-------
TABLE II-4
COMPARISON OF LIGNITE-FIRED AND TOTAL U.S. STEAM-ELECTRIC
GENERATING CAPACITY. 1972
Lignite-Fired Plants
U.S. Electric-Generat-
ing Plants, All Fuels
Lignite Share
Number of
Companies
8
395
Number of
Plants
19
966
Installed
Generating
Capacity(MW)
2269
297,564.9
0.8%
Net Power
Generation
(TO6 kWh)
9227
1,358,785.4
.0.7%.
SOURCE: Federal Power Commission, Steam-Electric Plant Construction Cost
and Annual Production Expenses, 1972; various utilities.
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11-10
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According to Table II-5, growth in lignite-fired industry capacity ;.'
over the period 1960-72 averaged 17.61 per year, which is more than
twice thei growth rate of 7.0% per year experienced by U. S. electric
generating capacity as a whole. Similar effects are shown for compara-
tive growths in net power generation.
Table II-5 also shows that the growth in lignite consumption
exceeds twice the growth rate experienced by coal consumption for
power generation.
3. Announced Expansion
Inasmuch as the design/ordering/ereetion schedule for steam-electric
power plants is typically a three to five-year undertaking, a reasonably
accurate projection of future industry growth is possible under the
reasonable assumption that plants already ordered are not affected by
the adoption of pollution control regulations. Table II-6 summarizes '
information on new generating stations currently being planned for
construction within the next five years. Thirteen new installations
are being built, and at least one other is currently being planned.
All of these units will be owned by utility companies.
Summing the capacities shown in Table II-6, it is shown that 7,930
MW will be added by 1980, representing an average annual growth rate
of 20.7% per year over the period 1972-80. This is comparable to the
industry's present growth rate. In essence, it is anticipated that :
the capacity of the industry will increase by a factor of 4.5 by 1980.
There are two principal restraints on future development of .
lignite-fired steam generators:
11-11
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. Lignite-fired steam generators and any other fossil fuel-fired
steam generators require a constant source of water in order to
operate; and water is scarce in most areas where there are
known lignite reserves.
. . The high moisture content and low energy content of lignite .
combine to make it uneconomical to transport long distances.
4. Financial Resources
The financial resources, borrowing power, and ability to sustain
capital expansion of a utility company are dependent both upon the
individual company and the type of utility. The lignite-fired electric
generating "industry" can be characterized by six of the eight utilities
previously listed in Table II-2. For the purposes of discussion, we
have divided the utilities into two distinct classes from which financial
data and future construction plans have been assembled through a review
of their annual reports and discussions with their corporate management
and various state regulatory authorities.*
01 ass I: Investor Owned
The designation, Class I, refers to investor-owned utilities, which
use long-term public and private debt placement and/or equity to finance
their capital expenditure programs for capacity expansion. Three such
utilities (Companies A, B, and C) have major building programs for
- .
Two very small, municipally-owned utilities that use lignite fuel were
excluded. The electric revenues of the two utilities combined were less
than $4 million, their net plant was less than $10 million, and they have
no announced plans for capacity expansion.
11-13
-------
I1gn1te-f1red generating capacity. One of these (Company C) controls
nearly half the lignite-firing capacity of the United States. Nearly
70% of present lignite-generated capacity is held by Class I utilities.
Class II; Rural Cooperatives :
Class II utilities differ from Class I utilities in that they may
either borrow directly from the REA (at significantly lower rates than
investor-owned utilities) to finance construction or may ask for REA
guarantees on loans from other sources. Class II utilities are
typically smaller in terms of their generating capacity and invested
capital. Three such cooperatives (Companies D, E, and F) herein
discussed, have lignite-fired generating stations and are adding addi-
tional lignite-fired capacity.
Both the investor-owned and rural electric cooperative utilities
are making a significant investment to expand lignite-fueled capacity.
Companies A, B, and C whose total installed capacity is over 12,300
megawatts, of which 1,511.3 megawatts (12%) are accounted for by lignite-
fired plants, will add 6490 megawatts of lignite fired capacity by
1981, or about 4.3 times their current lignite capacity. Note that
Class I's total installed capacity will increase only 1.5 times by
1981; thus it appears that the Class I companies are depending heavily-
on lignite-based expansion rather than other alternatives.
The three rural electric cooperatives (D, E, and F), account for
>, I* ' "-",, ^
almost one-third of all lignite-fired generating capacity and will add
1,895 megawatts of lignite-fired generating capacity between 1975 and
1981, to increase lignite-fired capacity 3.8 times.
11-14
-------
Basic financial data has been collected in Appendix A for the
three investor-owned electric utilities (Table A-2) and for three
electric power cooperativ.es (Table A-3) from Moody.1 s Public Utilities
Manual and annual reports.* Briefly, the fixed interest charges of
Class I companies are covered by earnings to a greater degree than
those of Class II companies. Thus Class I companies have significantly :
more capitalization and are readily able to obtain rate structure
adjustments to cover increased costs.
C. EMISSIONS REQUIRING CONTROL
Large fossil fuel-fired steam generators are the largest stationary'
source of sulfur oxides, nitrogen oxides, and particulate matter. When
standards of performance were promulgated for fossil fuel-fired steam
generators under Subpart D of 40 CFR Part 60 in December 1971 (36 FR 24877),
lignite-fired units were exempted from the nitrogen oxides standard
because of lack of data on levels of emission reduction achievable on
fl^!LU"!ts'-. The l!gr!e of Mrgency 1n Contro11in9 mx emissions from lignite
firing has been questioned since neither North Dakota nor East Texas"" "
have high ambient levels of NOX and neither has a heavy concentration
of automobiles, the primary source for NOX. These two regions of heavy
lignite utilization have a potential for growth either as population
centers or more likely as energy producers. The fact that the North
Dakota area is becoming an exporter of energy and the fact that lignite V
A financial brief for each of the six utilities, including planned
pollution control expenditures, is found in Appendix A. We suggest that
the reader consult the prospectuses for bond issues, bond counsellor
others, if more detailed information is needed.
rr-15
-------
1s becoming an attractive fuel alternative in both the North Dakota
area and 1n Texas suggest the possibility of a potential high
concentration of NOX if control action is not forthcoming.
Other pollutants from lignite firing include:
. Carbon monoxide, unburned hydrocarbons, soot
. Particulates , :
. Sulfur Oxides (SOx)
These pollutants are common to all fossil fuel stationary combustion
sources and particulate and SOX standards of performance are already
applicable to lignite firing. The expected levels of these emissions
for lignite firing are not significantly different from those expected
from bituminous coal firing.
D. STEAM GENERATION PROCESSES
All but one of the large (250 x 106 Btu's. per hour input) lignite-
fired steam generating units in the United States are associated with
the production of electricity. In a steam-electric plant the fuel is *
burned in a steam boiler to generate steam, which is in turn passed
through a steam turbine to generate electricity. Such plants are
designed for high reliability, operating 350 days per year or more.
* ' ,: ' ' '..':.-
Comparing generated power to generating capacity in Tables II-2 and II-3, the
nationwide utilization factor for lignite firing was 52% in 1972.
A sketch of a typical steam boiler is shown in Figure II-1. The
radiant section of the boiler is lined with boiler tubes on the walls,
floor and roof of the furnace enclosure. The boiler feed water is
i ' '
converted to saturated steam within these tubes through the radiant
transfer of heat from the hot combustion gases within the furnace.
" ( < -. . -. ''*!,' " , _ '
Additional heat transfer tubes required to superheat the saturated
: n-16 ;':'.':" .' .'.. ', , '' '"';.
-------
steam (i.e., the primary, secondary and reheat superheaters) are
usually included directly following the radiant section of the boiler.
Finally, most boilers have an air preheater to transfer heat from
the boiler exhaust to incoming combustion air.
The three areas where steam-generating equipment differ in'.'-"
design are in fuel preparation, firing mechanism, and ash removal.
These variables are summarized in Table II-7.
The boilers have been classified according to the three commonly
used methods of fuel firing:
. Pulverized fuel firing
. Cyclone firing
. Stoker firing
These three categories are discussed further below.
-------
SECONDARY AND REHEAT
SUPERHEATER
RADIANT SECTION
COMBUSTION ZONE
C
c
PREHEATED
COMBUSTION AIR
PRIMARY SUPERHEATER
ECONOMIZER
AIR PREHEATER
TO STACK
INCOMING AIR
Figure I1-1. SCHEMATIC DIAGRAM OF UTILITY STEAM GENERATOR.
11-18'
-------
TABLE II-7. SUMMARY OF UTILITY BOILER DESIGN FEATURES
Firing
mechanism
Pulverized fuel
Cyclone
Stoker
Fuel preparation
size drying
200 mesh Partial
1/4 in. Partial
2 in. No
Ash removal
Dry (typically)
Wet
Dry
1. Pulverized Firing
In a .pulverized fuel steam generator9 the fuel is fed from the stock
pile into bunkers adjacent to the steam boiler. From the bunkers , the
fuel is metered into several pulverizers which grind it to approximately
200 mesh particle size. A stream of hot air from the air preheater par-
tially dries the fuel and conveys it pneumatically to the burner nozzle
where it is injected into the burner zone of the boiler.
Three burner arrangements are used for firing pulverized lignite in
existing steam generators:
Tangential firing .
Horizontally-opposed burners'
Front wal1 burners
" n-19
-------
These arrangements are shown schematically in Figure II-2.
The tangential method of firing pulverized coal into the burner
zone has been developed by Combustion Engineerings Inc., (QE) of
Windsor, Conn, In this firing,method the pulverized coal is
introduced from the corners of thei boiler in vertical rows of burner
nozzles. Such a firing mechanism produces a vortexing flame pattern
which CE describes as "using the entire furnace enclosure as a
burner."
Other manufacturers, such as Babcock and Mil cox and Foster
Wheeler, have developed both .front-wall firing and horizontal1y-
opposed firing. In these firing mechanisms, the pulverized coal is
introduced into the burner zone through a horizontal row of burners.
For furnaces less than about 200 MW the burners are Usually located
on only one wall. For larger boilers, the burners have been located _
on the front and back walls firing directly opposedI-to eachother. i
This type of firing mechanism produces a more intense combustibn
pattern than the tangential firing and has a slightly higher heat
release rate in the burner zone itself, , ; ;
In all of these methods for firing pulyerizedjfuel,,sthe ash is
removed from the furnace both as fly ash and bottom ashi The bottom
of the furnace is often characterized as either wet or dry, depending
upon whether the ash is.removed as a liquid slag or as a solid.
Pulverized coal units have been designed for both wet and dry bottoms,
but the current practice is to design only dry bottom furnaces. The
wet bottom furnace requires higher temperatures^usually, <26QO*F) 1n
11-20
-------
order to melt the ash before it is removed from the furnace. This
is important to NOX control since higher temperatures result in higher
NOX emissions from thermal fixation.
2. Cyclone Firing
The cyclone burner, manufactured by Babcock and Wilcox, is a
slag-lined high-temperature vortex burner. The coal is fed from the
storage area to a crusher that crushes the coal (or lignite) into
particles of approximately 1/4 in. or less. Crushed lignite is
partially dryed in the crusher and is then fired in a tangential or
vortex pattern into the cyclone burner. The burner itself is shown
schematically in Figure II-3. The temperature within the burner is
hot enough to melt the ash to form a slag. Centrifugal force from
the vortex flow forces the melted slag to the outside of the burner
where it coats the burner walls with a thin layer of slag. As the
solid coal particles are fed into the burner, they are forced to
the outside of the burner and are imbedded in the slag layer. The
solid coal particles are trapped there until complete burnout is
attained.
The ash from the burner is continuously removed through a slag
tap flush with the furnace floor. Such a system insures that the
burner has a sufficient thickness of slag coating on the burner walls
at all times.
One of the disadvantages of cyclone firing is that in order to
maintain the ash in a slagging (liquid) state, the burner temperature
must be maintained at a relatively high level. The higher
temperature promotes NOX fixation. Unfortunately, this cannot be
. 11-21 . .
-------
TANGENTIAL
HORIZONTALLY OPPOSED
FRONT WALL
FIGURE II-2. BURNER ARRANGEMENTS FOR PULVERIZED-FUEL
FIRING IN A UTILITY BOILER
-11-22.
-------
offset via the reduction of available oxygen without employing an
auxiliary fuel to maintain stability. Tests on cyclone burners
firing lignite alone have shown that the burner cannot be satisfactorily
operated at a sub-stoichiometric air condition because of flame
stability problems, i.e., the fire goes out at air addition rates
less than the theoretical requirement.
3. Stoker Firing
In a stoker-firing furnace, shown schematically in Figure II-4,
the coal is spread across a grate to form a bed which burns until
'the coal is completely burned out. In such a mechanism the coal is
broken up into approximately 2-in. size and is fed into the furnace
by one of several feed mechanisms underfeed, overfeed, or spreading.
The type of feed mechanism used has very little effect on NOX emissions.
The physical size of stoker-fired boilers is limited because of
the structural requirements and extreme difficulties in obtaining
uniform fuel and air distribution to the grate. Most manufacturers
of stoker-fired equipment limit their design to 30 MW. The largest
stoker in the United States, Heskett Station in Mandan, North Dakota,
is a 65 MW twin stoker and is fired with lignite. It is unlikely
that plants any larger than this would ever be built in the United
States. .
In most stoker units the grate on which the coal is burned
gradually moves from one end of the furnace to the other. The coal
is spread on the grate in such a fashion that at the end of the
grate only ash remains, i.e., all of the coal has been burned to the
final ash product. When the ash reaches the end of the grate it
ri-23 : :
-------
Furnace
Fuel and Air
Molten Slag
FIGURE II-3 SCHEMATIC OF CYCLONE FIRING OF LIGNITE IN A UTILITY BOILER
Coal Spreader
'Ash Removal
FIGURE II-4. SCHEMATIC OF STOKER FIRING IN A BOILER
11-24
-------
falls off into an ash collection hopper and is removed from the
furnace. ., . -....-... .".,. .-... ...
I..1'..'..:;.:.;1..,.- -. .-' ' '... ' .-". ; . *~i: ':'" '-',;('" r^j-ni'.^ ',''' i uwe.r
Stoker-fired furnaces are dry-bottom furnaces and, as such,
generally have lower heat release rates and lower temperature profiles
than the corresponding pulverized coal or cyclone-fired units. Hence
stoker-fired units typically have lower NOX emission rates than other
coal-burning equipment used for generating steam.
E.; NOX EMISSIONS FROM LIGNITE FIRING
Several emission factors have been published comparing the
different types of stationary combustion steam-generating equipment
currently in use. These are shown in Table II-8. Preliminary
emission factors were published in 1956 by the Public Health Service.
These numbers have been recently revised through an extensive field
testing program carried out by Exxon Research and Engineering for
78
EPA. ' The emission factors for lignite firing were determined from
data reported in Chapter V of this report.
The variables which affect NOX emissions can be segregated into
two classes: fuel variables and burner design parameters. The
significant parameters in each of these two classes are listed below
along with a brief discussion of the reasons for their importance.
a. Fuel Variables
. Fuel moisture'content - the flame temperature in the ,
combustion zone is inversely proportional to the moisture
content of the fuel being fired. A high moisture-containing
fuel, such as lignite, burns at a relatively lower flame
11*25
-------
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temperature than that corresponding to the firing of
bituminous coal. The lower temperature results in lower
NOX emissions.
Volatility content - the rate of devolatilization of fuel
particles alters the local combustion conditions surrouriding
each individual particle. Experimental data suggest that
high volatile fuels burn at a lower heat release rate than
less volatile fuels. Hence, the anticipated temperature
profile within a boiler is expected to be lower for a high
volatile fuel than it is for a low volatile fuel, resulting
in a correspondingly lower NOX emission.
Fuel-nitrogen - although the mechanism by which NOX originates
from the fuel-nitrogen is not clearly defined, it has been
demonstrated that fuel nitrogen oxidation can account for as
much as 80-90 percent of the total NOX emissions in pulverized
firing. Lignite has a fuel nitrogen content larger than
gas or oil and comparable (on a Btu basis) with that of
bituminous coal.
Sodium content of the ash - although the sodium content of
the lignitic ash does not affect NOX emissions, it has an
indirect effect on the emissions level in that lignite
boilers are designed with low heat release rates to avoid
ash fouling problems accompanying the high sodium ash. The
lower heat release rate results in lower NOX emissions.
11-27 .
