing Society, 1972.
DI-R-161 Dickerman, James C., et al., Comparison of the avail-
ability and reliability of equipment utilized in the
electric utility industry, draft report. EPA Contract
No. 68-02-1319, Task 12, Radian Project No. 200-045-62.
Austin, TX, Radian Corporation, December 1976.
-------
ED-043 Edison Electric Institute, Prime Movers Committee,
Equipment Availability Task Force, Report on equip-
ment availability for the ten-year period, 1965-1974.
EEI Pub. No. 75-50, NY, Nov. 1975.
ED-059 Edison Electric Institute, Prime Movers Committee,
Equipment Availability Task Force, EEI equipment
availability summary report on trends of large mature
fossil units categorized by fuel and in commercial
operation prior to January 1, 1971. NY, Oct. 1976.
ED-060 Edison Electric Institute, Prime Movers Committee,
Equipment Availability Task Force, Equipment avail-
ability data reporting instructions. N.Y., Jan. 1976.
FL-090 Flora, Tim, Private communication, Pennsylvania Power
Co., Shippingsport, PA, 13 October 1977.
HE-258 Heacock, Frank A., Jr. and Robert J. Gleason, "Scrubber
surpasses 90% availability", Elect. World 1975 (May
15), 42.
IS-021 Isaacs, Gerald A. and Fouad K. Zada, Survey of flue
gas desulfurization systems, Will County Station,
Commonwealth Edison Co., EPA-650/2-75-0571. Cincin-
nati, Ohio, PEDCo-Environmental Specialists, Inc.,
Oct. 1975.
KN-039 Knight, R. Gordon and Steve L. Pernick, "Duquesne
Light Company, Elrama and Phillips Power Stations
lime scrubbing facilities", in Proc., Symposium on
Flue Gas Desulfurization, New Orleans, March 1976,
vol. 1. Research Triangle Park, NC, EPA, 1976, pp.
205 ff.
89
-------
KR-115 Kruger, R.J. and M.F. Dinville, "Northern States
Power Company Sherburne County Generating Plant
limestone scrubber experience". Presented at the
Utility Representative Conference on Wet Scrubbing,
Las Vegas, NV, Feb. 1977.
KR-116 Kruger, Rick, Private communication. Northern States
Power Co., 16 May 1977.
MC-289 McDaniel, Clifford F., "La Cygne Station Unit No. 1,
wet scrubber operating experience". Presented at
the EPRI-FEA Coal Blending & Utilization Conference,
Des Mbines, IA, June 1976.
MC-290 McDaniel, Clifford F., "La Cygne Station Unit No. 1,
wet scrubber operating experience". Presented at
the EPR Flue Gas Desulfurization Symposium, New Orleans,
March 1976.
MC-293 McDaniel, Clifford F,, "La Cygne Station Unit No. 1,
wet scrubber operating experience". Presented at
the Utility Wet Scrubber Conference, Las Vegas, NV,
Feb. 1977.
MC-295 McDaniel, Cliff, Private communication. Kansas City
Power and Light, 16 May 1977.
MU-074 Mundth, Lyman K., "Operational status and performance
of the Arizona Public Service Co. Flue Gas desulfuri-
zation system at the Cholla Station". Presented at
the Flue Gas Desulfurization Symposium, Atlanta, GA,
Nov. 1974.
90
-------
MU-155 Mundth, Lyman K., Private communication, Arizona Public
Service Co., Phoenix, AZ, 20 July 1977.
NA-325 National Electric Reliability Council, 6th Annual
Review of Overall Reliability and Adequacy of the
North American Bulk Power Systems. July 1976.
PE-107 Pernick, Steve L., Jr. and R. Gordon Knight, "Duquesne
Light Co. Phillips Power Station lime scrubbing facil-
ity." Presented at the Flue Gas Desulfurization Sym-
posium, Atlanta, GA, 1974.
PE-259 PEDCo Environmental, Inc., Flue Gas Desulfurization
systems, Jan., Feb., March 1977, summary report, EPA
Contract No. 68-02-1321, Task No. 28, Cincinnati, OH,
1977.
