DRAFT
DO NOT QUOTE OR CITE
Notice
This document has not been formally released by EPA and should not now
be construed to represent Agency policy. It is being circulated for
comment on its technical accuracy and policy implications.
IMPACT OF STEAM GENERATOR MODIFICATION/RECONSTRUCTION
ON S02 EMISSIONS
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
-------
-------
GCA-TR-77-21-G
November 1977
IMPACT OF STEAM GENERATOR MODIFICATION/RECONSTRUCTION
ON S02 EMISSIONS
' 'V,
Second Draft Report
by
Mark I. Bornstein
Paul F. Fennelly
Robert R. Hall
Douglas Roeck
Norman F. Surprenant
GCA CORPORATION
GCA/TECHNOLOGY DIVISION
Bedford, Massachusetts
Contract No. 68-02-2607
Work Assignment No. 3
Project Officer Program Manager
Kenneth R. Woodard Joseph A. McSorley
Emissions Standards and Operations Program Office
Engineering Division Industrial Environmental
Environmental Protection Agency Research Laboratory
Research Triangle Park, NC 27711 Research Triangle Park, NC 27711
U.S. ENVIRONMENTAL PROTECTION AGENCY
Research Triangle Park, North Carolina
-------
DISCLAIMER
This Final Report was furnished to the U.S. Environmental Protection Agency
by GCA Corporation, GCA/Technology Division, Bedford, Massachusetts 01730, in
fulfillment of Contract No. 68-02-2607, Work Assignment No. 3. The opinions,
findings, and conclusions expressed are those of the authors and not necessarily
those of the Environmental Protection Agency or of cooperating agencies. Mention
of company or product names is not to be considered as an endorsement by the En-
vironmental Protection Agency.
11
-------
ABSTRACT
This report discusses the terms "modification" and "reconstruction" as
related to New Source Performance Standards (NSPS) for SC>2 emissions from
coal-fired boilers greater than 250 million Btu per hour input. An analysis
of current boiler technology indicates there are few physical or operational
changes that would qualify as modifications or reconstruction in the sense of
altering S02 emissions from a boiler system. This is true because SC>2 emis-
sions are a function of the sulfur content of the fuel and are not affected
by furnace and boiler design and operating parameters. Two situations which
could be construed as modifications affecting SOy emissions would be conver-
sion of a wood burning facility to coal or the use coal/oil slurries in a
boiler originally designed for oil. Neither of these are expected to be
widespread occurrences. First, there are few wood-fired boilers in the size
range covered by NSPS and, secondly, it is doubtful there would be any incen-
tive for such units to switch from a cheap waste fuel to a more expensive
primary fuel. Boilers using coal/oil slurries have only recently been pro-
posed and are still at an experimental stage.
Also discussed in this report are some of the constraints that could
inhibit an existing facility from installing flue gas desulfurization
equipment.
iii
-------
iv
-------
CONTENTS
Abstract ill
1. Introduction and Summary 1
2. Modifications of Coal-Fired Power Plants 2
Modification as Covered by NSPS 2
"Modifications": Their Effect on Coal-Fired Power Plants
and SC-2 Emissions . 3
3. Reconstruction of Coal-Fired Power Plants 6
Reconstruction as Covered by NSPS , 6
Reconstruction/Coal-Fired Power Plants 6
4. Constraints Preventing Application of FGD 7
Land Restrictions . 7
Constraints Caused by Equipment Configurations 8
References 11
Appendices
A. Economics of New Construction, Repair and Maintenance 12
New Construction 12
Repair and Maintenance 12
References 20
B. List of Individuals Contacted 21
-------
SECTION 1
INTRODUCTION AND SUMMARY
New Source Performance Standards (NSPS) were promulgated by the Environ-
mental Protection Agency (EPA) on December 23, 1971, as part of 40 CFR Part
60. Fossil fuel-fired steam generating units larger than 73 megawatts (250 x
106 Btu per hour) heat input were covered under subpart D.
The limit on emissions of sulfur dioxide from affected coal-fired facil-
ities is 520 nanograms per joule (1.2 Ib per million Btu) heat input, which is
equivalent to about a 75 percent reduction in S02 emissions from plants burn-
ing 3 percent sulfur coal. This emission limitation is effective for any
facility firing coal which is greater than the stated size and which began
construction after the date of proposal of the standard (August 17, 1971) or
for any existing facility which is significantly modified or reconstructed
after that date.