-------
b. Burner Design Parameters
( -
. Firing mechanism - the method of firing fuel into the boiler
affects the local heat release rate and temperature within
the burner zone, and thus the thermal NOX. Of the three
boiler designs discussed above, the cyclone burner has the
highest local heat release rate. Pulverized coal firing has*
a heat release rate in the burner zone, lower than that of
cyclone firing but higher than stoker firing. The lowest
heat release rate of all is obtained by stoker-fired units.
However, stoker units are limited in physical size and will
not be of significant importance in future lignite-fired
steam-generating equipment. '
. Temperature profile - the temperature profile throughout
the boiler is directly related to local levels of available
oxygen, heat transfer and heat release rates. Although the
designer has little control over the burning,rate of the
coal particle (i.e., heat release rate), they can predict
'!.' '
what these rates will be for a given furnace and fuel '
combination. The local temperatures can then be controlled
through, the addition of excess air or provision for greater
heat transfer surface. Above the burner zone, the temperature
profile for pulverized coal firing and cyclone firing are
similar. The temperature of gas entering the superheating
section is limited to about 185DฐF in>both types of furnaces,
so as to minimize the effects of ash fouling. This design
II-28
-------
philosophy has a favorable impact on the level of NOX
emissions.
. Ash handling - ash can be removed from the boiler either as
a molten slag (wet bottom) or as a dry-bottom ash (dry
bottom). The wet-bottom furnaces require much higher
temperatures in the burner zone in order to maintain the
ash in the molten state. This high temperature results in
a higher NOX emission rate. The cyclone is the only wet-
bottom design being proposed for lignite firing.
F. CONTROL OF PARTICULATE MATTER EMISSIONS '
All of the large lignite-fired steam generators in the country
either (1) have high efficiency precipitators, or wet scrubbers, or (2) are in
the process of purchasing this equipment. Since lignite is relatively
low in sulfur, the ash resistivity is lower than needed for standard
precipitators. Hence, some companies have selected the "hot side" '
'
precipitator design. The combustion of lignite does not affect the
possible level of control attainable using these high efficiency air
pollution control devices nor does the firing of lignite alter any
of the general design features of tjftis equipment. All of the large ;
existing sources currently meet the State implementation plan regulations
for particulate matter. New lignite-fired steam generators using
properly designed control systems can easily comply with new source
performance standards for particulate matter.
G. CONTROL OF SULFUR OXIDES EMISSIONS ,
Lignite is a relatively low sulfur fuel, typically containing less ,
than 0.4 percent sulfur. Sulfur oxide emissions from combustion of
11-29 '
-------
lignite are a function of the alkalinity (especially sodium content) of
the ash. Unlike bituminous coal combustion, in which over 90 percent of
the fuel sulfur content is emitted as S02, a significant fraction of the
sulfur in the lignite is retained in the boiler ash deposits and flyash.
Thus, most lignite-fired units may not require application of S02
control systems and flyash. The Energy Research and Development Agency
in Grand Forks, North Dakota, is experimenting with removal of S02 by
lignitic flyash. Pilot scale demonstrations of this technology have been
developed using Montana subbituminous C coal at the Montana Power Company's
Corette Station in Billings, Montana. A full-scale scrubbing system
(360 MW) is scheduled for start-up at MPC's Col strip Station in March
1975. A second system will be installed on Colstrip #2, scheduled for
start-up in March 1976. ;
H. MODIFICATIONS , ! . "-.>,'
Under section 111(a)(4) of the Clean Air,Act, a source may become .
subject to standards of performance if equipment or operations are
altered in a manner which increases emissions* To clarify the meaning,
of the term "modification" appearing in the Act and to clarify when
standards of performance are applicable, EPA established interpretative
amendments to Part 60 of Chapter 1 of Title 40 of the Code of Federal
Regulations. These provisions were adopted in the Federal Register on
December 16, 1975 (40 FR 58416).
The provisions of 40 CFR 60.14 provide that a modification is
considered to have occurred if a physical or operational change to an
existing facility results in an increase in the emission rate to the
atmosphere of any pollutant for which a standard of performance is
applicable. Section 60.14 also provides that the following changes
11-30
-------
applicable to lignite-fired steam generators do not of themselves classify
a facility as modified:
1. Routine maintenance, repair, and replacement of equipment,
2. An increase in production rate if the increase can be
accomplished without a capital expenditure,
3. An increase in the hours of operation,
4. Use of an alternative fuel or raw material if the facility
was designed to accommodate use of that fuel. Conversion
of facilities to coal firing required for energy considera-
tions as specified in section 119(d)(5) of the Act is not
considered a modification. v
For lignite-fired steam generators a modification is considered
to have occurred if an increase in emission rate of sulfur oxides,
nitrogen oxides, or particulate matter occurs after a change in the
physical facility or its operation, Examples of changes which would
be considered a modification of an existing lignite-fired steam
generator are:
. Instal 1 a_t1gn_of_ burners of a different type than initially
installed (e.g., cycljjne burners in a pulverized^ fuel
furnace or a pulverized fuel burner instead of a stoker).
The changes indicated above would result in higher NOX
emissions due to firing design changes which inherently
produce higher NOX emissions.
. Relocation of burners ini^an^existinjg furnace With or
without a change in J:he number of burners. A change in
burner arrangement or number which created a more intense
flame pattern would result in higher NOX emissions.
11-31 '-'' ' ' "':
-------
For effective implementation of the provisions of sections 111 of
the Clean Air Act, knowledge of sources which may be subject to the
standards is important. For this reason, provisions were established
in 40 CFR 60.7 which require written notification to EPA of any physical
or operational change to an existing facility which may make it an
affected facility. This notification shall be postmarked within 60
days or as soon as practicable prior to commencement of the change.
The notification shall include the precise nature of the change, present
and proposed emission control systems, productive capacity of the
facility before and after the change, and the expected completion date
of the change. .
11-32
-------
III. PROCEDURES FOR DEFINING BEST CONTROL TECHNOLOGY
A. DEVELOPMENT OF DATA BASE
The following steps were taken to develop adequate information
to support emission limitations for NOX control for lignite-fired
steam generation.
1. The population of lignite-fired steam generators currently
being operated by utility and industrial concerns was
identified and sorted by state, furnace type, and size.
2. Nationwide emissions of NOX were estimated from th.e
population of lignite-fired steam generators.
3. Steam generators with "best systems" of NOX emission
reduction were identified.
4. The available methods for sample collection and analysis of
NOX emissions from lignite-fired steam generators were
documented.
5. Presurvey inspections were conducted on 8 plants to
select candidates for source testing by EPA and its
contractors.
6. Source tests were conducted to gather information on the
emissions, the processes, and the emission control systems.
7. Alternative emission limitations for new lignite-fired
steam generators were formulated.
B. SOURCES OF PLANT DATA
To obtain basic data on plant location, capacity and generation
for utility boilers (presented in Table II-2 of this report), a
literature survey was conducted and the following source was
III-l
-------
identified as containing the most complete arid up-to-date information:
Steam-Electric Plant Factors/1973 Edition. National Coal
Association, Washington, D. C., 1974. (Reference 10)
Similar information on industrial-type steam generators was
obtained from records kept by the American Boiler Manufacturers
Association (ABMA) from January 1970 to April 1974. These documents
indicated that no industrial installations were supplied with new
'- .
lignite-fired steam boilers during this time period. The ABMA
records previous to January 1970 do not separate lignite-fired ;;
generators from the general classification of coal-fired generators:
Conversations with the four major boiler manufacturers confirmed
our assumption that the number of industrial facilities burning
lignite would be very small. Two of these manufacturers have
significantly contributed to lignite-fired steam generation. These
are Combustion Engineering and Babcock and Nil cox. Riley Stoker,
Inc., supplied many of ."the older stoker-type boilers; Foster-Wheeler
Corporation supplied two installations. Information on two industrial
units of sufficient size to be studied was also obtained.
Individual utility and industrial companies were then canvassed.
Information on boiler configurations was gathered from them directly.
C. SELECTION OF PLANTS FOR EMISSION TESTING
As a result of our literature.review, conversations with
industrial and utility lignite users and eight site visits for pre-
survey inspection, four lignite-fired steam generators were recom-
mended for emission testing.
D. SAMPLING AND ANALYTICAL TECHNIQUES RECOMMENDED
The sampling and analytical techniques used for this work are
, rir-2 .
-------
the same as those used in developing the standard for other fossil
fuel steam generators. A detailed discussion of these is given
in Chapter IX of this report.
The primary technique for analysis of NOX is the phenol-
disulfonic acid (PDS) method, EPA Method 7. Instrumental
methods were also used to provide a check for the PDS method and also
to provide data while the tests were in progress. A comparison of
the PDS method data and the instrumental data is given in Appendix B.
Use of a continous monitoring device which meets the criteria of
Performance Specification 2 of Appendix A to 40 CFR Part 60 is required
for NOX emission monitoring.
E. EMISSION MEASUREMENT PROGRAM
In order to obtain the data required to investigate alternative
NOX emission limitations, four boilers (three stations) were tested.
The summary of the text matrix for each of the boilers and the data
obtained as a result of that testing program are presented in Chapter V
of this report.
F. UNITS OF THE EMISSION LIMIT ,
All units used in this document are consistent with the units of
measure used for developing.the standard for the combustion of other
fqSsil fuels. EPA has promulgated in the Federal Register (40 FR 46250)
a procedure, the F factor method, for calculating NOX emissions
in Ibs/million Btu's heat input. The method determines the ratio
of NOX to heat input based upon an Orsat analysis of the stack gas,
instead of using data obtained from EPA Methods 1 and 2 (i.e., flow
rate and moisture content of flue gas). The calculation of NOV emissions
> ' . ' " - **'.''
in terms of Ibs/million Btii's heat input has been made according to the
III-3 ;
-------
F factor procedure (see Appendix B). For all coals including lignite',.-.'ฃ
' , ' '"-,
heat input is based upon the higher heating value of the fuel when
calculating emission factors. We have also included the NOX emissions '
calculated using the methods 1 and 2 data whenever the data have been .
available.
III-4
-------
IV. NOV CONTROL TECHNOLOGY FOR LIGNITE-FIRED BOILERS
/\ " _"-'"'
A. PRINCIPLES UNDERLYING NOV CONTROL METHODS FOR FOSSIL FUELS
A '
Nitric oxide is known to form via two distinct mechanisms, one in
which nitrogen is taken from the air and the other in which nitrogen is
taken from the fuel.
Some fuels such as natural gas and distillate (#2) oil contain
negligible organic nitrogen; control methods for combustion of these fuels
are based solely on preventing nitrogen from being taken from the air.
"Fixation" of N2 can be prevented by reducing the level of thermal excita-
tion in the flame, thereby minimizing the Zel'dovich reactions :
02 + M -* 0 + 0 + M
.0 + N2 * N0'+ N . ' -
N + 02 > NO + 0
Thermal excitation or peak flame temperature can be reduced by means of
(a) flue gas recirculation, (b) staged combustion, (c) water injection,
(d) reduced air preheat, or (e) combinations of these techniques.
Other fuels such as residual (#6) oil, coal and lignite contain
0.2 to 1.5 percent organic nitrogen; control methods for these fuels
are based not only on reducing thermal fixation but also on preventing
fuel nitrogen from forming HQ upon volatilization. Oxidation of fuel-
nitrogen may be responsible for as much as 80 - 90 percent of the
IV -
-------
47 '-
total NOV emissions from pulverized coal firing. Thus, control of y
A - _ ''-;,;;.__
fuel-nitrogen oxidation may be the limiting factor in controlling NO V-
A ,;-,;'_>
emissions from pulverized lignite-fired boilers. Fuel nitrogen con-
version can be controlled by removing oxygen from the volatilization
" .' ;v'r
zone by means of (a) low excess air, (b) staged combustion, (c)
fuel/air mixing pattern adjustment (burner design).
An approximately constant fuel-nitrogen content for the various
U.S. lignites rules out the possibility of changing to a lower fuel- ;
nitrogen lignite for NOV control (see Appendix D).
A ' '["''
In Table IV-l, these NO' control methods are summarized. In Sections
A - - , - -
C, D, E, and F of this chapter, the most effective control methods are
i; :
described in detail. , '
B. CONTROL METHODS APPLICABLE TO LIGNITE-FIRED BOILERS
Because of intolerable efficiency losses, water injection and reduced
preheat are not competitive NOV control methods for large steam generators
J\
Flue gas recirculation is not competitive for lignite because the
substantial fuel NO .contribution would go uncontrolled. Therefore,
J\ - ' ' i '
the viable control methods in Tables;IV-1 to be considered in further
detail for lignite are as follows: . . . ;
Low Excess Air (LEA)
Staged Combustion (SC) .
Low-Emission Burners
I Combined Low Excess Air and Staged Combustion
Certain peculiarities of lignite impose constraints on the applica-
tion Qf these NO control techniques. For example, higher primary air t
A ' ,
IV-2
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IV -3
-------
temperatures are employed, larger furnace volumes per unit heat input :
are customary, the number of soot blowers is increased and pulverizers '
are larger. Among planned units or units under construction cyclone
burner lignite furnaces are more prevalent for high-fouling North , '
Dakota lignite; whereas, pulverized firing is used with little ,
difficulty for the low-foul ing Texas lignite. Due to the variability
of the ash fusion temperature of Texas lignites, pulverized firing is
preferred to cyclone firing. Cyclone burners are believed by some in ,
the industry to be better able to handle the slagging problems of high ',
sodium lignite than pulverized fired units. The reliability of cyclone-;
firing of lignite in the U. S. is good; however, experience with firing of
high sodium lignite is limited for either cyclone or pulverized fired units.
The impact of the ash-depositing tendency of lignite on NOX emission
controls is as follows: :
. If operational dependability is obtained by using cyclone
burners, then NOX controls such as SC or LEA are quite
limited. Cyclones must have 110 percent of the total
stoichiometric air directed into the burner and cannot ;
be staged when firing lignite alone without compromising
the high heat release per unit volume required for slag
control. Initial testing indicates that cyclone combustion
air can be staged if an auxiliary oil gun is employed to
provide sufficient heat for slag control.
. If pulverized firing is adopted, utilization of 100-110
percent of the total stoichiometric air in the fuel.admitting
zone can be achieved with 18*25 percent overall excess air.
Thus, staged combustion with pulverized firing is not
unduly restricted by fouling considerations.
. IV-4, ' ' "'". '*.'''- " "
-------
C. STAGED COMBUSTION
A typical utility boiler operates with an array of burners, each of
which produces a flame "basket" of overall excess air equal to the total
excess air of the entire boiler. Staged combustionis accomplished by
redistributing the air flow such th$t a secondary combustion zone is en-
countered by the hot combustion gases after they leave the flame basket, i
This two-stage combustion has two effects on NO:
-. ' ' ' ', ''.-.". ."".' ' X ' . . .',-, . . . ' '
ซ Fuel NO^ is reduced because less oxygen is available during !
volatilization.
Thermal NQX is reduced because the temperature does not reach
':.'.;' , as high a peak as when all the heat release occurs in, one stage
(heat loss occurs between the two stages).
Two methods of air redistribution are shown schematically in Figure IV-1.
Starting from the normal air/fuel ratio at the burners, staging can be
accomplished either by maldistributing air (oyerfire air port), or by
maldistributing fuel (burner out of service). The extent of staged air
can be conveniently indexed by the fraction of stoichiometrically-required
air remaining at the burner flame baskets. For example, suppose a boiler
operating with 15 percent excess air has five operating burner levels with
air supplied to six levels. Then one-sixth of the air supply is staged,
leaving the burners with (115 x 5/6) qr 95 percent of stoichiometric air *
at the burners. , v
Staged combustion has shown reductions of about 30 percent when applied
to lignite fired utility boilers, as shown in Figure IV-2.
IV-5
-------
I 1 AIR
EZ3 FUEL
.NORMAL STAGED BY STAGED BY
FIRING BURNERS OUT OVERFIRE
OF SERVICE AIR
Figure IV-1. TWO METHODS OF STAGED COMBUSTION
AS APPLIED TO A VERTICAL COLUMN
OF BURNERS IN A UTILITY BOILER.
'IV-6
-------
o
D
57QMW, Tangentially Fired, Habelt (1974) -Ref.18
155MW, Tangentiany Fired, Habelt (1974) - Ref. 18
102MW, Front Wall Fired, Crawford (1974)* - Ref. 8
328MW, Tangentially Fired, Habelt (1974) - Ref. 18
218MW, Front Wall Fired, Crawford (1974) - Ref. 8
700
600
500
CM
O
ง400
ts
.ง
8
5 300
200
100
1
0.7lbN02
106 Btu
0:6lbNQ2
106 Btu
80
90
100
110
120
% Stoichiometric Air to Active Burners
'This unit was fired by a fuel which, although classified subbituminous, had
a heating value of 6800 to 7800 Btu/lb., 7 to 16% ash, and 28% moisture.