PE-265 Pernick, Steve L. , Jr. and R. Gordon Knight, "Duquesne
Light Company Phillips Power Station Lime Scrubbing
Facility", paper no. 75-64.2. Presented at the APCA
68th Annual Meeting, Boston, MA, June 1975.
PE-266 Pernick, Steve L., Jr., "Duquesne Light Company's
experiences in flue gas desulfurization". Presented
at the National Governor's Conference on Coal Utili-
zation- -Scrubbers and Other Options, Annapolis, MD,
November 1975.
PE-267 Pernick, S.L., Jr., Private communication, Manager,
Environmental Affairs, Duquesne Light, Pittsburgh,
PA, 9 December 1976.
91
-------
PE-287 Pernick, S. L., Private communication, Duquesne Light,
Pittsburgh, PA, 11 August 1977.
PE-288 PEDCo Environmental Inc., Summary report, Flue gas
desulfurization systems, June - July 1977. EPA
Contract No. 68-01-4147, Task No. 3. Cincinnati, OH,
1977.
RE-263 Reed, John, Private communication, Commonwealth Edison
Company, Chicago, 111., 20 May 1977.
RO-243 Rosenberg, H.S., et al., Status of stack gas control
technology Research Project 209, final report, Part 1.
Columbus, OH, Battelle Columbus Lab., Aug. 1975.
RO-314 Rosenberg, H.S. and R.G. Engdahl, Progress toward
reliable equipment to control emissions of SOx and
NOx. Columbus, OH, Battelle Columbus Lab., Oct 1976.
SI-174 Sitnko, Sandy, Private communication. Kentucky Util-
ities, 16 May 1977.
i
US-391 U.S. Atomic Energy Commission, Reactor safety study.
An assessment of accident risks in U.S. commercial
power plants, final report, 9 vols. WASH-1400, NUREG-
75/014. Summary and main reports, appendices 1-11.
Oct. 1975.
WO-130 Workman, Keith, Private communication. Pennsylvania
Power Co., 13 May 1977.
WO-139 Woodard, Ken, Private communication, EPA, OAQPS
Durham, NC, 4 October 1977.
92
-------
TECHNICAL REPORT DATA
(Please read iKttructioits on the reverse before completing)
REPORT NO.
EPA-600/7-78-031b
2.
3. RECIPIENT'S ACCESSION NO.
.T.TUE AND SUBTITLE The Effect of Flue Gas Desulfurization
Availability on Electric Utilities
Volume n. Technical Report
5. REPORT DATE
March 1978
6. PERFORMING ORGANIZATION CODE
. AUTHOR(S)
R.D. Delleney
8. PERFORMING ORGANIZATION REPORT NO.
. PERFORMING ORGANIZATION NAME AND ADDRESS
Radian Corporation
P.O. Box 9948
Austin, Texas 78766
10. PROGRAM ELEMENT NO.
EHE624
11. CONTRACT/GRANT NO.
68-02-2608, Task 7
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
Task Final; 4-12/77
14. SPONSORING AGENCY CODE
EPA/600/13
15.SUPPLEMENTARY NOTES EPA prOject officers are J.E. Williams (IERL-RTP, 919/541-2483)
and K. R. Durkee (OAQPS/ESED, 919/541-5301).
is. ABSTRACT rpne repOrt giv6s results of an analysis of the effect of the availability of a
flue gas desulfurization system on the ability of an individual power plant to generate
electricity at its rated capacity. (The availability of anything is the fraction of time
it is capable of service, whether or not it is actually in service.) Also analyzed are
its effects on a power generating system (a group of several coal-, oil-, and gas-
fired power plants plus nuclear and hydroelectric plants).
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
. COSATI Field/Group
Air Pollution
Flue Gases
Desulfurization
Electric Utilities
Alkalies
Scrubbers
Calcium Oxides
Limestone
Sulfur Dioxide
Dust
Air Pollution Control
Stationary Sources
Alkali Scrubbing
Particulate
Venturi/Spray Towers
Mist Eliminators
13B 07B
21B 08G
07A,07D
11G
13. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
93
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
93
------- |