On October 15, 1974, EPA proposed amendments to these regulations with
respect to modification, notification, and reconstruction. These amendments
were adopted and became effective on the date they were published - December
16, 1975.
It is the purpose of this study to identify and asess possible and
typical changes to steam generators that are affected by the amendments to
NSPS dealing with modifications and reconstruction. A further objective is
to assess constraints which might hinder the application of flue gas desul-
furization to modified facilities.
Few physical or operational changes have been identified which would
qualify as modifications or reconstruction of an existing boiler. This is
true primarily because S02 emissions are a function of the sulfur content of
the fuel and are not affected by furnace and boiler design and operating
parameters.
Certain obvious constraints attributable to cost, land and water avail-
ability, and the configuration of equipment at an existing facility tend to
hinder the installation of flue gas desulfurization systems to control S02
emissions from coal-fired boilers. Many of these constraints are site related
and must be considered on an individual basis.
-------
SECTION 2
MODIFICATIONS OF COAL-FIRED POWER PLANTS
MODIFICATION AS COVERED BY NSPS
In certain situations, modifications of already existing industrial opera-
tions can cause these facilities to be regulated by New Source Performance
Standards. Situations in which this can occur are delineated in Paragraph 60.14
of Part 60 of Chapter I, Title 40 of the Code of Federal Regulations (CFR).
Specifically the amended regulations state:
§60.14 Modification
60.14(a) Except as provided under paragraphs (d), (e), and (f)
of this section, any physical or operational change to an
existing facility which results in an increase in the emission
rate to the atmosphere of any pollutant to which a standard
applies shall be considered a modification within the mean-
ing of Section 111 of the Act. Upon modification, an existing
facility shall become an affected facility for each pollutant
to which a standard applies and for which there is an increase
in the emission rate to the atmosphere.
As indicated above, there are certain exceptions to the rule for describing
source modifications with respect to Nev Source Performance Standards. These
are summarized below:
60.14(d) (Simply stated, this exception indicates that physical
or operational changes are allowed for one facility within a source,
with a corresponding increase in emissions from that facility,
provided that the overall emissions from the source do not in-
crease. If the owner can demonstrate that the overall emissions
have not increased, then a "Modification" is deemed not to have
occurred. The burden of proof is on the operator.)
6014(e) The following shall not, by themselves be considered
modifications:
Routine maintenance, repair, and replacement
An increase in production without an increase in
capital expenditure
An increase in the hours of operation
2
-------
Use of an alternative fuel or raw material for which the
facility was designed to use
The addition of air pollution control equipment
Relocation or change in ownership
Relative to an increase in production, a capital expenditure is defined as
an expenditure for a physical or operational change which exceeds the product
of the applicable "annual asset guideline repair allowance percentage" (AAGRAP)
(as specified in the Internal Revenue Service Publication 534) and the existing
facility's "basis," as defined by Section 1023 of the Internal Revenue Code.
For the purposes of 60.14(e)(2), the total amount: of expenditures necessary to
increase the facility's operating rate must not be reduced by any excluded
additions as given in Publication 534. The tabulation of annual asset guideline
repair allowance (AAGRAP) percentages at the end of Publication 534 shows values
for three categories that could be applicable to coal-fired boilers. The first
lists an AAGRAP of 5 percent for an electric utility steam production plant
producing electricity for sale. The second shows an AAGRAP of 2.5 percent for
central steam production and distribution for sale. The third category is for
steam and electric generation systems for use by the taxpayer in his industrial
manufacturing process or plant activity and a value of 2.5 percent is given.
Further information concerning the economics of boiler operations is provided
in Appendix A.
60.14(f)~ Special provisions set forth under an applicable
support of this part shall supercede any conflicting provision
of this section.
"MODIFICATIONS": THEIR EFFECT ON COAL-FIRED POWER PLANTS AND S02 EMISSIONS
Changes which could be deemed modifications break down into two cate-
gories physical and operational. The physical boundaries of the facility are
currently defined as the coal reduction equipment on the front end of the
boiler, through the boiler and its accessories; e.g., air preheaters, economizers,
ash hoppers, etc., up to the stack. (If control equipment is installed the
system terminates before the control devices.) The essential feature in the
case of either physical or operational changes is that the activity must result
in an increase in emissions. In power plants, S02 emissions are related only
to the amount of sulfur contained in the fuel. In general, 90 percent or more
of the sulfur in the fuel is emitted as S02 although high alkali fuels; i.e.,
lignites and many low rank coals, do retain more sulfur in the ash.