Since these values are similar to lignite, this data is useful for assessing NO
control effectiveness for lignite firing. x
Figure IV-2. EFFECT OF STAGED COWUSTIOH ON NOW FROM
LIGNITE-FIRED BORERS. X
IV-7
-------
D. LOW EXCESS AIR . . /:
In addition to the air needed to complete combustion, about 10 to 20
, ' . ..;%'.",
percent overall excess air is added to utility boilers to insure an oxidiz-
ing atmosphere throughout the burning process, to cover normal +3 percent
fluctuations in excess air, to aid carbon burnout, and to increase the ; \. - .
convective heat transfer rate. Subject to these operating constraints,
if excess air can be minimized then NOX is reduced for two reasons:
t Fuel NOX is reduced because less oxygen is available ;
during volatilization. :
0 Thermal NOX is reduced because the controlling Zel'dovich
reaction, 0 + N2 + NO + N, is retarded by low oxygen
radical concentrations.
It should be noted that well mixed, adiabatic combustion systems respond '
adversely to lower excess air, giving higher NO because of higher adiabatic
flame temperature. But real utility boiler systems usually show NO reduction
'..'' A
with low excess air. Low excess air has been tested on lignite fired boilers,
as shown in Figure IV-3. About 20 percent reduction in NO can be expected
X , . . . \ ;
when excess air is reduced from 20 to 10 percent (excess oxygen from 4 to ฃ
percent).
IV-8
-------
218MW/ Horizontally Opposed Fired, Crawford (1974) - Ref.8
P;.'. 102MW, front Wall Firedi Crawford (1974) - Ref. 8
A 155MW, Tangentiany Fired, Habelt (1974) - Kef. 18
700
600
'_ 500
P"
ฃ
400
I
o
x. 300
200
100
I
I
0.7 Ib NOX
MM Btu INPUT
...
0.6lbNOx
MM Btu INPUT
100
JOB
125
110 .115 120
% Stoichiometric Air to Furnace
(about 20% reduction when air reduced from 120 to 110)
Figure IV-3. EFFECT OF EXCESS AIR ON N0y FROM LIGNITE-
FIRED BOILERS. .:/*.
130
IV-9
-------
E. DUAL REGISTER-LOW NOX EMISSION-PULVERIZED COAL BURNER
Near the end of 1974, one of the two major suppliers of
lignite-fired boilers made a corporate decision to include low NOX ,'
emission burners as standard equipment on all pulverized coal fired
boilers. Although EPA emission testing on only one retrofitted furnace
i s compl ete, ^ these results' T ncTfcate"tMt; thi s burner yi eras Wx rectatttpns
close to those obtained by tangential firing. For this reason, the
following description of the low NOX emission burner is given even
though it is not presently a wel1-demonstrated NOX control technology
for lignite-fired steam generators.
Figures IV-4 through IV-6 illustrate the principles on which the ;
low NOX emission burner is based. Due to slagging and fouling
problems, combining lower peak flame temperatures with controlled .
fuel-air distribution is the optimum design tool for NOX control in
coal*fired furnaces. Burners have been spaced to increase the water-
cooled surface area around the burners, thereby lowering the burner
zone heat release rate, and the burners and windbox have been designed
to provide for optimum air distribution to the burners and within.
the burners. This arrangement permits the burners to operate with
minimum total air for NOX control, while providing sufficient air for
combustion and slagging control.
During the last two months of 1974, the EPA performed NOX emissions
tests on a 270 MW, 18-barner, horizontally opposed, bituminous coal
fired utility boiler equipped with dual register low NOx emission burners.
These tests were run on a boiler firing bituminous coal, not lignite.
IV-10
-------
.2
.ฃ
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"5
Q.
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Figure IV-4
IV- IT
-------
-------
Figure IV^6
' IV-13
JQ
QL
-------
Operating at baseline conditions, this boiler had an emission factor
of approximately 0.53 Ib NOY/10 Btu while a sister unit Identical .
A
in design, but not equipped with the low NO emission burners had an
X
emission factor of approximately 0.82 Ib NOX/10 Btu when run under
identical baseline conditions. When the boiler equipped with
the low NO dual register burners was operated with low excess air,
** ' , ' .
NOV emissions were further reduced to approximately 0.38 Ib NO /10
*\ , X
<* Q ' ฃ :ป . j .*_,_ .,_ . . , ^ '_.,, . _, , v_, . _, ,_-^ ^^ ^ ; ^ ' ^^_ : , ' '
Btu. Although these figures are only data from tests on one fetrbfTtted
boiler, it is clear that the low NOX emission burner should prove to
be a viable and effective NOX control technology for coal-fired and
possibly lignite-fired steam generators.
F. BEST AVAILABLE CONTROL SYSTEM: COMBINEDTOW EXCESS AIR AND STAGED COMBUSTION
By reducing excess air from 20 to 10 percent and simultaneously diverting
, about 15 percent of this reduced air supply to a second stage combustion ?bne,
NOX reductions of about 40 percent are expected, based on test results reported
by Crawford et al_8 on lignite-fired units. This figure is conservative since
reductions of 55 to 64 percent were reported for other coal-fired units.... The
applicability of this control system to any given unit and any particular Hgnltt
Will depend on slagging and efficiency constraints as affected by burner,
furnace, and soot blower arrangements. Successful prolonged application of the
technique also requires closer "-control over air flow''distributi on and better
control over excesf 02!'drift t:|an is currently available at most utility steam
\\ 'V' ** > . '.'*'' * ' '"''..
generators.
IV-14'
-------
V. EMISSION DATA TO SUBSTANTIATE STANDARDS
A. SUMMARY OF NOV DATA FOR LIGNITE FIRING :
,,''.".. X . I . ' . ' " ' ".,'.,,. "".''' ; ..''."'.-
A field test program covering four lignite-fired utility boilers was
conducted to determine NOV emissions under normal operating conditions,
. ' - , . " ' " ' . - '"-'- ' i' - ' . . "
low excess air and staged air.
The results of this test program are summarized in Table V-8 and
Figure :V-4. Details of the testmethodology are contained in Sections
B, C and D, and a complete listing of individual data points may be
found in Section E directly preceding the results summary.
B; DESCRIPTION OF BOILERS fESTEl) ^ ^^^ " ;
1. Basis of Selection
There are currently only five lignite-^fired utility boilers of greater
than 70 MW generating capacity in the United States; four;of. these were
included in the field test program, as shown in Table ~V-l,.r Note thaTof ;:
the 13 units planned; to go on line between 1975-1980, eight are tangential,\
three are cyclone, and two are hbrizontally-dpposed fired. All three types
. ' , i ' - ;= ' ' ' .'.'.' 'i '-'-,. . ...,'.',' _ ',
were tested. Additional reasons for selecting these units arc as ''-'..,-
follbws: (a) to include both Texas and North Dakota lignites, (b) to
compare emissions from nominally identical units (Plants I & II), (c)
to compare emissions taken in successive years (plant IV had previously
been tested by EPA8). .
V-l
-------
CO
LU
CO
CO
t4
sr
UJ
or
o
LU
O
LU
LU
CU
jQ
re
to
r- CU
4- =3 en
O to J3 i
r- 1
S- -E CU LO
CU 4-> -Q t-ป
3 O -SC^
C T3
O CU
r- (/> ฃ
tfl 4-> C
to to o
i- CU ซป-
pป 1 ^ c
LU CU
0.
n.
. 4- t- 3
O CU
CU-r^ S-
{) ^3 rt5
re CQ +j
Q CO
1
CU
0.
>^
I
S3
C
re
^"
&
r
O
O.
re
re
CM CO 1 CO
W l/>
tf> f^ \Q QQ f"^
vo i*^ 10 vor>.
en en cr> .en en
* *
a
CU
w -a
O CU
i- CJ C CD
S- >> O E
o o s- re
n: u. H-
. , ! : . - ..-
oo :bB ."^; iii
ea " bo LU o
t _ '
LO LO CM , LO
r" co t*^ r*^
CM CM i LO
14
> ป-4 t~t
H-l f-H >
4J '4J 4-> 4J
E S= C E
(^ re re re
51 ou al a- >-<
-------
2. Process Description of Plant IV
plant IV is a 215 MW steam-electric plant. The boiler,
desigrieel by Babcdck arid Wilcox, burns pulverized lignite which Is fired
through horizontally-opposed burners, as shown in Figure .V-l/. The lig-
nite is pulverized in one of ten pulverizers, each pulverizer feeding two
burners. The burners are arranged in three rows of four burners each on
the front wall, and two rows of four burners each on the rear wall. The
plant was first put into operation in 1966.
3. Process Description of Plant III
.Plant HI is a 235 Mlf steam-electric plant which burns
crushed lignite (1/4 in, size) in a boiler designed by Babcbck and Wilcox,
using eye 1 one burners. The bo 11 er 1 s dep 1 cted in F i gure V-2". there ;are
a total of seven burners located in two rows on the front Wail of the
furnace. Crushed lignite is fired tangentially into each burner at a high
velocity* creating a vortex effect, the burner temperature is maintained
at a sufficiently high temperature to melt the fly ash and thereby create
a molten layer of ash on the inside surface of the burner. The ash is
continuously tapped from the burner and is drained out through the bottom
of the furnace. In order to maintain high temperatures within the
cyclone, relatively low excess air is used. Additional air is added to
the hot gases after they leave the burners, creating a form of staged
combustion. This plant was put into operation in 1970 and, as of 1974,
is the only operating cyclone design firing lignite.
4. Process Description of Plants I & II
Each of the units is a CE twin furnace, tangentially fired
boiler of 575 MW rated load, as show.n in Figure V-3a and h. Annroximatslv
-------
".Z3
', "i
El-
V-4
-------
I
D>
V-5
-------
Figure 'V-3(a). TYPICAL TANGENTIALLY-FIRED BOILER.
V-6
-------
WINDiOX
AIR DAMPERS
DAMPER DRIVE
UNIT
Figure V-3(b). TANGENTIAL FIRING SYSTEM
V,
V-7
-------
4.2xl06lb/hr steam flow is generated at 1000ฐF, 3650 psig. Texas lignite
of 7000+500 Btu/lb heating value is carried through eight burner levels
by preheated primary air. Secondary air is preheated to 760ฐF to assist
in lignite volatilization and combustion. The primary secondary air flow
ratio is normally 35/65, and the overall excess oxygen is normally 3.2+0.4
percent. Less than 1 percent of the total airflow is supplied by the soot
i, - '.-,,*''
blowers, which number over 100. It is interesting to note that normal
operating practice at these units calls for the top burner level to be out
of service, which means that one-eighth of the secondary air (about 8 to
10 percent of the total air) is staged. The remaining seven burner levels
operate at about 105 percent stoichiometric air.
C. DESCRIPTION OF OPERATING CONDITIONS MEASURED
Three basic parameters characterize boiler operation: the chemical
energy feed rate, the overall-air flow ,and the air distribution to active
burners. Although gross load (MW) and excess Oo are "output" variables,
ซ . ฃ
they were used as convenient and reliable indices for "input" chemical
energy and overall air flow. This interchangeability is justified because
(1) combustion is essentially complete and (2) boiler efficiency is nearly
constant.
The air flow to active burners (as percent of stoichiometric) was
controlled and estimated differently f,or each bojl.er: ' ( . t
a. For Plants I & II, burner1'air *flow was varied by with-
holding fuel (but not air) from the top burner level. Three conditions
could be set up: no overfire with all burners operating, moderate over-
V-8
-------
fire with secondary air to the top idled burner level, or maximum pyerfIre
with primary and secondary air to the top idled burner level. For each
ca's'e'i the air flow was measured by calibrated pi tot tubes.
b. For . Plant IV, ho overfire was attempted and total air was assumed
equally distributed over the burners.
c. For Plant III, about 15 percent of the total air flow bypasses
the cyclone combustion chambers and is injected above the chamber outlets.
This air comes from the coat, handling and p>eliieat system. The amount of
overfire air as a fraction of total air Is fixed for all tests.
Additional variables also known to affect NOV were also measured: Wind-
' - " - ' ' - J\ '',".' - ' . . ' .=.
box temperature and pressure, ambient humidity, anil fuel nitrogen contentV i;
Sufficient steam cycle measurements were recorded to construct an energy bal-
' '.'' -'''. ' ';-'"'' ' --V. '.-.',. .1 '^'- . '. ' >' V;..:.v:. "'> ':'"-';';'.' . V. :V. ::
ance 'and verify normal operation of each boiler. The methods of measuring
these operating conditions are given in Table 'V-2 ,for Plants I & II;
''-'.','. ; ' , , . ' i -. . . '. : '-'','''-.' ."'.''*'.ซ',
nearly identical methods were used for Plants III & IV, -
Emissions data corresponding to discrete, identifiable, reproducible
operating conditions is impossible to obtain because of continuous drift ;
in operating conditions during each two- or three-r hour test interval.
It was not unusual for excess oxygen to fluctuate between 2.7 and 3.3 per- .
cent within one-half hour when set at 3.0 percent. The reason for this
drift is as follows: electrical output and steam flow typically are main-
tained constant with about to.5 percentby continually adjusting excess
air or burner tilt to compensate for transient slag buildup, coal heating
value, oir air flow variations. This drift contributes to the scatter in ?
successive NOX measurements taken at .onfr-half hour intervals. Therefore I
the averaged NOX data corresponds to an average cohdition representative j,
of the range over which the boiler conditions drifted. '.
V-9
-------
TABLE V-2 PROCESS MEASUREMENT METHODS
TYPICAL OF THOSE USED*
ITEM
Electrical load
Flue excess 00
Air to active
burners
(% stoichiometric)
Coal rate
Total air flow
Pressure drop across
burner and primary ai
flow
Air temperature
Relative Humidity
Steam cycle
METHOD OF DETERMINATION
Gross load before subtracting auxiliary
Measured before preheater. For Plants I & II,
values given are average,of two furnaces _,
(A&B) which typically differed by 0.3$ Op.
Stack 02 values expected to be larger be-
cause of preheater leaks.
For Plants I & II, air to active burners
can be estimated by noting number and level
of coal pulverizers out of service (see text).
For Plant IV, burner air was taken equal to
total air (no staging). For Plant III,
burner air was taken at 85% of total air.
Sum of rates measured for each operating pul-
verizer using the RPM of conveyor belts. A
scraper adjusts to maintain 100 Ib on each
belt. .Estimated accuracy +_ 2%.
Secondary air to each burner is measured with
Venturis. Total air determined from sum of
primary and secondary air.
Pitot-tubes in windbox and furnace.
Thermocouples in windbox (secondary), and at
pulverizer outlet (primary).
Continuous dew-point monitor. Changes due to
temperature not water content.
Flow nozzle at inlet to economizer measures
feedwater flow (503ฐF, 4200 psig). Pressure
drop across HP turbine measures throttle flow
(1000ฐF, 3650 psig). Approximately propor-
tional to load,,
* These methods were used for Plants I & II.
V^TQ
-------
D. TEST METHODS
A complete description of the field test methods may be found
in the Contractors' reports to the Emission Measurement Branch of
the EPA. ':-: "''"'. ' ' . -, '. '", - '..";...' ''.''.. . ...'.- ';; .':.'
The analytical methods employed fx)r the field test^ are summarized
in Table V-3. The primary analysis technique for NOx was the phenoldl- .
sulfonic acid (PDS) method (Method;7 as specified in the Federal Register,.
Vol. 36, No. 247, 23, December 1971J11. A continuous NOx monitor was
used to obtain on site information about the emission behavior of the
boiler, and vto provide back-up data in support of the PDS samples.
The Orsat ahalysis of Method 3 was performed to obtain 02, C02, and
CO with the methods outlined in the Federal Register.
Lignite samples were taken every half hour and the moisture,
volatiles and ash content qf the lignite Samples were determined by
using ASTM Method D 271-70.
Data on NOx concentration {Ib/dscftmust be multiplied by the
volume of flue gas produced per heating value '(dscf/Btu) to obtain
emission indices (Ib/Btul. the volume of flue gas produced per
h&ating .value was detenntned a| follows;. ___ ' v_LJ_____ _____
(i) by direct measurement of flue gas flow rate,
. r coal flow ratei and heating value.
(ii) by calculating the volume of combustion products expected,
using data on the coal composition*. and correcting for
dilution using excess 02 data ("F-factor" method).