There are very few situations which would cause an existing facility to
become affected through the "modification" provision. The obvious example of
fuel switching (oil or gas to coal) which would lead generally to substantial
increases in sulfur emissions is not likely to occur because of the high cost
of the many physical changes required to connect the facility, the increased
land requirements, other problems associated with the storage and handling
of coal and ash and the considerable downrating of the facility, typically
40 to 50 percent1 which occurs. As an example, connection of a 300,000 Ib/hr
-------
oil/gas unit for spreader stoker operations would require the facility ope-
rator to: ^
Modify the furnace to accommodate a spreader and dual fire
air system
Provide space for the dropped furnace rotor, an ash hopper
and ash removal system
Add superheater surfaces
Add additional sootblower and associated piping, etc.
Add hoppers for fly ash collection and reinjection
Modify the air heater and install an economizer
Install a dust collector ahead of the regenerative a.c. heater
Install new foundations, support timer etc. as required
Modify combustion and safety controls
Add an induced-draft fan for balanced draft operation
Modify furnace backstays and add duct work stiffeners for
balanced draft operations
The above modifications will take about 18 to 24 months and will result
in a downrating of the unit to between 150,000 to 175,000 Ib/hr. The connec-
tion to pulverized coal firing would require even more extensive modifications
and would take about 24 to 30 months.^
Numerous literature references indicate that conversion of oil or gas units
to coal is basically impractical.1~4 In addition to literature sources, contacts
with utility operators and individuals associated with combustion oriented
organizations (see Appendix B), confirmed that conversions, except for the case
of units designed primarily to burn coal, would be costly and impractical. These
individuals were also unable to identify practical physical or operational
changes that would cause a facility to become affected by the "modification"
provision. Changes such as the conversion of a stoker unit to a slag-tap or
cyclone furnace would increase emissions by approximately 5 to 10 percent but
are unlikely to occur because of the unfavorable economics associated with such
conversions.
A boiler designed originally for gas firing may be almost impossible to
convert economically to coal firing.3 Furthermore, it should be noted that a
conversion to coal carried out because of energy considerations is exempt from
NSPS. A more practical conversion would be the conversion from a wood burning
facility to coal. Although some modification of equipment (e.g., fuel feed
and replacement of burners) would usually be required, the change could be
accomplished relatively inexpensively. Based on EPA S02 emission factors, the
-------
conversion would increase S02 emissions and would be covered by the "modifica-
tion" provision. However, very few conversions of this type seem likely to
occur since wood burning units were planned to take advantage of a cheap,
available fuel which might otherwise be considered waste.
One development, the combustion of coal suspended in oil in conventional
oil-fired boilers, may be of interest as a "modification." If this development
proves successful, the boiler could be considered coal-fired. If used in this
fashion, such a boiler would result in an increase in S02 emissions.
-------
SECTION 3
RECONSTRUCTION OF COAL-FIRED POWER PLANTS
RECONSTRUCTION AS COVERED BY NSPS
As stated in §60.15, Title 40 of Code of Federal Regulations (CFR), "Re-
construction" means the replacement.of components of an existing facility to
such an extent that the fixed capital costs of the new components exceeds
50 percent of the fixed capital costs required to construct a comparable en-
tirely new facility. For the "reconstruction" criteria to apply, it is also
necessary that it is technically and economically feasible to meet the NSPS
standards for the pollutant in question.
RECONSTRUCTION/COAL-FIRED POWER PLANTS
Conceivably, a switch from natural gas (or oil), to coal may classify as
a "reconstruction" since such an action may well exceed 50 percent of the
cost of a comparible facility. If the cost did not exceed 50 percent the
changes would constitute a "modification" (provided the conversion to coal was
not required for energy considerations), because of increased S02 emissions.
Approximately 50 to 80 boilers will be required by the Federal Energy
Administration to convert back to coal. While switches from oil or gas to
coal which are federally mandated have been defined as not subject to NSPS
a certain number of voluntary conversions may occur. State legislation, such
as the Texas Railroad Commissions' Ruling No. 600, may also force facilities to
convert to coal. This ruling was passed in December 1975 and amended in March
of 1976; it specifies that gas utilities must limit new natural gas sales to
3 million cubic feet per day to any company wishing to use that premium fuel
in boilers. For those companies already .operating above the 3 million limit,
gas deliveries are to be cut by January 1, 1981 to 90 percent of the highest
consumption attained in 1974 or 1975. Given this impetus, Texas firms are
beginning 'the switch away from natural gas.6
Voluntary conversion will be few in number because of the high cost of
boiler modification as discussed previously. For the most part changes will
occur because of fear of shortages in natural gas and oil supplies.
-------
SECTION 4
CONSTRAINTS PREVENTING APPLICATION OF FGD
An objective of this program is to identify and assess the constraints
which might prevent the application of FGD to a modified facility. Generally,
difficulties regarding the installation of FGD are technically solvable al-
though the cost impact will be increased. Section 3 of the Clean Air Act spec-
ifies that cost must be considered in promulgating new source performance stan-
dards as quoted below:
"A standard for emission of air pollutants which reflects the
degree of emission limitation achievable through the application
of the best system of emission reduction which (taking into
account the cost of achieving such reduction) the Administrator
determines has been adequately demonstrated."
Therefore, potential constraints are identified and discussed in relation-
ship to their potential cost impacts.
The capital investment required for a FGD system applied to an existing
plant will typically be 10 to 20 percent higher than at a new plant.7'8 How-
ever, in specific instances difficulties can be much more severe than the
typical case, potentially increasing capital investments 60 percent.' An ad-
ditional and important factor is that existing plants will tend to have shorter
life expectancies. A new plant can be expected to last 30 years while an
existing plant may only last 10 years and operate at lower loads during that
period. Annual FGD costs in terms of mills/kWh for the existing plant in the
above example operating at the same load as the new plant, should be two to
three times as high as the new plant.8
LAND RESTRICTIONS
Land availability can be a major constraint. Space in the immediate
vicinity of the flue gas ducting .is required for the scrubber modules, fans,
pumps and associated ducting. For a typical 500 MW plant about 17,000 to
34,000 ft2 will be needed.8 While the amount of land required for the scrubbers
is not large, the location is critical it must, be in close proximity to the
boilers where space is often limited. Additional land (4 to 8 acres) is re-
quired for raw material (i.e., lime/limestone), receiving, storage and pre-
paration, access roads, and a process control building.
For a nonregenerable system (such as the most common lime /lime stone units),
sludge disposal requires the most area, 130 acres for a 500 MW plant with
-------
30 year life.9 Sludge may be disposed of offsite but land use restrictions
and environmental considerations can impose additional constraints.
Land for each of the three requirements (scrubber modules, raw material
storage and handling, and sludge disposal) can be constraints on the installa-
tion of FDG systems. The actual land area required for the scrubber modules
is not large and will seldom create problems that are not solvable. Longer
duct runs, staking and elevating equipment, and other engineering modifications
can usually be successfully employed to meet space limitations. Raw material
storage and handling requires more land but more options for location are avail-
able. In addition, the amount of limestone required is much less than the
amount of coal and the storage area is also relatively smaller. For example,
at a plant using a 3.5 percent sulfur coal, the quantity of limestone required
would be 5 to 10 percent of the coal quantity. A coal-fired power plant should
be able to locate space for limestone storage.
The disposal of sludge generated by a nonregenerative scrubbing system is
responsible for significant land requirement. A new 500 MW plant burning 3.5
percent sulfur coal would require 130 acres for disposal of sludge over a 30-
year period. The same plant would also require 75 acres for disposal of
fly ash.° At some existing sites the availability of land may be a serious
constraint.
An additional problem is that some land will not be suitable because of
environmental considerations. Offsite disposal may be an option as evidenced
by the practice at the Bruce Mansfield station, where sludge is pumped 7 miles
for disposal. A situation could, however, arise at an existing plant where
the cost of sludge disposal would be prohibitive. If onsite land is unavail-
able, expansion may be impossible (within reasonable economic limits) because
the surrounding land is already developed and pipe lines through developed
areas may also be prohibitively expensive. The use of a regenerative system
could eliminate or minimize any sludge disposal problem. However, for systems
producing sulfuric acid, markets must be available or storage problems will
be serious. On the other hand, sulfur can be easily stored in outdoor piles
if markets are not available.
CONSTRAINTS CAUSED BY EQUIPMENT CONFIGURATIONS
During the design and construction of a new plant FGD equipment will be
included as an integral part of the plant. Flue gas at a specified temperature
and maximum dust loading will be specified and included in the design. Space
for FGD will be provided and the location of particulate removal equipment,
FGD system, fans and the stack will be provided so that extensive ducting and
other problems are avoided.