-------
Table V-3 ANALYTICAL METHODS USED IN, ACQUISITION OF NOx EMISSION DATA
Substance
Reference
method #
Analysis techniques
Test series
NO,
co2
CO
Lignite
3
3
3
PDS
Electrochemical
Cheriri1umi nescence
Orsat -
Continuous Analyzers
on site
Orsat
Orsat
Proximate analysis
ASTM Method D 271-70
All four
Plants I & II
Plant IIIi Plant IV
All four
All four
All four
All four
All four
V-12
-------
Based on method (ii), which agreed with the value recommended In the
Federal Register^4' for sub-bituminous coal, a constant value of F >
98 dscf/104 Btu was/used for all data reduction; This F-factor must
be multiplied by 2090/(20.9 - Q2 percent) in order to estimate actual
flue gas volume per 106 Btu under air-dilution Conditionsv Excess p^
(percent) in the stack Was measured by thei Orsat method as described abpye.
Both methods (i) and (11) were used in calculation of dry gas
volumes, but emissions were calculated using gas volumes as idetermined
by the F factor method (method ii). Dry gas volumes as, determined by V
direct measurements were not used to calculate emissions because for
all four test series these volumes were 5 to 16 percent greater than
expected from the elemental.composition of lignite and there was much ;
scatter in the data. Consequently, the emission rates in the lignite
tesb were calculated using the F factor method. A subsequent study on
a lignite f ired- steam generator'showed excellent agreement between: dry
gas volumes as calculated by the F factor method and as determined by :
direct measurements. The follow up study^^ also indicated that the
discrepancy observed in the four lignite tests was due to errors in the ;
measurements of gas velocity..'^(Seie Appendix B for discussion of
discrepancy of data reduction procedures.) \
E. DATA REDUCTION PROCEDURES
The emission index E (Ib/million Btu) was calculated as NO^ from
the following expression: ,
'- ."..-''- E = 1.215xld"7CFD ' ':";:;"" .-'." ,; .-'".. " V
-------
where C = NOx concentration (ppm, dry basis), F is the dry flue gas
volume (dscf per 10 Btu) at zero excess air as. discussed above, and D*
2090/(20.9-percent 02). The F-factor method was used to calculate
emissions with F taken to be 98 dscf/104 Btu. A simpler F-factor method,
which results in comparable values, was published in the federal- Register
on October 6, 1975, (40 FR 42650).
Based on an analysis .of the uncertainty of emission measurements,
we estimate emission uncertainty at *.9 percent, t 7 percent, .and +
6 percent for Plants I & II, Plant IV, and Plant-Ill series,
respectively. (See Appendix B).
AIT NOx data taken during a fixed boiler operating condition dur-
; ... - ;
ing any one day was averaged .PDS. data only, adjusted as noted in Ap-
pendix B and supplemented by electrochemical data where appropriate.
We denote this average .
The 02 data was also averaged for each test interval and dilution ,
corrections applied to reduce (NOX) values to common dilution condition
(3 percent 02). The lignite feed rate (ton/hr) and stack gas velocity _
were also averaged over each test series. From this average data, a .
representative dscf/Btu value was calculated by both direct method and
F-factor method.
In addition, all baseline (WOX at 3 percent 0'2) data for a given
boiler were averaged, and standard deviations derived (weighted by
the number of samples per test interval). The values of E(or NO at
3 percent Op^from successive test series were usually within the 8 per-
cent estimated scatter. ; , \
V-14
-------
,F. '-'RESULTS, ''.;' ;." '; ;-./;" ' -/-.-' *. /.' . '':'.'", \\.-.- ;';:';;-..'-: . .: .''..
Test results are presented 1n TablM V-4 through V-7 for the four
utility toilers and a summary of results Is given in Table V-8 and
;Figure y-4.SpeGifie values are presented, and calculated averages
;for the test condition are given in brackets:<>. Questionable data
discarded are given in parentheses. Data listed for a given tinie
day was taken usually within ten minutes and always during the half
hour following that time of day. Nitrogen oxidts emissions are^cal-
culated as N02 and are givซn three ways: g/106 joules, lb/ld6 Btu,
and ppm(dry) @ 3 percent 02.
V-15
-------
TAOLE V-4. DATA FROM PLANT I
Day H*ur*
f/30 1100
1X0
30
1400
30
1500
90
ttfjn
MOO
10/1 1000
M**a
TTof-
30
1100
30
1300
90
1400
Jh**-_
90
1SOO
X
1100
Mean
10/20*00
90
1030
M
1100
30
1200
30
1900
*M-
X
1400
30
1500
H*an
10/3 0700
90
MO
90
MO
30
Hป.
1000
93
1100
Bt*B_
30
1100
30
1900
ttttt-
lajj-^
1400
10/4 0409
*3
TfiSr
99
1103
1209
30
^ss-
M
Heating
Fled value
Laid r*ti (jaulet/g.
(ป0 (kg/sซ) rec'd)
607 108
609 108
595 104
596 104
<601> *10fiป 14.900
483 84 14.900
597 101
<597> ซ101> 14.020
599 102
597 102
595 101
ฃ00 102
*KOR> onป> I4.njn
598 103
600 105
ซ599> <104> 14.020
593 101 14.990
592 103
594 103
560 97
594 102
*im* i4. <102> 14.990
602 104
601 105
599 105
<-ซniป ซ105> 14.4(10
602 104
602 104
<602 > <1W> 14.400
601 106 *
601 106
I4.4nn
600 105 14.400
595 106
13.480
594 107
593 107
594 107 "
HS94> <107ป 13.480
592 106
13.480
pUrntr
ซ1r
Condition (X Stolen)
Baseline 105
Low load 105
Baseline 104
Lnw air 103
Baseline 105
High air 111
Baseline 104
Hloh ซ1r ' 109
Baseline 106
Ma$( overflre 101
Baseline 104
Hloh air 107
No overflre 114
Baseline 104
-IJOx (PP") ,
Method
7
* Analyzer
254
262
299
279
309
338 (110)
314 (HO)
310 (100)
<295>
<333> (90)
289
338 410
<309> .
345 370
335
317
328 390
- 380
346 385
280 (365)
<333>
(75) . 365
357 372
(413) 385
339 380
<341>
268
(96) (285)
334 250
307 380
370
354 310
(570) 315
(2987) 315
346 > 250
<335>
(5905) (260)
304 320 '
309 320
(701) 335
<306>
306
300
(202) -
308
<305>
|559) 370
(3057) 435
(267)' -
295
209
(470) 200
(2942) 200
<25&
393 220
(1089) 250
(565)
475 (37SJ
(385) (500)
358
288
311 310
(477) 275
(2687) (85)
<310>
275 (55)
271
,0j (*
Method
3
* Analyzer
3.2
I 2^8
- 3?7
(6.3)
3.1
3.2
4.6 3.6
5.2
<4.9> _ -
,5.2 2.8
(7.6)
4.1 2.6
5.3 -
(11.0) 2.8
(8.1
(10.0) 2.7
<4.6>
5.4
4.4 3.2
(6:5) 3:2
<5.0>
6.0 4.2
5.3 '
H 3:6
! 4.3 2.8
3.0
.' - : s'l
,4.6,
4.8' 3.0
4.4'
6.4 3.2
<5A -
5.0 3.7
S~2 3~.9
5.0
5.8 3.7
5.7
<5.4>
5.4 3.4
(7.0)
5.8 3.5
5.1
5.6 3.2
5.2
5.8 3.1
<5.3>
4.8
<4.9> 3,1
6.0 3.9
6.2 3.1
4.9 3.0
4.9 2.5
(6.3) 2.3
' 4.5 2.7
4.6 2.5
5.0 2.5
<4.7>
5.9 2.8
*ซeซl/104. Ml
F-factorb
Mtthod Method
2 .. * ., ,
.0155 .0148
.01 5? . .0148
.0161
.0161 .0145
*
.0160 .0143
.0157 .0146
.0156 .0155
.0155 .0143
.0152 .0146
.0177 .0149
.0160 .0152
.0155 .0145
.0162 .0145
.0175 .0156.
.0171 .0144
.0173 .0746
NO, DMulMC
"(tiling*)
.9 y pp.
106 joules 106 bttt * Jlflj
0.20 .47^ 332
0.23 .53;; 37S
0.21 ..49>, 340
^22 >5>, 360
.23 .54;, 37ป
.19 -.451 314
.22 .52. Xt
.21 .48' 348
.21 ..49:' 940
.17 .40^ ' 280
- -
... - -
.21 .48. 340
.
*Ustปtf tlM Includtl 1/2 hour Interval which followed.
<'Values rtpresentattve of test series.
()DปU In Hrenthcses were discarded according to screening criteria discussed 1* the text.
b$eซ Section 1V-0. Appendix B a.nd Reference 14.
Sleight tmltt are calculated ซ N02.
V-16
-------
e
IP[|
ฐEฐ!fl '
5 g
ง>< I
ซO -M *
fcfi*
;*
&
15
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a. -, S
'fa-*.
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V
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v: ; ;;>'': V
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'f^-^M;*.
"''"... '?-i:.
"r-." '; ' ' .' .- en -
-.. ..-. ' - o
, ซ CO CO CO *ป ' CM
CO CO CO to . <*3 ซo
cocoซi^ซ.eocoi-.i-ป4
1 ' . v
. r^ co r*ป f"ป 10 en co c^ o ci o ^3 i
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, , ,"~ ; . .-ซ.-.-. ._. ...;t v
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So , o co co en f*"* .
1 CO 1 CO I U* 1 F^ 1 ^ ^
m ' S S m m mm
O O O C6 O C3 O O O O O O C
CO ^p to C3 (O C7 <*)' O CO O CO ^3 1Q
CM co *r m ซo . rป .eo M1
o '.'-. ..
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' : '' - :a
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in ซ
CO CO
eo^^ in CM r
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CM CM CO CM
CM CM CO CO CM
;-- ;-..ง
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ff imr -%r -* *"^^ "^
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V'-;|
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in ** in in
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in in^ in in
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ffo-gSfSJ
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el
'^*'
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' .A
IT) t ซ5 O
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O CO CO .
-. *
fm gjo
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krf v
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S , SS
;-. V
S , SS
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','' ' : ; '...:.'',.)' .'-.: *!
' .'':' '-,-.' 'ง
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'" /'.... 'c
en o r- to o
>-. i i o. i ; - 1 o i o r
--.-. ? : .- - "V
' A
en CO 'r^ co r^ r^eo
en i en i en i .en i en i encn
in m .in ' in in mm
: - ' , - ' ; y
oooooooooooc
C7COOCOOCOC3COOCOC3 It
Ol O r CM .CO, ซT O
J'V.'V ''"
: s
1 -. . co
'' s
.'"
';;-''5
'*:''--*.
.;.".'.ป
'^.
ฐ; ". i
<ป CO .
eoeoomrx
ooinco
*^* - e
"'-: -'-s
. ' *'
- . ' ' .oป
-:'*
' :/': ^
o o o
g 'is
S222 c-
~ v 10 ^ n
* K u> J
5
e
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: i:;
I
.
i
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f
ll
Is.
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lssl"
!ซ*
5V" ฃ
u *ป id
J81
>*s I
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*ป w o
p u cu
V ซ 3
-------
TABLE V-l. DATA FROM MANT HI
Day Heur
10/7 0ซ30
osoo
30
1000
30
1100
30
1200
30
1300
1400
30
10/1 0800
30
0*00
1000
1036
1100
1200
30
iSST"
30
1400
30
1SOO
io/ป osoo
VI
JW
MM
vปw/
30
1000
TOO
1100
30
itffi
i *w*
30
TjQJr
lion
TปA/
30
1500
10/10 MOO
30
OHO
30
1000
TEST
lino
1 IVAJ
30
1200
30
HMD
Heating
Feed value
told rate (Joults/g,
(BW) (kg/sec) rec'd)
251
251
250
251
252
252
51.5 15.400
251
252
252 "
<252> 51.8 14.690
251 .
251
<251> 51.5 14.690
__,
250
251
<251> 51 .5 14.690
252 51.8 15.110
254 52.3 15.110
3S2 51.9 15.200
ZS1 51.6 15.200
Burner
air
Condition (X Stolch)
'
.
.
Baseline 106
Baseline 107
Lax air 102
Baseline 107
Baseline 107
H1oh air 109
Baseline 106
Baseline 106
"H1 <581>
564
566 600
562 600
530
577' 545
<560> <581>
~T47 460
408 430
484 480
482 480
483 500
<461> <470>
524 540
558 560
542 565
560 560
571 570
473
503 520.
503 520
472 520
506 550
< 491 > < 528 >
~~3ง1 655
586 600
655 620
598 620
624 640
<609> <617>
~SH 525
615 610
. 631 . 630
684 640
626 610
< 635 > < 622 >
518 540
517 520
550 540
560 560
524 520
<534> <536>
503 530
518 540
464 540
336 540
573 560
<519> <542>
02 (X)
Method
* Analyzer
4.2
4.3
4.2
3.8
3.4
- 3.7
3.6
3.7
3.7
3^9 -
3.0
<3.7> *3.8>-
4.0 3.7
4.1 4.1
4.0
<4.1> <3.9>
3T5 =
3.2
3.5
3.1
<3.2>
3.9 4.0
. -
3.1 3.7
3.8
<3.8>
3.8 3.3
3~.B 3.8
. _
3.9
<3.7> <3.8>
335 ::
3.8
4.2
4.1
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O 3^
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3.7 3.7
' '
3.6
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3.8 3.8
3.4 4.0
.
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3.6
4.1
4.1
4.0
<3~9 - < 4"l >
dson/10* cald
F-factor
Method Method
2
t
.0152 .0135
.0167 .0138
.0162 .0133
.0169 .0133
.0156 .0135
.0164 .0138
.0159 .0136
.0156 .0134
.0163 .0136
NOX Emission
106 joules 107 ttu fiXOj
* '
.34 ^.78, 560
.36 ..84 (00
.28 ,..ซ 470
.
.34 .,ปป S70
^31 .72 5ป
^
.39 .ซ (SO
.40 -M 00
.33 .71 WO
'
.33 .71 999
*Duct 1
only (sec t*xt).
Cj[tCO Chcollwlnescent.
Stetieo IV-0. Appendix B aid Reference 14.
V-l 8
-------
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80
LEGEND:
O PLANT I
V PLANT 11
A "PLANT III
P PLANT IV
Characteristic
Uncertainty
for Each Point
ฑ 35 ppm
90 100 110 120
Fraction of Stoichiometric Air at the Burners
130
140
Figure V-4. N0y EMISSIONS FROM LIGNITE-FIRED BOILERS.
V-21
-------
G. DISCUSSION
1. Comparison with Prior Data
Table V-9 compares the results of this program with previous data.
NOV measurements on all four boilers agree fairly well with previously
/\ " """'''
published data when the estimated uncertainty of 35 ppm is taken into
account.
2. Effect of Low Excess Air and Staging ' '' ''
Reducing excess air flow to the active burners can yield about a
20-35 percent reduction in NO emissions, as shown in Table V-8, V-9 and
J\
Figure V-4. For tangential units, the overall air flow cannot be lowered
more than 5 percent. The only viable way to lower burner air is by in-
creasing the overfire air. For the horizontally opposed fired pulverized ',
unit, reduction in total air gives a 34 percent NO reduction. The
X ,
cyclone-fired boiler proved responsive to either LEA or staging.
3. Effect of Boiler Type
Horizontally opposed fired and cyclone boilers appear to give nearly
comparable uncontrolled NO emissions (650 versus 580 ppm), a level
f\ ' ' i ' i
which is about 70-90 percent higher than the tangential units (340-350
ppm). However, the horizontally opposed fired and cyclone boilers
appear more responsive to NOX control! techniques percentage-wise, as
is indicated in Figure V-4.
4. Effect of Fuel Type " " :.
The test program did not permit firing two substantially distinct
lignites in the same boiler in order to discern fuel effects. There
are two expected effects, however:
a. Moisture - The hiqh moisture content of lignite relative to
bituminous coal might be expected to control both thermal NO and fuel
x
NOX to the extent that water evaporation occurs in the volatilization
V-.22 ...
-------
fable V-9 NOV DATA COMPARED TO EARLIER PUBLISHED RESULTS
' , " '"'.'! " - ..'.,
, FOR LIGNITE-FIRED UTILITY BOILERS
Unit '
Plants I & II t.
Plant III
.. ;' ' '' ';": ','' :'-' '"
Plant IV f
Condition
Normal
Staged
Normal
LEA/Staged
Normal
-LEA
Staged
NOX (ppm (3 3%02)
This work Prior data
''.,'. ' ' ' t,
350
280-330
580
470
650
430
- ' '.