At an existing plant, equipment locations and configurations can present
problems. For instance, it is not uncommon at existing plants to have the
stack located on the roof of the building. Many steam electric plants in
operation prior to 1971 have roof-mounted stacks in order to take advantage
of building elevations of 100 to 200 feet. Some examples are facilities at
-------
Sunbury, Pennsylvania and some older units at Mystic and Salem, Massachusetts.
Even the modern Canal Plant at Sandwich, Massachusetts has a roof mounted
stack. This may require long runs of ducting to ground level and back to the
stack or construction of a new stack. Another typical problem is the location
of the particulate control device (usually an electrostatic precipitator) in
relationship to the stack and other equipment. If the electrostatic precipi-
tator is very close to the stack, it may be difficult to install new ducting
between the ESP and the stack without disturbing the flow patterns and decreas-
ing efficiency.
Figure 1 is a drawing of a boiler that exemplifies some of the equipment
configuration problems. The application of FGD to the boiler in Figure 1 is
technically feasible but the cost will be higher than application to a new
plant. Devitt, et al.1" have estimated that typical capital cost increases
for long duct runs will range from 4 to 7 percent, tight space will range from
1 to 18 percent and a new stack from 6 to 20 percent.
-------
STACK height «480'
211' -
202' 9l"a
I9/ 9 f
166* I "
GAS DUCT
KOPPERS
ELECTROSTATIC
PRECIPITATOR
100 6
saw
O CYCLONE
BOILER
APPROXIMATE SCALE:
I in. = 95 ft.
/COAL FEEDER
UR TO CYCLONE
Figure 1. Diagram of a boiler exhibiting some retrofit problems.
10
-------
REFERENCES
1. Schweiger, R. Industrial Boilers, What's Happening Today. Power.
p.516, February 1977.
2. Should you Convert to Coal. Power, p. 38. July 1976.
3. Bell, A.W. and B.P. Breen. Converting Gas Boilers to Oil and Coal.
Chemical Engineering. April 26, 1976. p. 93.
4. Bogot, A. and R. C. Sarreiz. Principal Aspects of Converting Steam
Generators Back to Coal Firing. Combustion. March 1976.
5. Coal/Oil Burned in Oil Burner. Coal Age. p. 24. October 1976.
6. Conversion.to Coal Firing Picks up Steam. Chemical Enginnering.
February 14, 1977. p. 40.
7. Ponder, T. C. , L. V. Yerino, V. Katari, Y.. Shah, and T. W. Devitt. Sim-
plified Procedures for Estimating Flue Gas Desulfurization System Costs.
PEDCo-Environmental Specialists, Inc. EPA-600/2-76-150, U.S. Environmental
Protection Agency, June 1976.
8. McGlamery, G. G., R. L. Torstrick, W. J. Broadfoot, J. P. Simpson,
L. J. Henson, S. V. Tomlinson, and J. F. Young. Detailed Cost Estimates
for Advanced Effluent Desulfurization Process. Tennessee Valley Authority.
EPA-600/2-75-006, U.S. Environmental Protection Agency, January 1975.
9. Summary Report Flue Gas Desulfurization Systems November-December 1976.
PEDCo-Environmental Specialists, Inc. Prepared for U.S. Environmental
Protection Agency, Contract No. 68-02-1321, Task Order No. 28. January
1977.
10. Devitt, T. W., L. V. Yerino, T. C. Ponder, and C. J. Chatlynne. Estimating
Costs of Flue Gas Desulfurization Systems for Utility Boilers. J Air
Pollut Control Assoc. Volume 26, Number 3, March 1976.
11
-------
APPENDIX A
ECONOMICS OF NEW CONSTRUCTION, REPAIR AND MAINTENANCE
This section is for the purpose of establishing the costs involved for
construction of new power plants and for routine repair and maintenance. New
construction costs will serve as a guide in assessing the fixed capital cost
required for new facilities. This is applicable in determining whether or
not an existing facility has been reconstructed to the extent that it will
become an affected facility under NSPS.
The types of repair and maintenance to be enumerated and their relative
costs can be used in determining what types of repair and maintenance acti-
vities are routinely performed at an electric plant so that they can be dis-
tinguished from "modifications" as defined in the NSPS.
NEW CONSTRUCTION
The cost of construction of new coal-fired power plants is projected to
increase dramatically in the next several decades. In 1967, the cost of
constructing a new coal-fired plant was approximately $115 per kilowatt (kW).
The cost of putting a 1000 megawatt (MW) coal plant on line in mid 1975 was
about $200 million or $200 per kW. The projection for 1980 is $450 per kW
and for 1990 is $950 per kW.1>2 An example of the breakdown of the costs in-
volved for the various system components is given in Table A-l for a 1000 MW
coal-fired facility going on line in July 1969. The total direct cost in-
curred would be approximately 117 million dollars. In addition to this cost,
there would be another 10 million dollars for indirect costs, 8 million for
contingency, 39 million for escalation, and 2.1 million in interest to make a
total of 195 million dollars. The same total costs for a comparable nuclear
facility would be about 239 million dollars for the same start-up date.
REPAIR AND MAINTENANCE
Repair and maintenance of coal-fired boilers can result in significant
costs to power plant operators. While there is a difference between the two
terms, they are most often considered together in available cost information.
The National Boiler Inspection Code does, however, distinguish between repair
and maintenance and as an example defines repairs as the following items:
1. Replacement of sections of boiler tubes, provided the remaining
part of the tube is not less than 75 percent of its original
thickness.
2. Seal welding of tubes.
12
-------
TABLE A-l. DIRECT CAPITAL COSTS FOR
CONSTRUCTION OF A 1000 MW
COAL-FIRED PLANT - JULY,
1969 START-UP1
Direct costs only Cost - 106 dollars
Boiler 24
Boiler erection 8
Boiler structural steel 3
Draft system 3
Ash handling system 5
Coal handling including chimneys 7
and high-efficiency ESP
Turbine-generating unit 20
Turbine-generator erection 2
Heater cycle and condensing system 18
Accessory and auxiliary electrical 10
equipment
Miscellaneous power plant equipment 5
Instrumentation . 1
Other structures 7
Site improvement 4
Total 117
13
-------
3. Building-up of certain corroded surfaces.
4. Repairs of cracked ligaments of drums or headers within certain
definite limits.
In order to obtain information on the maintenance costs incurred by vari-
ous power plants, a survey was made of 20 different coal-fired units greater
than 73 MW (250 x 10 Btu). This information is presented in Tables A-2 and
A-3 and was obtained from the 25th annual supplement of "Steam-Electric Plant
Construction Cost and Annual Production Expenses" put out by the Federal Power
Commission in April 1974.3 The data are for the year 1972.
Table A-2 gives data for coal boilers firing only coal and shows that on
the average, boiler maintenance is about 65 percent of total plant mainte-
nance. Whereas the percentage of total maintenance attributed to the boiler
is nearly the same in all cases, the cost per megawatt is highly variable.
A low figure of $800 per MW was obtained at a Missouri plant while a high
value of $2,834 per MW was obtained for a plant in Florida. As can be seen
from the data in the first two columns, the cost of fuel is greater that 75
percent of the total production expenses in almost every case.
The data presented in Table A-3 is for coal boilers firing some combina-
tion of coal plus oil and/or gas. Again, the average percent of plant main-
tenance associated with the boiler is 65 percent. Also, the cost of boiler
maintenance per megawatt varies along the same lines as those boilers firing
only coal except that one higher value was obtained. The range was from
$950 per MW to $3,828 per MW. In terms of absolute dollars spent on boiler
maintenance, the data show values ranging from $160,000 to $4 million for
all the boilers surveyed.
The types of maintenance that will usually require substantial amounts
of time are boiler cleaning, repair or replacement of various parts, generator
stator or rotor repair, and recoating or welding of eroded or, damaged hydro-
turbine runner blades.
Some national figures are available relative to dollars spent on repair
and maintenance in the different regions of the country. For example, elec-
tric utilities in New England (investor-owned) spent $61 million in 1974 for
maintenance and repair of generating equipment. The figure for the entire
contiguous United States was $1.1 billion.6
Some specific maintenance items are available for cyclone and pulverized
coal-fired boilers. For a cyclone, the principal items requiring maintenance
are the coal crusher and the cyclone furnace boiler. The crusher will usually
require replacement of hammers and grid bars at yearly or less frequent in-
tervals, depending on the coal used. The burner should be checked carefully.
Pulverizers will usually require only minor repairs which can be accom-
plished at the annual outage or overhaul. Burner parts subject to abrasion
may require replacement at more frequent intervals. Regardless of the main-
tenance work performed annually, the unit should have a complete overhaul
every 5 years.