390
- *'.
A 290
620-750
540
440
560-580
570
450
380
Ref
Habel %<ฃnd
Selker10 ,
-=;: -..,".. .' .-
Gronhovd et
Duzy andgg
Duzy and?n
Hillier U
Gronhovd et
Crawford et
:.".-' ป .;
"..' -.'" "'"
V-23 /
-------
zone of the flame. Indeed, restricting our attention to the tangential
furnace, the mean uncontrolled NOV emission level of 16 coal-fired units
" ...
was about 15 percent higher than the mean uncontrolled NOV emissions
*ป
from 11 lignite- and subbituminous-fired units. The current emissions
results for lignite-fired cyclone furnaces are well below the results of
early studies on NOX emissions from coal-fired cyclones.
b. Fuel Nitrogen - Evidence is mounting that as much as 90 percent of
the observed NOY emitted from pulverized coal is derived from organi-
*ป
cally bound nitrogen.47 The NOV levels observed in this program may
*ป
have resulted from a 15-25 percent conversion to NOX of the organically-
bound nitrogen in the fuel. The lignites tested contained 0.9 - 1.0
percent chemically bound nitrogen, on a dry fuel basis.
V-24
-------
VI. SUMMARY OF ECONOMIC INFORMATION ' ;
A. PURPOSE AND APPROACH ,: :v
The purpose of this chapter Is to develop art economic Impact
analysis for application of the control systems identified in v
Chapter IV. The approach to the economic impact analysis was as
follows: '. . '. .;' : * .;-.'... '.'.. ' ;: ' ' . _.- ;;." V' > /.;: , .
1. Derive baseline capital:investment and annual production
costs for three selected model lignite-fired steam-
.electric generating plants (Section B$;
2. Derive capital investment and annual cost of control for
each of several alternative NOY abatement schemes
- - . -,.".'.' '.'''.-'! * ,. -'. - .- ' * '*ป ' - ' * ."' .- - -
; '. . (Sectipn 6); , ^ :',.,... ."'.'" ''/-.;.-'-/' :'< ,.."> ''''.
3. Compare the cost of cpntrol for the alternative NOx
limitations, and develop a cost-effectiveness curve
'"'.;. , (Section D)j . .,
4. Evaluate the direct impacts of the various NO^ lintitations
upon the cost of pbwer, the lignite-fired utility industry
and .the mapor boiler manufacturers. Also evaluate the
possible indirect effects on related industries such as the
lignite mining industry and the conventional bitumindus-
fired utility industry (Section E). .>
B. BASELINE INVESTMENT AND ANNUAL PRODUCTION COSTS
The reduction of NOx emissions from lignite-fired steam-electric
generators, is accompanied by an incremental cost differential which
is expressed both as an increase in capital investment (or instal-
lation) costs and annual produeti on costs. The logical first step fn
VI-T
-------
investigating such additional costs is to develop a baseline cost to
' ' '. * - '
which these incremental costs may be added. The model plant sizes
thought to be most indicative of future lignite-fired units, and selected
for analysis here, were as follows:
250 megawatts
450 megawatts ,
750 megawatts
Based on discussions with various utilities and the selective use
of plant financial data as reported by the Federal Power Commission,
it was determined that actual'baseline investment and operating costs
for field-erected central station steam-boiler units are largely a
function of the plant size and fuel characteristics, and are independent pf
burner configuration. Thus, the investment and operating costs estimated
for this study were assumed applicable to all three major burner config-
urationscyclone fired, horizohtaTTy" o|>]D61fe^^, ""
Of the 24 utility-owned units identified within the U. S. (see
Table II-2), detailed cost information was collected on 21 units and is
summarized in Appendix"C. .From this-list, which represents 98% of the
installed generating capacity and 97% of the annual production accounted
for in Table II-2, we derived the followina:
Unit investment cost ($/kW) as a function of total
plant size, and .
Actually, the weighted average unit size for planned lignite-fired
plants is about 600 MJ.
* Federal Power Commission; Statistics of Publicly-Owned Electric Utili-
ties in the United States, 1972; Statistics of Privately-Owned Electric
Utilities in the United States, 1972.
VI-2
-------
Unit production costs (mills/kWhj as a function of annual
net generation. " ; ;
In general, it appears that no significant differences in unit costs
exist between large (> 200 MW) lignite-fired and coal-fired plants.
It was felt justified to estimate capital investment and annual produc-
tion costs for lignite-fired units based upon those costs typically
used for,.coal-burning units. The expected installed cost of a new uncori-
ic .
trolled coal-fired central station steam-electric power plant in the
U.S.* is on the order of $350-4QO/kw + in constant 1975 dollars.++
' 37 1ft 3s concerned with estimates
of the cost of new coal-burning plants for base-load utility service,
We have estimated the following total capital costs ** for new uncon-
trolled lignite-fired electric generating plants:
Model Plant Size (MM) Installed Capital Cost ($/khl)
250 420 ;;
450 395 v
750, , '365
**
An uncontrolled plant is defined to be one without either particulate,
S02, or N0x air pollution control equipment.
Includes-$15/kW for thermal pollution control cost.
'Design engineering estimates of the cost breakdown of complete new
lignite-fired generating plants (each of which typically represents a
quarter of a;bill ion dollars) are beyond the scope of this study.
Figures are in 1975 dollars and include interest during construction.
VI-3
-------
Using these capital costs, annual production costs were estimated
for the 250, 450, and 750 megawatt model plant sizes. These costs are
summarized in Table Vi-TriTrid "were derived under thei 'foilowing assump-",
tions:
Capital charges reflect a level fixed-charge rate to
cover interest, return on equity, depreciation, taxes,
and property insurance.
The annual fixed-charge rate was assumed to be 15% as
representative of the investor-owned facilities, and
10% as representative'Of the rural electric cooperatives.
Regarding investor-owned utilities, an assumption of 15%
is.consistent with traditional Federal Power Commission
and. Atomic Energy Commission cost estimation guidelines,
conventional utility financing, accounting, and taxation
based upon 60-65% debt funding, approximately 8-1/2%
long-term bond interest rate, and a 30-year depreciation.
The 10% used for rural electric cooperatives reflects
their reliance on lower cost REA financing (5%/year), and
different tax status.
t A load factor of 80% was assumed, resulting in 7,000
annual operating hours. (Some of the older lignite plants
have historically shown lower load factors.) This estimate
is supported by the intended use of large lignite-fired
plants as base-load plants, many of which are cooperative '
projects which will be producing large demand wholesale
electricity.
VI-4
-------
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VI-5
-------
Lignite costs are based on 1975 prices, and were assumed
to be $2.40 per ton delivered. This is consistent with
unit price estimates made elsewhere in this Chapter.
The plant heat rate was assumed to be 10,000 Btu/kWn and
the heating value of lignite to be 7,000 Btu/lb.
Plant operating and maintenance (O&M) costs were assumed
to average 1.5 mills/kWh for all plant sizes based on
i
averaged data from the Federal Power Commission (.re-
produced in Appendix C).
C. ESTIMATED COST OF NOV EMISSION CONTROL .
X
The NOX control technologies summarized in Chapter IV are based on
combustion modifications to the furnace and/or auxiliary equipment,
which in turn implies a differential cost of manufacturing. In view
of this, our basis for costing NOX control schemes is based upon direct
communications with the two major boiler manufacturers. Based on dis-
cussions with these manufacturers, the following observations are
made:
t Significant reduction in NOV emissions can be achieved
t X
most readily using low excess air in the fuel admitting
zone and/or "overfire air," otherwise known as "staged com-
bustion." This is consistent with the findings of Chapter
The incremental cost of adding overfire air ports to any
boiler configuration is relatively minimal, and in the
case of both manufacturers, will require no major modifi-
cations of the windbox.
VI-6
-------
t Other alternative combustion control schemes such as low
emission burners are being tested, although insufficient -
data exist which would confirm that such schemes could, ,
greatly reduce NO emissions below those levels "achievable:
.''.'.' .t ''.-.' * ' .. ,:. ' -v" '' ^_ '.;*-
through the use of staged combustion and low excess air. '-";':
While manufacturers have widely differing opinions as to "
--''.-."
, .the effectiveness of schemes other than staged combustion,
they agree that the approximate range of NO emission levels
i .- ' ... J\ f . ~
achievable using staged combustion would be consistently
equal to, or somewhat better than, the present 0.7 Ib/iO Btu
standard for coal-fired boilers. ',
Based on input from manufacturers, Table VI-2 summarizes thcTcoslT
impacts attributable to the most promising alternative control schemes:
staged combustion, low excess air, combined staging and low excess air,
and low emission burners. These costs are not applicable to cyclones.
The incremental investment shown is expressed as a percentage " ,
of "boiler island" cost, not as a percentage of total cost. The "bpiler .
island" consists of equipment relating to fuel preparation and handling,
steam generation, fans, soot blowers, and auxiliary boilerattendantsj, ;
among others. Based on discussions with manufacturers, we assumed the.. -..'.
boiler island costs to be 12% to 15% of the total plant costs excluding
air pollution control equipment, or $55, $50, and $45 per kW for the 250,
450, and 750 megawatt model plants, respectively.
In regard to low emission burners, it should be noted that one
manufacturer was constrained in the level of NO emissions which could
." - - X ' '".',-_"
be achieved as recently as 1970. Based on verbal discussions with this
VI-7
* f
-------
Table VI-2
ALTERNATIVE CONTROL COSTS FOR NOx EMISSIONS
FROM LIGNITE-FIRED STEAM-ELECTRIC GENERATORS
Control Method
Dual Register Burners
Staged Combustion
Low Excess Air
Impacts
Estimated Incremental Cost (%)
Installation 'Costf(arPrbd, Cost'(b)
Negligible, if any,
loss in efficiency.
No additional operating
costs.
Negligible, if any,
loss in efficiency.
No additional operating
costs.
Negligible, if any,
loss in efficiency.
0-3
0-3
0
Combined Staging
and Low Excess Air
Minimal loss in effic-
iency .
0-3
0
(a) Percentage of boiler island cost, assumed to range between $45-55 per kW. Assumes
boiler rating remains constant.
(b) Percentage of conventional production costs (excluding capital charges,) assumed to
be 3.3 mllls/kWh (Table VI-1). ' )
V ' f
SOURCE: Arthur D. Little, Inc., estimates, based on discussions with boiler manu-
facturers.
VI-8
-------
manufacturer, it was reported that major design changes dealing with. '
the installation of compartmented windbbxes and dual register burners
resulted in a reduction in NOX emissions level from 0.9 to 0.6 Ibs/IO6
Btu. * The incremental investment associated with these changes
has been estimated to cost $1.50 per kW.
Given the data in Table,VI-2, investment and annual control
costs by model plant size can be estimated, and are shown in Table VI-3.
Again, the upper range of the estimates are believed to be conserva-
tive so as to allow for potential error and to permit an analysis of .
maximum economic impact. '
Finally, Table VI-4 summarizes the control costs assumed for
several alternative levels of NOX emissions attainable with the,
most promising control systems based upon the dpsts shown in Table VI-3
for each model plant size. The mean cost estimates of"table VI-3 -r
were used and rounded upward to the nearest dollar or nearest hundredth
of a mill. , ',,. :
D. COST EFFECTIVENESS OF NOX CONTROL ".'-"
= A , , '. '',."'
Figure VI-1 .graphically relates the level of obtainable NOX
emissions as a function of the incremental capital investment and
annual cost for a 600 MW plant, or that size which best represents
the size of new lignite-fired units. These costs are applicable
only for pulverized-fired units and exclude cyclones.
This manufacturer plans to furnish the dual register burner on
new units, and would offer staged combustion very seldomly and
only for well defined fuels.
VI-9
-------
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-------
Capital Investment ($/kW)
234
Low Emission Burner,
Staged Combustion
Low Excess Air
Combined Staging
and Low Excess Air
0.1 0.2 0.3 0.4
Annual Production Cost (mills/kWh)
I
I
I
0 1 23 45 6
Capital Investment. ($/kW) .
Comparative Investment for NOX Control Alternatives
"Applicable to pulverized units only, excludes cyclone-type burners.
Source: Arthur D. Little, Inc., estimates.
Figure
COST EFFECTIVENESS OF NOX EMISSIONS CONTROL
OF 600 MW LIGNITE-FIRED STEAM-ELECTRIC GENERATOR'
VI-12
-------
The relatively broad band of costs reflects the range of emissions ;
performance associated with distinct boiler/burner designs. Although
the exact limit is debatable, manufacturers are in agreement thatfto
guarantee NOV emissions levels somewhere below about 0,4 lbs/10 Btu
A ' - ' . -'_'..'"
would be technically infeasible regardless of cost. ,
Those tangentially-fired and horizontally-opposed units presently
sold can generally meet the NOX standard of performance for coal-fired units
(0.7 lbs/10 Btu) with only minor investment. Tangential units will be.
able to achieve a level of 0.6 lbs/10 Btu without additional costs. .
Horizontally-opposed units will also be able to meet a level of
0.6 lbs/106 Btu. The applicability of control technique for horizontally-
opposed units at 6'. 51 bs. 71 06 Btu has not yet 'been well"demonstrated;
E. ECONOMIC IMPACT ANALYSIS " ''
The lignite-fired steam-electric generating "industry," as it applies
to this analysis, is unique in two respects. First, it is more appro-
priately considered a sub-industry of the steam-electric utility industry,
and second', the behavior and general economic health of the utility
industry is strongly determined by regulatory authority pressures rather
than, by the more conventional market-oriented pressures of other nonregu-
lated industries. These differences suggest that the economic impacts
brought about by the setting of NO emission limits be presented
. - . ,,,... ^ --
in a slightly different fashion than in previous industry impact
studies. In general, there are three distinct areas which will be
directly affected by the incremental cost increases associated with
NO control of 1 ignite-fired steam-electric power plants:
*\ , .. , ". ;: ' -' - ' " - ' - " " '
vr-13
-------
The cost of electrical power production,
The lignite-fired utility industry, and
The boiler manufacturers.
Each will be discussed separately, in addition to a brief discussion
of secondary impacts on related industries.
1. Effect Upon Cost of Power Production .
as follows, depending on plant size:
Emission Factor
Lbs. NO../1Q6 Btu
"" '" 'A
0.8
0.7
0.6
0.5
It appears that the impact of NOV control on the cost of new
X . s
generating capacity within any particular utility is relatively
negligible even under the most stringent NO standard under consideration.
A ' ' '
Figures Vl-2 and VI-3 summarize the comparative capital investment.
and annual costs of NO control on investor-owned or rural electric
A , - -
cooperative utilities with and without S02 control. Based on these esti-
mates, the following may be concluded as the effect of NO control on the
A
cost of power:
Incremental capital investment costs for NO control range
A '
0
1-2
1-2
1-2-
Percent Increase i n
Power Plant Investment Cost
0
0.3 - 0.5 \
0.3 - 0.5
0.3 - 0.5
From this*, it appears that the difference between a control
level of 0.8 Ibs. NO/106 Btu and 0.5 Ibs. NO /106 Btu
..x x
poses no significant economic barrier, and that the effect'
on capital investment of the most stringent alternative
levels would result in only a KsY^nrnpfsFTrTcapital
investnent requirements.
vr-i4
-------
(M>l/$) 1U3011S9AUI Jl
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VI-16
-------
t Concerning annual 1 zed production costs including fixed
capital charges, the incremental cost impact of the
most strinqent4IQx..1imit is small,as indicated
in Table VI-4.
Reflecting upon the way in which costs are passed on to consumers,
the cost of power is generany a weighted average of the cost of pro-
duction for the"ut1.T1.ty as a whole. Thus, if it tง assumed that
existing capacity retains tts present level of control, Incremental !
increases in power costs for the utility's customers would be less
than ;cited above.
2. Effect Upon Lignite-Fired Utility Industry
Implications based on the previous sections are that the incre-
mental cost of NOX control on capital requirements and annual pro-
duction costs are relatively minimal, and could readily be handled by
the affected.JiltItltfes, _;
3. Effect Upon Boiler Manufacturers .
The market for large steam-electric furnaces within the U. S. 1s
dominated by four suppliers, two of which have an estimated 70% of the ,
market between them:
Company AA 35%
Company BB- - 35% .
Company CC 20%
Company DD 10%
Of these, Companies AA and BB have supplied furnaces for, all lignite-
fired installations greater than 200 MW, and will be responsible for
virtually all announced capacity increases within the industry through
1980. In both cases, lignite units have accounted for a minor
percentage of their annual revenues.