14
-------
TABLE A-2. MAINTENANCE COSTS FOR BOILERS FIRING ONLY COAL DURING 19723
1972 production expenses
Power plant
location and size
Cost, $ x 10 6
Cost of
boiler
maintenance
Percent
AI A2 B C
Total product Total product Total 'cost Total cost . ,-.- , ,_,. _,
, . , . ., per megawatt B/A, x 100 B/A;, x 100 C/B
expenses expenses for plant for boiler v ^6 l 2
(including fuel) (excluding fuel) maintenance maintenance only
.nn
x 100
1. Alabama Power Co. 36.2
Barry Plant
Bucks, AL
1770.8 MW
2. Alabama Power Co. 23.6
Gorgas Plant
Gorgas, AL
1545.7 MW
3. Colorado-Ute 3.1
Elec. Assoc. Inc.
Hayden Plant
Hayden, CO
163.2 MW
4. Tampa Elec. Co. 10.0
Big Bend Plant
Tampa, FL
445.5 MW
5. Tampa Elec. Co. 28.4
F.J.Gannon Plant
Tampa, FL
1270.4 MW
6.1
4.3
0.8
1.7
7.2
3.7
2.1
0.38
0.9
5.3
2.7
1.4
0.16
0.6
3.6
1,525
906
980
1,347
2,834
10.2
8.9
12.2
9.0
18.7
60.6 73.0
48.8 66.7
47.5 42.1
52.9 66.7
73.6 67.9
-------
TABLE A-2 (continued). MAINTENANCE COSTS FOR BOILERS FIRING ONLY COAL DURING 19723
1972 production expenses
Cost, $ * 10 ° , Percent
, Cost of
Power plant
boiler
location and size Ai A2 B c
Total product Total product Total cost Total cost n1310 enance
^ ... , . ., per megawatt B/Ai x 100 B/A-i x 100 C/B * 100
expenses expenses for plant for boiler s
(including fuel) (excluding fuel) maintenance maintenance only
6. Central Illinois 11.6 2.0 0.96 0.71 910 8.3 48.0 74.0
Light Co.
E.D.Edwards Plant
Bartonville, IL
779.8 MW
7. Central Illinois 5.34 1.55 0.68 0.5 2,784 12.7 43.9 73.5
Public Service Co.
Grand Tower Plant
Grand Tower, IL
179.6 MW
8. Empire District 3.9 0.6 0.25 0-17 800 6.4 41.7 68.0
Elec. Co.
Asbury Plant
Asbury, MO
212.8 MW
9. Minnesota Power 3.7 0.9 0.52 0.32 2,756 14.1 57.8 61.5
and Light
Aurora Plant
Aurora, MN
116.1 MW
10. Basin Electric 3.76 1.05 0.54 0.33 1,375 14.4 51.4 61.1
Power Cooperative
Leland Olds, NO
240 MW
-------
TABLE A-3. MAINTENANCE COSTS FOR BOILERS FIRING COAL PLUS OIL AND/OR GAS DURING 19723
1972 production expenses
Power plant
location and size
Cost, $ x 10~6
Cost of
boiler
maintenance
Percent
Total product Total product Total cost Total cost ^_ , .-_ .. ..,. _, . nn
, , , , .. per megawatt B/A. x 100 B/Ao x 100 C/B x 100
expenses expenses for plant for boiler «
(including fuel) (excluding fuel) maintenance maintenance only
1. Duke Power Co. 59.3
Marshall Plant
Terrell, NC
2000 MW
2. Potomac Electric 22.9
Power Co.
Chalk Point Plant
Chalk Point. MD
728 MW
3. Appalachian 17.1
Power Co.
Clinch River
Plant, Carbo, VA
713 MW
4. Detroit Edison 58.8
St. Clair Plant
E. China Twp.,MI
1905 MW
5. Indiana &
Michigan Elec. Co.