It is extremely doubtful that foreign manufacturers will enter the U. S.
market for lignite furnaces.
-------
We believe the market for lignite units will continue to be
dominated by AA and BB following 1980, providing the NOX emission
limit which is adopted does not result in a restraint of trade
situation by effectively constraining one (or both) of the :
companies for technical reasons.
Both companies have a positive attitude towards being able
to meet a limit of 0.7 or 0.8 Ibs NOX/106 Btu heat input based
upon the adoption of staged combustion (overfire air) or dual
register burners to furnace configurations other than the cyclone.
Likewise, both companies are willing to guarantee to their customers
the ability of their furnaces to meet such, a limit. Thus, there are
no foreseeable marketing disadvantages which might affect the balance
between Company AA and BB and thus act as a restraint of competition.
The adoption of an NOX emission limit of 0.6 Ibs NOX/106 Btu,
could have a slight effect on the competitive position of Company BB
relative to Company AA. In thisjnstance, cyclone-type burners
^
probably would not be guaranteed by BB, and would result in its .
removal from the list of alternative burner systems available to
utility pruchasers. However, this would not necessarily impair
Company BB's position, since cyclone units represent a small proportion of
coal-fired utility boiler Sales due to their lack of fuel versatility
or cost advantage.
Finally, the adoption of a limit of 0.5 Ibs NOX/106 Btu would
probably result in the destruction of a competitive balance between the
two major manufacturers, even after assuming Company BB has foregone
* A boiler supplier generally guarantees a.certai.n emission level when
-gKRi^lince, has shown rts equipment is_ capable of bettering the -*.-.
allowablestandard "by"at least 0\1 Tbs'NOx/T0^7BtuT "" ' ~
"" " - - VI-18
-------
the cyclone burner. At this level of .emissions, the burner :
configuration (horizontally-opposed) by which Company BB will base
its future lignite fired business may not consistently achieve 0.5 .
lb/10 Btu. Consequently Company BB may not offer performance
guarantees to purchasing utilities; leaving only one major
established supplier. We do not believe it is in the best
interests of purchasing utilities to remove their option to
obtain competitive bids for industry expansion. Further, at an
emission limit of 0.5 Ib NOX/106 Btu,, Company AA may not Offer
compliance guarantees either. '.-,. ,,
4. Indirect Effects V
In addition to the above three sectors, there is a possibility of
some indirect effects due to NOX emissions abatement on lignite-
fired plants. In general, most such secondary effects will be
comparatively minor; however,' those dealing with the following should
be noted anyway:
'. Lignite's position as an energy resource,
,'. Lignite mining industry, and
. Cost of lignite.
The effect on lignite in relation to bituminous-coal due to the
inclusion of NOX emission abatement on new sources appears to be
negligible. Moreover, the relative cost of NOX versus S02/particulate
control dictates that no substantial economics of production can be /
obtained by those facilities without NOX control assuming all :
facilities are equipped to handle S02 and particulate emissions. It
, ;'' vi-i9 '.. - , ... ,,,' .,-'
-------
appears logical that any change in the percentage of installed
capacities firing lignite instead of other fossil fuels will
occur for reasons other than NOX control.
Regarding lignite mining, the unit consumption of lignite
per kWh is not expected to be affected by NOX emission limitations.
Finally, concerning the cost of lignite, we note that the
relative isolation of large lignite reserves plus the fact that most
utilities operate captive mines or have established long-term
contracts will probably constrain the f.o.b. mine price. Of those
utilities of concern to us, all have long-term purchasing agree-
ments or own and operate captive mines. Their activity in 1974 was
as follows!
Utility
A
Fuel Supply
Buys lignite under contract at $2.32 to $2.73/ton
f.o.b. mines. .
B Owns and operates lignite mines, and is developing
a new coal mine at an estimated cost of $8.5 million.
Their full costs were about $3.30/ton delivered,
C Owns and operates lignite mines through a subsidiary
company; 1973 price at about $3.00/ton.
D Buys lignite at $2.15 to $3.00/ton.
E Recently participated in expansion of leased lignite
reserves at plant's mine-mouth ($1.52/ton in 1973).
F Buys lignite at $2.24/ton.
We are of the opinion that lignite prices peaked in 1974, and.
that prices may be leveling off, with a slight downward trend expected.
VI-20
-------
Lignite prices paid in 1974 were, according to the Office of Coal ;
Research, about $1.50 to $1.75 more per ton than 1973 prices.
; We do not believe that NOX control costs will directly affect
lignite prices, nor is the attractiveness of lignite so great ;;"'
versus bituminous fuels that its price can be expected to increase
substantiany. "'''-."."
VI-21
-------
-------
VII. RATIONALE FOR THE PROPOSED STANDARD
OF PERFORMANCE
Based on the technical information presented in Chapters IV and V,
" ' ' , " ' ;',"'. -*.''.
it can be_concl.uded that low excess air, staged combustion, low
emission burners and combined staged firing and low excess air are the
best systems of emission reduction. In addition, the method of firing and
boiler design parameters can affect the quantity of nitrogen oxides . <;.-
emitted and the degree to which control techniques are effective.
Consequently, in order to consider these factors, alternative emission
standards ranging from 0.5 to 0.8 pounds NOX per minion Btu neat input
Were considered for proposal. The low end of the range represents a
level of control which would push the limits of existing control tech-
nology, while the upper end of the range represents a level of control ;'~
which all furnace types can meet with little or no control. - ',
On the-basis of the test data, it appears that the cyclone furnace,.
cannot meet a nitrogen oxides standard more stringent than
0.8 Ib per million Btu. The test data also indicate that horizontally
opposed-fired units would have difficulty consistently achieving a
nitrogen oxides standard of 0.6 Ib per million Btu over a long time .
period. However, development of low emission burners for pulverized-
fired units appears promising for application to horizontally opposed- '
fired units, and with application these units should be able to attain
a standard of 0.6 Ib per million Btu. Tangentially-fired units should
have no difficulty meeting a standard of 0.6 Ib per million Btu and may
be able to consistently achieve a level of 0.5 Ib per million Btu.
VII-1
-------
In selecting the level of the proposed standard, EPA considered
whether the cyclone furnace was necessary for burning lignite. As
mentioned in Chapters II and IV, the high temperature necessary to
maintain the ash in a slagging state in a cyclone burner promotes NOX
fixations. The methods of NOX control/low excess air and staged
combustion, have limited applicability to cyclone-fired units because
of operating problems of flame instability. Thus in development of a
proposed NOX standard for lignite-fired steam generators, consideration .
had to be given to the necessity of setting a standard achievable by :
cyclone units (i.e. a standard not less than 0.8 lb/10 Btu).
EPA discussed the need for cyclone furnaces to fire high-sodium
lignite with the lignite electric utilities and with manufacturers of
utility steam boilers. Some of the lignite electric utilities maintained
that cyclone furnaces are better able to handle the slagging problem of
high-sodium lignite than are pulverized-fired units. These utilities
believe that the cyclone burner retains a large proportion of the ash
in the burner, thus reducing fouling of the boiler tubes. However, due
to the higher temperatures more volatilization of the sodium in the
ash will occur in a cyclone burner than in a pulverized coal-fired
boiler. Depending on the gas temperature profile in the furnace, these
sodium compounds can condense on the boiler tubes or the air heater and
cause fouling.
The relative advantages and disadvantages of the two firing systems
cannot be thoroughly evaluated due to the limited amount of information
VII-2
-------
available. Presently, the experience of the utility industry in firing
high-sodium lignite is very limited for either pulverized or cyclone-
fired units. -The Minnkota Power Cooperative's Young-Center station,
which started up in 1970, was the first large cyclone-fired steam generator
unit designed to fire North Dakota lignite. The cyclone-fired 235 MW "
B & W boiler was selected on the basis of a cooperative study to develop
a better method for firing high-sodium lignite. The Young-Center station
has a good record of operating availability. However, as of 1976 the -
unit has not used the high-sodium lignite for which it was designed.
In addition, the operating reliabi1ity may be attributed to other
boiler design features such as increased number of soot blowers,
increased furnace surface area, and increased spacing between boiler
tubes. These design features help minimize the ash fouling problems
associated with firing high-sodium lignite. Since startup of the
Young-Center station, three additional cyclone-fired units have
been purchased by power cooperatives and companies in the area. Two
of these three units were started up in,1975 and have been operating
for less than one year. One of the units has been firing lignite
With sodium content of about four percent; while the other unit
has fired lignites of about six percent sodium for short periods.
Since numerous operating problems typically occur in the first year
of operation of a,boiler, the performance of these units on high-
sodium lignite cannot be accurately evaluated at this time.
VII-3
-------
Of the units presently planned or under construction, not all of ;
the boilers designed to use North Dakota lignite will be cyclone-fired \
units (see Table II-5). In 1972, the United Power Association (UPA)
solicited bids for two 500 MW boilers to burn lignite with a maximum ;
sodium content of five percent. Bids were received for both cyclone
and pulverized-fired units. UPA purchased two CE tangentially
pulverized-fired units guaranteed to reliably fire lignite with a
maximum sodium content of 4.8 percent. This selection.of a pulverized-
fired unit to burn North Dakota lignite with high fouling potential
indicates that pulverized-fired units are economically competitive
with cyclone units and that at least one utility believes that cyclone
burners are not required for use of high-sodium lignite. Startup of
these two units at Underwood, North Dakota, is scheduled for 1978 and
1979 and thus evaluation of the operating reliability of & modern
designed pulverized-fired unit will not be possible until 1979.
Presently, experience with pulverized firing of lignite is limited to
two units: a frontwall-fired 192 MW unit and a horizontally-opposed
fired 215 MW unit at Stanton, North Dakota. The horizontally-opposed
fired 215 MW boiler at Leland-Olds station of Basin Electric Power Is 7
a good example of early experience with pulverized firing of lignite.,
When this unit was designed in the early 1960's, there was little
experience with lignite firing and effects of various amounts of sodium
in the fuel on boiler operation. The horizontally-opposed fired unit
at Leland-Olds is susceptible to extensive slagging and ash fouling
problems when firing high-sodium lignite. Short term derating of the
unit has been prevented by selective mining of the lignite to maintain
the sodium content below five percent. For the 192 MW frontwall-fired
VII-4
-------
unit at Stanton, North Dakota, the ash fouling problem has been managed
by increasing the spacing between the tubes and installation of additional
soot blowers as well as by derating of the unit. For the past year, this
boiler has been firing 8 percent sodium lignite at about 86 percent boiler
capacity and has not been shutdown to deslag the unit. Based on this
experience, new lignite pulverized-fired units would be designed with greater
surface area, increased superheater tube spacing, and increased number of
sootblowers, than is conventional for bituminous-fired units.. Thus,
B & W believes that a properly designed pulverized-fired unit should
be able to burn high-sodium lignite without derating due to slagging
problems. In addition, EPA discussed this issue with boiler manufacturers
and determined that manufacturers of pulverized-fired units (including
B & W, the manufacturer of cyclone burner units) believe that the
pulverized-fuel design can be as effective as cyclones for burning
lignites, including the high-sodium ones. Combustion Engineering,
which is installing the units for UFA, is confident that pulverized-
fired units can be properly designed to handle the slagging and ash
fouling problems of high-sodium lignite.
In addition to the experience of boilers operating on high-sodium
lignite, ERDA has conducted a short term study on the relative ash
fouling rates on pulverized fuel and cyclone-fired boilers. The test
was conducted while the two units were firing lignite with 3.5 .to 4.5
percent sodium in the ash. The preliminary results of the study show
that coupons located in the pulverized-fired boiler had deposition rates
approximately twice those of the coupons in the cyclone-fired boiler.
Because the study was conducted over a two-day period and the fuel supply
was relatively inflexible, study of the relative deposition rates at
VII-5
-------
higher sodium contents could not be investigated. Possible interpretations
of these results are (1) that cyclone-fired units can operate more reliably
and possibly at a lower cost on high sodium lignite than pulverized-fired
units or (2) that cyclone-fired units do not require as conservatively
designed convection section as do pulverized-fired units. Until verified
by further testing possible differences in design and operation of
pulverized or cyclone-fired units for high-sodium lignite are speculation
only. At this time, design of pulverized-fired units for high-sodium
lignite is proven and a retrofitted unit has been operating reliably on
eight percent sodium lignite for the past year. Therefore, the standard
was not established at a level which would allow use of cyclone-fired
boilers. EPA recognizes that this decision is based on limited information
on the slagging and ash fouling problems of firing of high-sodium lignite
and is requesting all interested persons to submit factual information on
this issue during the public comment period of the proposed standard.
EPA also considered proposing the same standard for lignite-fired
steam generators as the present standard for coal-fired steam generators,
300 nanograms per joule heat input (0.70 Ib per million Btu heat input).
Application of staged combustion and low excess air firing techniques
to lignite boilers was observed in this study to result in emission
levels sufficiently lower than 300 nanograms per joule (0.7 lb/10 Btu).
The measured levels of 0.4 to 0.5 lb/106 Btu indicated that a 300
nanograms per joule standard would not require best demonstrated control
technology considering costs. Also, recent studies on combustion
modifications to utility boilers have reported control of nitrogen
oxides emissions from coal-fired units to levels of approximately 0.4
to 0.5 Ib per 106 Btu.8'9 The standard of 300 nanograms per joule heat
VII-6
-------
input (0.7 lb per million Btu heat input) for coal-fired units was
based on limited data on combustion modification techniques in 1970-1971.
Since 1971,. research into this area has been conducted and considerable
improvements have been made in boiler design, the flexibility for '
staged firing, and low excess air operation. Consequently, EPA
recognizes that assessment of recent information and data for nitrogen
oxides control techniques on coal-fired units could indicate a need
for revision of the standard for coal-fired units.
Since tangentially-ffred boilers have been demonstrated to achieve
emission levels of less than 0.5 lb/106 Btu, alternative standards of
less than 0.6 Tb/106 Btu were considered. On the basis of available
data it appears that the other pulverized-fired boiler designs,
horizontally opposed or frontwall, probably cannot consistently achieve '
an emission level of less than 0.6 Ib NOX per million Btu input. ; Thus, '''>'
a standard of less than 0.6 Ib NOX per million Btu could destroy the
competitive balance between the two major boiler manufacturers. ,
Consequently., only one major established, supplier would be available.
EPA has concluded that it is not in the best interest of purchasing
utilities to remove their option to obtain a competitive bid for
expansions.
On the basis of the test data and the above considerations, EPA
is proposing a standard of 260 nanograms per joule (0.6 lb per million
Btu) for lignite-fired steam generators. The proposed standard, while
\
numerically more stringent than the present coal-fired standard, will
require the same types of combustion modifications (i.e. low excess
air and staged combustion) as the coal-fired performance standard.
VII-7
-------
3
ol
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ol
s
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VII-8
-------
Using these best adequately demonstrated systems of control,' ail the
major boiler manufacturers should be able to design equipment to
achieve an emission level below n.6 Ib per million Btu. The alternative
standards considered are summarized in Table VII-1. ' '"""''
Since there is essentially no difference in investment or annualized
costs to achieve an emission level of 0.5 to 0.8 Ibs per million Btu
(see Chapter VI-TabTe VI-4), cost was not a determining factor in
selecting the proposed standard. The cost to the utilities as a result
of compliance with the proposed standard has been analyzed and appears
to be negligible in comparison to capital costs. Conservative estimates
show that nitrogen oxides control costs will increase capital investment
cost 0.5 percent for a new lignite-fired utility boiler and'ancillary
equipment." The incremental costs for NOx control, thus, represent ''"'""
approximately $2 per kW installed capacity relative to the estimated
capital investment, costs of-approximately $400 per kW installed capacity
for a new-boiler and associated equipment. Since power costs are 'a
weighted'average of production costs for the entire utility, the costs
for NOX control will result in only a negligible increase in costs to
the consumer. n ./- -Y.
In the discussions with theTignite steanf generating industry^
the comment was made that the economic analysis should consider the
costs associated with derating of the boiler when firing high-sodium
lignite. EPA discussed this issue with the four major boiler manu-
facturers and found that derating does not result from NOX control
techniques. Derating of a boiler occurs due to inadequate design of
the furnace gas temperature profile and inadequate soot blowing for
VII-9 . '
-------
the fuel being fired. For high fouling fuels, proper design of the
boiler requires a larger furnace and more liberal tube spacing. These
design practices for high-fouling lignites have been developed from
experience with units designed in the late 196Q's. To maintain
equivalent slagging and fouling conditions when firing a high-sodium
fuel, a cyclone-fired boiler should be the same size as a pulverized
coal-fired boiler. So, there are no cost advantages associated with
cyclone-fired units. The increased costs referred to by the industry
result from firing of high slagging and fouling fuel and not from NOX control
procedures. The economic analysis does not reflect the costs of
construction of the larger lignite boiler, or derating of the model
units. This omission does not affect the analysis of costs for NOY
/\ '
control and somewhat decreases the percentage control costs relative . :
to baseline plant costs.
EPA also considered whether or not the fuel-nitrogen content of
lignite varies enough between geographical areas to warrant separate
standards of performance. A comprehensive literature search revealed
that Texas lignite contains a slightly higher fuel-nitrogen content
than North Dakota lignite, 1.4 versus 1.1 percent Nฃ on an ash and
moisture free basis. However, this apparent difference in fuel-
nitrogen content may only be the result of a larger data base for
North Dakota lignite. A statistical analysis of. lignites from the 10
major North Dakota mines showed that there is no significant difference
in the average fuel-nitrogen contents of the various North Dakota
lignites. A detailed discussion of this question along with pertinent
data are contained in Appendix 0,
VII-10
-------
While the best adequately demonstrated system of emission reduction
has been defined as low excess air and staged combustion, EPA
has considered whether or not the low NO emission burner discussed
A
in Chapter IV can achieve equivalent emission reductions. Initial EPA
tests of a horizontally opposed-fired boiler employing bituminous coal
indicated that the low NOX emission burner operated with low excess air
through the burner was equivalent to tangential firing with over^fire air.
However, NOX emission tests of lignite-fired boilers equipped with low
NOX emission burners have not yet been performed.
VII-1T
-------
-------
VIII. ENVIRONMENTAL EFFECTS
A. ENVIRONMENTAL IMPACT OF THE BEST SYSTEMS OF EMISSION REDUCTION v'
1. Ai r Impacts
Lignite-fired steam generators are not uniformly distributed, ;',
throughout the country but are concentrated in the North Dakota and v;
Texas areas. Both of these areas currently enjoy relatively low
ambient air concentrations of N02. It is expected that one primary
beneficial impact of an NOX emission limit for lignite-fired boilers ,
would be reduction of the atmospheric burden of nitrogen oxides. :
A second potential1 environmental benefit would be prevention of
- " . ' " ' ' ' ' .?>'ป.'
increased ambient oxidant concentrations. The potential for high
ambient concentrations of oxidant exists if appropriate concentrations
of precursors are present. The required precursors (primarily reactive
hydrocarbons, and NOX) may come from natural or anthropogenic sources,
R65Stivehydro5arbons may be Present in rural air as a result of emissions
from natural sources such as vegetation, or'natural ga^depos its land:~'~~~
from transport of urban pollution into rural areas. Transport of \
urban pollution has been documented for distances as great as 80 km
(50 miles)48, and has been strongly indicated by pollution.."".
characteristics for distances of 700km (435 miles)49'50. Investiga-
tions of rural oxidant levels relative to urban hydrocarbon emissions; '
have found that rural emissions combine with transported urban
pollutants to generate appreciable quantities of oxidant over wide
48
areas . In addition, irradiation of bag samples of rural air,
, .VIII-1 ' .
-------
without urban pollution, has shown enhanced oxidant production with
addition of NOX to bag samples having very low initial NOX concentra-
CO
tions . This finding is consistent with theoretical curves derived
CO ' '.'.!,,...,,.,.,'-...
from smog chamber data which show increased oxidant formation with
addition of NOX to mixtures containing large hydrocarbon to NOX ratios.
Since a number of investigators48'52 have reported measuring high
non-methane hydrocarbon to NOX ratios in rural air samples, control
of NOX emissions in rural areas may be expected to help prevent an
increase in rural oxidant levels.
The primary impact of an NOX emission limitation on air quality-, '
can be assessed in two ways: the reduction in total mass emissions
of NOX to the atmosphere and the reduction in the maximum predicted
ambient NOg concentration in the vicinity of a source.
a. Mass Emissions ;
The reduction in mass emission levels was calculated assuming an
emission limitation of 0.6 lb/106 Btu and using the known increase in
lignite-fired steam generator capacity to 1980. The standards of
performance for nitrogen oxides would not affect any of the existing
or planned lignite-fired steam generators scheduled to come on-line .
before 1980. The lignite-fired utility boilers planned and under
construction will increase the 1972 capacity by a factor of 4.5 in
1980. Although it is safe to say that growth of the lignite-fired :
utility boiler industry will continue after 1980, it is impossible '.
to accurately predict the number or distribution of boiler types
which will be installed. For this reason, an example of the mass
emission reduction that would result from adoption of a 0.6 lb/106
VIII-2
-------
Btu emission standard has been calculated by assuming that future
capacity increases will have similar distribution of boiler types
to that present with existing power plants (see Table VIII-1).
TABLE VIII-1. NOx EMISSION REDUCTIONS FROM LIGNITE-FIRED STFAM
GENERATORS LOCATED IN TEXAS AND NORTH DAKOTA--ESTIMATED FOR THE
YEAR 1980 BASED ON 0.6 LB/1Q6 BTU EMISSION STAN DARD (BY
CATEGORY AND REGION)
Emissions-
103 tons N0v/yr
Boiler Category
; Con-
sumed^* <
(106 tons/yrj
Uncontrolled
Tangential
Horizontal
Cyclone
\ , ' . - .
Other
North
Dakota
Total
% Emission Reduction
; Mass emissions of NOY are calculated as N00.
b ' '' ' : \ " -
Estimated from net generation using the conversion factor 1000 MWh =
900 ton lignite. Net generation for 1980 taken from Table I1-5 usinq
the conversion factor 1 MW capacity = 7 x 10^ MWh/yr. " 9
O ! ' -.-"'" "- ' ' " - ' - ;,'-..',..,'''"'*
Emission level not achievable by specified boiler category.
Table VIII-1 indicates than an emission standard of, 0.6 >,'
Tb NOX/106 Btu input would reduce NOX emissions by 29 percent.
Although a standard of performance for nitrogen oxides ,
VIII-3 - :
-------
would not apply to the boilers used in these calculations, the
emission reduction percentage should be valid for boilers built ;
after 1980 which would come under the standard. By 1985 it is estimated
that installed lignite generating capeity will have increased by an additional
16,000 MW if the recent 20.7 percent growth rate continues. Control
of NOX emissions from these boilers to 0.6 lb/106 Btu will reduce
emissions of nitrogen oxides by 141,000 tons per year. The standard
of performance limiting NOx emissions from bituminous-fired steam
generators requires a comparable degree of control.
b. Ambient NOg Levels
Another method of evaluating the impact of emissions is to
calculate the maximum ambient concentrations of N02 at ground level
from model facilities. These estimates are made using atmospheric
dispersion modeling assuming that all nitrogen oxides were emitted
from the source as nitrogen dioxide (N02). For the dispersion analysis,
ground level concentrations of N02 were estimated for a 450 MW lignite-'
fired steam generator. Because emissions vary with the furnace design,;
the dispersion analysis considered emission rates for cyclone, tangential,
and horizontally opposed fired boilers. The plant and exhaust gas
parameters used in the model are shown in Table VIII-2. Ground level
concentrations of N02 associated with building downwash were not
estimated in this analysis because it is expected that stacks will be
designed to avoid downwash problems. ' ,
The atmospheric dispersion model used in the analysis was EPA's
"24-Hour Single Point Source" model modified for aerodynamic effects.
This model assumes that: .
1) there are no significant seasonal or hourly variations in
emission rates,
VIII-4
-------
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VIII-S
-------
2) the plants are located 1n gently rolling terrain, and
3) meteorological conditions are unfavorable to dispersion.
The model integrates the plant parameters with hour-by-hour actual
meteorological conditions recorded over a one-year period. "Worst
case" climatology consists of a high frequency of strong winds of
persistent direction under conditions of neutral stability. Omaha,
Nebraska fits this description fairly well, and data for this .;
location were readily available in a form appropriate for input into ..'.
the model. The above estimate is valid, then, for the Omaha area.
Winds in North Dakota are generally less persistent in direction than .
are the Omaha winds; thus the estimate is conservative for North
Dakota.
The results of the dispersion analysis indicate that emissions
from the model lignite-fired steam generators would have a nominal
impact on ambient NOg levels on,an annual average basis. Specifically^
the resulting maximum ground level annual average concentrations would
3 ',"'
be about 1-2 yg/m for the cyclone furnace emission rate and
proportionally less for the other two furnace designs with lower
emission factors. The maxima would occur at distances of 10-15 Rro
from the plant. All the annual average concentrations of NOg calculated by
the dispersion model were lower than the national primary and secondary
ambient air quality standard for nitrogen dioxide, 100 yg/m (annual
average).
2. Water Pollution Impact . -:
The NOX control techniques required to meet the alternative
emission limitations would not create any aqueous wastes or additional
thermal pollution. Staged combustion, tangential firing, low excess
VIII-6
-------
air, and burner modifications are NOX control techniques;which have *a
adverse or beneficial water pollution impact.
3. Solid Waste Disposal Impact
The alternative NOX emission limitations would have no jeffeet on
the amount of sol id waste produced, but, would have an effect on the 'form
...of.the.solid waste. The solid waste generated by lignite-fired steam:
generators depends upon the type of equipment being used, If the
furnace is a dry bottom furnace (pulverized-fuel or stoker) then the .
solid waste is in the form of fly ash and bottom ash which can be
Jandfllled. used as a road ffiler, or because of lignfticCash's pozzolanic
characteristics can also be used as,raw material in the manufacture of\-:
construction blocks or other cementious materials. Many of the r .:
utilities market fly ash with reasonable success. However, when 'markets 1.
are not available for fly ash, the material can be 1andfi11ed,or placed .
in the lignite mine with no serious environmental effects.,. ,
For wet bottom furnaces (cyclones) the bottom ash is in^a sl^g form;
slag tap ash can be utilized in road construction. Any alternative which
would essentially prohibit the use of cyclone furnaces.would thus, V
change the form but not the amount of solid waste produced.
f- Energy Impact
The NOX control measures presented in Chapter IV do not cause bo:iler
efficiency losses, and therefore, no serious impacts are expected with
respect to energy. If other control techniques such as the addition of
unpreheated air or the use of flue gas recirculation were considered,
impacts on boiler efficiency as large as 6 percent could be expected,
lowering boiler efficiencies from 80 percent to approximately 74 percent.
However, NOX control techniques which cause boiler efficiency losses are!
Vlil-7
-------
not needed to meet a limitation of 0.6 Ib NOX/10 Btu input. For this
reason, there is no incremental energy demand associated with the proposed
limitation. ;
5. Other Environmental Concerns *
There are no anticipated adverse environmental concerns associated with
the NOX control technologies required to meet the alternative emission
limitations. These NOX control technologies are all based upon modification
of combustion conditions within the furnace. Although combustion conditions
are altered, the primary chemical reaction which occurs in the furnace is
still oxidation of lignite, and effective operation of a boiler requires
complete combustion of the fuel. The combustion modifications do not
alter the nature or quantity of the particulate matter emitted and do
not affect the quantity of sulfur oxides emitted. Thus, NOX control
techniques do not adversely affect the ability of a lignite-fired steam
generator to comply with the standards of performance for particulate
matter or sulfur dioxide.
B. ENVIRONMENTAL IMPACT UNDER ALTERNATIVE EMISSION CONTROL SYSTEMS ':
1. No Standard .
Lignite-fired steam generators are only a small portion (about 1/2.
percent) of the total number of fossil fuel-fired steam generators.
Although units firing lignite were exempted from the current fossil fuel- ,
fired steam generator NOX standards, pulverized lignite firing units ',
have benefited from furnace design changes implemented by boiler manu-
facturers to meet the NOX standard for boilers firing bituminous coal.
Over-fire air controls will be included as standard equipment for all
tangentially-fired pulverized coal boilers supplied by one of two major
manufacturers of lignite units. As a result of this manufacturer's
stated corporate policy, tangentially-fired furnaces utilizing lignite
VIII-8
-------
will emit NOX at a rate of approximately 0.5 + 0.1 Ib NOX/106 Btu input
regardless of the proposed NOX limitation for 1 Ignite-fired steam
generators. The other major manufacturer of lignite-fired; boilers win
provide new low NOX emission burners as standard equipment for its >
hori zontally opposed; fi red boi1ers, Although EPA tests of this burner:
are not complete, horizontally opposed fired boilers can achieve'an :
emission rate of approximately 0.6 Ib NOX/106 Btu input without using,
the burner (See Figure VIII-1). ; : ,;
From the previous statements, it appears that a proposed limitation
i of 0.6 Ib NOX/106 Btu would have little effect on emissions from
lignite-fired steam generators; however, this is not the case. Cyclone
boilers which can only achieve an emission rate of approximately 0.7
Ib Nbx/106 Btu input wou1d.be indirectly prohibited. Al soothe proposed,
NOX emission limitation would guarantee that horizontally opposed firing,
boilers, are equipped with low emission burners. A general rule of thumb
is that a boiler must produce an emission rate 0.1 Ib NOX/106 Btu input
below the emission standard in order to be guaranteed by the boiler
manufacturer. Thus, horizontally opposed firing boilers would be
encouraged to achieve an emission factor of, 0.5 Ib NOX/106 Btu input.
Continuing to exempt lignite-fired steam generators from an NOV
-i s ' ' " '" i ' /ป . ,r,
standard would not yield any beneficial secondary environmental impacts.
As stated in Section A, the proposed NOX limitation does not have any
water pollution, sol id waste disposal, or energy impact.
2. . Delayed Standard
None of the currently existing or planned boilers firing lignite
would be affected by the proposed SPNSS for NOX. Therefore,.it is
impossible to state quantitatively the effect of delaying the proposed .
-
VIII-9 \
-------
emission limitation. As of February h976 it is believed that tangentially
fired-units can consistently achieve the proposed NOx standard. The
other major suppliers' horizontally opposed fired boilers have a
controlled emission factor nearly equal to the proposed emission limita-
tion, and that manufacturer has recently decided to include low
emission burners for these units. Although testing of these low
emission burners is not now complete, they will probably further reduce
the NOX emission factor for horizontal opposed boilers. For these
reasons* delay of the proposed NOX emission limitation is not thought
to be desirable or necessary.
3. More Effective Emission Control System . .
Figure VIII-1 shows NOX emission factors for the three major furnace
configurations used in lignite-fired steam generators. This figure
compares emission factors for both controlled and uncontrolled sources.
The NOX controls used in generating these factors include over-fire air,
low excess air, and combinations of the two. Tables Mlll-3 and 4 list
Texas and North Dakota NOX emissions from lignite-fired steam generators
in 1980 by boiler category and region for the proposed and three
alternative emission limitations. Identical assumptions to those made
in Section A.I of this chapter were used to construct these tables.
As indicated in Figure VIII-1, tangential firing with over-fire
and low excess air is currently the best demonstrated NOX control
technology for lignite-fired steam generators. This type of boiler
will be provided by one of the boiler manufacturers who supply lignite-,
fired units. The other major supplier, although not yet equal in NOX
control technology, would have to employ a low NOX emission burner to
lower NOX emissions.
VIII-10
-------
700
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a heating value of 6800 to 7800 Btu/lb., 7 to 16% ash, and 28% moisture.
Since these values are similar to lignite, this data is useful for assessing NO
control effectiveness for lignite firing. , X ,
SOURCE: REF. 8,18,19, 20 AND CURRENT FIELD TEST DATAlSEE CHAPTERf IV).
FIGURE VIII-1 '. N(T EMISSION FACTORS BY BURNER CONFIGURATION FOR
LIGNITE-FIRED sfEAM GENERATORS.
VIII-11 '
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A more stringent NOX limitation, 0.5 Ib NOX/106 Btu input was
not proposed because adoption of this standard could adversely
affect the competitive balance between the major suppliers of
lignite-fired boilers. Horizontally-opposed fired boilers
manufactured by one of the major suppliers may not be capable
of consistently achieving 0.5 Ib NOX/106 Btu and the manufacturer
probably would not guarantee compliance with this standard. Thus,
only one proven supplier of lignite-fired boilers would be
available.