Tanners Creek
Plant
Lawrenceburg, IN
1100 MW
22.A
4.6
2.3
7.4
6.0
2.6
3.4
1.2
4.9
4.1
1.9
1.95
0.7
4.1
2.8
950
2,679
982
2,152
2,545
4.4
14.8
18.3
65.0 73.1
73.9 57.4
7.0 52.2 58.3
8.3 66.2 83.7
68.3 68.3
-------
TABLE A-3 (continued). MAINTENANCE COSTS FOR BOILERS FIRING COAL PLUS OIL AND/OR GAS DURING 19723
1972 production expenses
Cost, $ x 10~6 Percent
Power plant C°st of
location and size A, A-, B C boiler
, , "- , . maintenance
Total product Total product Total cost Total cost , .nn , .nn r .n_
_ , , , .. per megawatt B/Ai x 100 B/Ao * 100 C/B * 100
expenses expenses for plant for boiler «
(including fuel) (excluding fuel) maintenance maintenance only
6. Public Service Co. 17.9 2.7 1.4 0.77 961 7.8 51.9 55.0
of Colorado
Cherokee Plant
Denver, CO ~
801.3 MW .
7. Northern States 14.2 3.8 2.5 0.86 1,767 - 17.6 65.8 34.4
i-1 Power Co.
00 Black Dog Plant
Minneapolis, MN
486.7 MW
8. Montana Power Co. 2.05 0.48 0.27 0.2 . 1,157 13.2 56.3 74.1
J.E.Corette Plant
Billings, MT
172.8 MW
9. Omaha Public 15.2 2.5 1.4 0.9 1,500 9.2 56,0 64.3
Power District
North Omaha Plant
Omaha, NE
600 MW
10. Nevada Power Co. 7.8 1.75 1.1 0.87 3,828 14.1 62.9 79.1
Reid Gardner Plant
Moapa, NV
227.3 MW
-------
As has been mentioned previously in this report, S02 emissions vary
directly with the amount and percent sulfur of the fuel burned. For this
reason, maintenance of coal-fired boilers - whether routine or not - should
have little or no effect on total S02 emissions.
19
-------
REFERENCES
1. Power Engineering. August, 1974.
2. Vierath, D. R. and W. W. Walkley. Costs of Meeting Clean Air Requirements.
Power Engineering. September, 1976.
3. Steam-Electric Plant Construction Cost and Annual Production Expenses -
1972. Federal Power Commission. April, 1974.
4. Rowsome, Frank H. The Role of System Reliability Prediction in Power
Plant Design. Power Engineering. February 1977.
5. Federal Power Commission News Release No. 22083. January 22, 1976.
6. Maintenance-Repair Costs to Top $3 Billion. Electrical World 183(6).
March 15, 1975.
20
-------
APPENDIX B
LIST OF INDIVIDUALS CONTACTED
W. H. Axtman, Executive Director, American Boiler Manufacturers Association,
Arlington, Virginia
S. Baruch, Edison Electric Institute, New York, New York
L. Davis, Station Superintendent, Public Service Company of New Hampshire,
Concord, New Hampshire
E. M. Diehl, Bituminous Coal Research Inc., Monroeville, Pennsylvania
F. Gottlich, Boston Edison Company, Boston, Massachusetts
W. McKinney, Supervisor of Environmental Research, TVA, Chattanooga, Tennessee
J. Taylor, Arizona Public Service Company, Phoenix, Arizona
21
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse, before completing)
1. REPORT NO.
2.
4. TITLE AND SUBTITLE
STUDY TO DEVELOP DATA TO AID IN THE REVIEW OF THE Is
FOR S02 EMISSIONS FROM COAL-FIRED BOILERS
7. AUTHOR(S)
Mark I. Bornstein; Paul F. Fennelly; Robert R. Hall
Douglas Roeck; Norman F. Surprenant
9. PERFORMING ORGANIZATION NAME AND ADDRESS
GCA Corporation; GCA/Technology Division
Burlington Road
Bedford, Massachusetts 01730
12. SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection
Research Triangle Park, North Carolina
3. RECIPIENT'S ACCESSIONING.
5. REPORT DATE
SPS November 1977
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
; GCA-TR-77-21-G
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-2607,
Work Assignment No. 3
13. TYPE OF REPORT AND PERIOD COVERED
Second Draft Report
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
17.
a. DESCRIPTORS
KEY WORDS AND DOCUMENT ANALYSIS
b.lDENTIFI
13. DISTRIBUTION STATEMENT
19. SECURI1
UNCLASS
20. SECURM
UNCLASS
ERS/OPEN ENDED TERMS C. COSATI Field/Group
FY CLASS (This Report) 21. NO. OF PAGES
IFIED 29
fY CLASS (Thispagej 22. PRICE
IFIED
EPA Form 2220-1 (9-73)
23
------- |