4. Less Effective Emission Control System
Figure VIII-1 and Tables VIII-1 and 3 show that cyclones are
the least .control 1 abl e type of boilers: The two major jxnlex
agree that cyclone furnaces are not necessary to fire high sodium lignite,
and at present cyclone furnaces have not been demonstrated to fire
high sodium lignite more reliably than pulverized coal boilers. Also,
cyclone furnaces are essentially equivalent in price to pulverized coal
units. For these reasons, new cyclone boilers have been indirectly
prohibited by the proposed emission limitation. Raising the proposed
NOX limitation to allow use of cyclones would clearly violate the mandate
of Section'ill of the Clean Air Act of 1970 which requires use. of the
best demonstrated technology taking costs into account. (See Chapter
C. SOCIOTECONOMIC IMPACTS
Compliance with the proposed emission limitation should cause no
adverse socio-economic impacts. The NOX control costs associated with
the proposed emission limitation are small and would be lost in the overall
cost of power generation, Thus, the cost impact of the proposed emission <
limitation on electricity bills paid by consumers would be negligible. .
(See Chapter VI).
VIII-14
-------
The small incremental capital cost associated with the NOX control
cost requirement would hot cause any problems to the owners of the
affected facilities who would be required to make additional investment
to comply with the proposed emission limitation. There would be no plant
closures or other such hardships on the electric utilities involved. ,
The proposed emission limitation should not give any one boiler ;
manufacturer a monopoly on future sales of lignite-fired boilers. The .
required NOX control technology is already available to .the manufacturers.
Also, the additional control cost is a small part of the total capital
cost of the boiler. Thus, factors other than control cost would affect the
choice of boilers selected by a customer.
D. .OTHER CONCERNS OF THE BEST SYSTEMS OF EMISSION REDUCTION
Promulgation of the proposed NOX emission limitation for lignite-fired
steam generators would not result in any irreversible and irretrievable
commitment of natural resources, nor would it cause any long-term environ-
mental losses. The proposed emission limitation fulfills its intended pur-
pose of reducing NOV emissions without generating any adverse secondary
/\ . ' . ' : ,,.<-'
environmental impacts. In fact, probably the only secondary environmental
impact of the proposed standard would be a change in the form of solid
waste produced by lignite-fired steam generators. (Section A.3.).
VIII-15
-------
-------
IX. ENFORCEMENT ASPECTS OF THE PROPOSED STANDARD .
The proposed standard limits emissions of nitrogen oxides from'
lignite-fired steam generators of greater than 73 megawatts thermal (250
million Btu heat input). Nitrogen oxides emissions can be reduced to ;,i
the level of the standard by the combustion modification techniques of
low excess air, staged combustion, low emission burners, and combined
low excess air and staged combustion. Based on present information
cyclone-fired steam generators firing lignite alone cannot achieve the
proposed staridard and operate reliably.
Compliance with standards of performance is determined by perfor-
mance testing of the affected facility while it is operating under
representative conditions. In addition continuous monitoring require-
ments are established where the information will assist enforcement
personnel in ensuring continued compliance with the standard or in ensuring
proper operation and maintenance of the control system; Consequently,
this section will 'briefly discuss the performance test methods and
continuous monitoring requirements and equipment available. Determination.
of compliance with the nitrogen oxides standard also requires designation
of the type fuel being burned. Due to the variability' of the heating
value of lignite, in some cases there could be a question as to which
nitrogen oxides standard is applicable. .:.>
A. PERFORMANCE TESTING
The EPA reference method for the analysis of nitrogen oxide_emission:s
from stationary sources. (Method 7) calls for the use of the phenpl^sulfonic
acid (PDS) procedure for the analysis. This involves oxidizing all NO to V
by colorimetric measurement using PDS. The mass emission
V '.-.-. , ' ix-1- "' '..'" ;-.'. \ .']:
-------
rate for the facility is calculated using either of the following
equations:
_ / 20.9 N
or
B. CONTINUOUS MONITORING
There are a large number of potential instrumental methods for :
the measurement of nitric oxide emissions from stationary sources.
Perhaps the largest problem encountered in the use of many of these
techniques is in providing proper sampling interface and conditioning
equipment for the transport of the stack gas to the analyzer. The
performance specifications for instrumental methods for the measurement
of nitric oxides from stationary sources required to continuously
monitor emissions were published in the Federal Register on October 6,
1975 (40 FR 46250).
Due to the sensitive relationship between operating conditions and
NOX emissions, a continuous monitoring device is required for NOX
emission monitoring of lignite-fired steam generators. Any instrument
which meets the criteria of Performance Specification 2 of 40 CFR 60,
Appendix B is acceptable for this purpose.
C. FUEL ANALYSIS
Lignite has a high moisture content and low heating value. Analyses
of lignite show considerable variation in moisture and ash content and
the heating value on a moist mineral matter free basis. Lignite is
defined by ASTM D 388-66 as any solid fossil fuel with a moist mineral
matter free heating value between 8,300 and 6,300 Btu/lb. As a result
IX-2
-------
of this definition, a boiler which fires a fuel of around 8,300 Btu/lb
technically may be firing lignite one day and subbituminous coal the
next. .-"'." "'..- .'- : /. ; .-'''' ''-'. ''''.'' .','.' ;'.
In order to resolve this problem, EPA considered alternative
definitions for lignite. No generally acceptable definition was found
which would avoid this arbitrary differentiatipn and which would not
introduce additional enforcement determination problems. Consequently,
in order to reduce the relative effect of fuel analysis and sample
handling errors, EPA concluded that the coal rank should be detennined
on the basis of a relatively large sample population. Determination of ;
the coal rank on the basis of daily samples is not recommended because a
facility would not know the applicable NOX standard at all times. There-
fore, in order to simplify enforcement of the applicable NOXrstandards,<
the rank of a coal will be determined on the basis of the mean heating
value for a 30 day period prior to the period in question.
IX-3
-------
-------
X. REFERENCES
1. Steam/Its Generation and Use. Babcock and Wilcox Company.
1972. p. 5-11. ;, ; K%
2. Gronhovd, G. H., R. J. Wagner, and A. J. Wittmaier. "A Study of
the Ash Fouling Tendencies of a North Dakota Lignite As Related to
Its Sodium Content." Transaction of the Society of Mining
, Engineers. September 1967. p. 313. '
3. Demonstrated Coal Reserve Base of the United States on January 1.
1974. U. S. Bureau of Mines.
4. Zel Vdovich, Ya. B., P. Ya. Sadovnikov, D. A, Frank-Kamenetsku. .
"Oxidation of Nitrogen in Combustion." Academy of Sciences of
the U. S. S.,R.y Institute of Chemical Physics, Moscow-Leningrad.
Translated by M. Shelef, Scientific Research Staff, Ford Motor
Company. 1947. . ' ; .'.''-;..;. \
5. Armento, W. J. Effects of Design and Operating Variables on NOX
from Coal-Fired FurnacesPhase I. Washington, D. C.
Environmental Protection Agency. EPA Report 650/2^74-002a.
6. Cuffe, Stanley T., and Richard W. Gerstle. Emissions frdm
Coal-Fired Power Plants: A Comprehensive Summary. Durham,
North Carolina: U. S. Department of Health, Education and
Welfare Public Health Service, 1967. 26 p.
7. Bartok, William, Allen R. Crawford, Gregory 0. Piegari. V, .
.Systematic Field Study of NOx Emission Control Methods for Utility
Boilers. ESSO Research and Engineering Company, Linden, New
Jersey. Research Triangle Park, North .Carolina: Environmental
Protection Agency, December 1971. EPA Report APTD 1163. 218 p.'
See also EPA Report GRU-4GNOS-71.,
8. Crawford, A(. R., E. H. Manny, and W. Bartok. Field Testing:
; Application of Combustion Modifications to Control NOX Emissions
from Utility Boilers. EXXON Research and Engineering Company,
Linden9 New Jersey. Research Triangle Park, North'Carolina:
Environmental Protection Agency, June 1974. EPA Report
650/2-74-066. 151 p.
9. Crawford, A. R., E. H. Manny, M. W. Gregory, and W. Bartok. The
Effect of Combustion Modification on Pollutants and Equipment.
Presented at Symposium on Stationary Source Combustion, Atlanta,
Georgia. September 24-26, 1975. 98 p. ,,
10. Steam-Electric Plant Factors/1973 Edition. National Coal
Association. Washington, D. C. 1974.
' ' , X-V' " ' ..:.'... '=
-------
11. Method 7Determination of Nitrogen Oxide Emissions from
Stationary Sources. Federal Register 36_(247):24891. December 23,
1971. ' .:.
12. Improved Chemical Methods for Sampling and Analysis of Gaseous
Pollutants from the Combustion of Fossil Fuels, Vol. II, Nitrogen
Oxides. Waiden Research Corporation. Report prepared for EPA.
Contract No. CPA-22-69-95. July 1971. 162 p..
13. Performance Specifications for Stationary-Source Monitoring System
for Gases and Visible Emissions. Washington, D. C.:
Environmental Protection Agency,, 0anuary 1974. EPA Report No.
EPA-650/2-74-013. 75 p.
j .
14. Standards of_Performance for New Stationary Sources. . Federal,._.,
Register4]Ch 46250-46271. "October 6, 1975.
15. McAlpin, W. H., and B. B. Tyus. Design Considerations for 575 MW
Units at Big Brown Steam Electric Station. Texas Utilities
Services, Inc., April 5, 1973. 9 p.
16. Oxygen Bomb Calorimetry and Oxygen Bomb Combustion Methods. Parr
Manual No. 120. Parr Instrument Co., Moline, Illinois.
17. Fisher, G. E., and T. A. Huls. "A Comparison of Phenoldisulfonic
Acid, Nondispersive Infrared, and Saltzman Methods for the
Determination of Oxides of Nitrogen in Automotive Exhaust."
JAPCA 20_:666. 1970.
18. Habelt, W. W., and A. P. Selker. Operating Procedures and
Prediction for NOX Control in Steam Power Plants. Combustion
Engineering Power Systems. Windsor, Connecticut, Presented at
Central States Section of the Combustion Institute, Spring
Technical Meeting, Madison, Wisconsin. March 26 and 27, 1974.
17 p.
19. Gronhovd, G. H., P. H. Tuffe, and S. 0. Selle. Some Studies on
Stack Emissions from Lignite-Fired Power Plants. Presented at
the 1973 Lignite Symposium, Grand Forks, North Dakota. May 9-10,
1973. 28 p. .
20. Duzy, A. F., and L. V. Hillier. Operation of the Lignite-Fired
Cyclone Boiler at the Milton R. Young Station. Presented to the
Canadian Electrical Association. March 1972.
21. Hall, R., Control Systems Laboratory, EPA. Private Communication
to J. Smith of the Industrial Studies Branch, EPA. Based on Field
Tests of B & W Burner. February, 1975.
X-2
-------
22. Kirner, W. R., "the Occurrence of Nitrogen in Coal", Chapter 13
Of Chemistry of Coal Utilization, Ed. H. H. Lovry. (New Ydrk:'
Wiley, 1945.:~~~~
23. Heap, M. P., T. L. Lowes, and R. Walmsley. Combustion Institute
Engineering Symposium. Academic Press, 1973. p. 493^
24. Armento, W. J., and W. L. Sage. Coal Combustion Seminar.
Environmental Protection Agency, 1973.
25. Martin, G. B.ป and E. E. Berkau. Fourteenth Symposium on
Combustion. 1972.
26. Halstead, C. J., C. D. Watson, and A. J. E. Munro. IGT
Conference on Natural Gas. 1972.
27. Turner, D., R. Andrews, and C. Siegmund. AIChE Meeting,
December 1971.
28. Muzio, L. J., R. P. Wilson, Jr., and C. McComis. EPA Report No.
EPA-R2-73-292-b. 1974.
, 29. Turner, D. W., and C. Siegmund. Paper presented at the Winter
Symposium of the IEC Division, American Chemical Society; 1973.
30. Thompson, R. E., and D. P. Teixeira. APCA Paper 73-310.
June 1973.
31. Par, R. H., R. E. Sommerlad, and R. P. Welden. Heat EngineeM'nq.
April 1971.; p. 17. '...;' ( . :
32. Blakeslee, C. E., and H. E. Burbach. JAPCA 23_:37. 1973.
33. EPA Report No. EPA-R2-73-284 on Kansai Electric Power Co.
1973. p, 14.
34. Gorter, K., J. Vander Kooij, J. de Lange, and A. J. Elshort.
Electrotechniek. 5]_:79. 1973. . \
35. Efendier, T. B., and V. R. Kotler. TepToenergetika. 20:41.
1973.
36. Rawdon, A. H., and S. A. Johnson. Application of NOv Control
Technology to Power Boilers. Riley Stoker Corp. 1973.
37. A Study of Base Load Alternatives for the Northwest Utilities
System. Arthur D. Little, Inc. 1973. ;
38. Low-Btu Gas for Electric Power Generation. Progress Report by
Combustion Engineering to the Office of Coal Research, 1973.
"Range of Estimated Capital Costs for Selected 1,000 Mw Central
Station Electric Power Plants." Table 1-3, in WASH-1174/74,
USAEC, December, 1974. A
- ' ' ' 'X-3 ' ;'' . '.' ' .. '
-------
39. The Nuclear Industry, 1974. (WASH-1174-74), Report of the U. S.
Atomic Energy .Commission. 1974.
40. McGlamery, G. C., and R. C. Torstrick. Cost Comparisons of Flue
Gas Desulphurization Systems. TVA, presented to the Flue Gas
Desulphurization Symposium, sponsored by EPA, Atlanta, Ga.
November 4-7, 1974.
41 Martin, G. B., Environmental Considerations in the Use of
Alternate Clean Fuels in Stationary Combustion Processes,
Environmental Protection Agency, 1974.
42. Hanes and Kirov. Combustion and Flame, Volume 23, p. 277. 1974.
43 Sondreal E A. Analysis of the Northern Great Plains Province
LiSniSs and Their Ash: A Study of Variability. U. S. Bureau of
Mines Report of Investigations 7158. August 1968.
44. Zerban, A. H., and Edwin P. Nye. Power Plants, Scranton,
Pennsylvania: International Textbook Co., 1966. Table 3-1.
45. Schafer, H. N. 0. "Factors Affecting the Equilibrium Moisture ;
Contents of Low-Rank Coals," Fuel 51_(1). January 1972.
46. Arkin, H., and R. R. Colton. Tables for Statisticians, Second ,,
Edition. New York: Harper and Row, 1963.
47 Pershing, D. W., G. B. Martin, and E. E. Berkau. Influence of
Design Variables on the Production of Thermal and Fuel NO from
Residual Oil and Coal Combustion. Presented at 66th Annual
AIChE Meeting, Philadelphia, Pennsylvania. November 11-lb, 19/J.
48. Investigation of Rural Oxidant Levels as Related to Urban
Hydrocarbon Control Strategies. Raleigh, North Carolina:
Environmental Protection Agency, March 1975. EPA-450/3-75-036.
343 p.
49. Cox, R. A., A. E. 0. Eggleston, R. G. Derwent, J. E. Lovelock,
and D. H. Pack. Long-Range Transport of Photochemical Ozone in
Northwestern Europe. Nature 25.5:118-121. May 8, 1975.
50. Cleveland, W. S., B. Kleiner, J. E. McRae, and J. L. Warner. _
The Analysis of Ground-Level Ozone Data from New Jersey, New York,
Connecticut, and Massachusetts: _Transj3ort_ from the .New_York.City
Metropolitan Area. ^Presented *at 4th Symposium on Statistics and
the Environment, National Academy of Sciences, Washington, D. C.
March 4, 1976.
X-4
-------
51. Manna, S. R. Modeling Smog Along the Los Angeles-Palm Springs
Trajectory. To be published in: Advances in Environmental Science
and Technology. Suffet, M. (ed.). New York: John Wiley & Sons.
ATDL Contribution File No. 75/4.
52. Grimsrud, E. P. and R. A. Rasmussen. Photochemical Ozone Produc-
tion from Captured Rural Air Masses of Ohio and Idaho. Report to
Environmental Protection Agency, Grant No. 80067. December 29,
, ' .1974.; . ' ' _-.-.. . ' , ; . . ; , ; . ;;;
53. Dimitriades, B. Oxidant Control Strategies. Part I. An Urban
Oxidant Control Strategy Derived from Existing Smog Chamber Data.
Research Triangle Park, North Carolina: Environmental Protection
Agency. .
54. Youngblood, P. Written communication to S. T. Cuffe.
Environmental Protection Agency, Research Triangle Park, North
Carolina. February 11, 1975.
55. Barrin, J. A. Babcock & Wilcoxj Barberton, Ohio. Written
communication to G. B. Grane. Environmental Protection Agency,
Research Triangle Park, North Carolina.
X-5
-------
-------
APPENDIX A . ; /
BACKGROUND ON LIGNITE-CONSUMING
UTILITIES AND INDUSTRIES
1.. PAST GROWTH OF LIGNITE-FIRED PLANTS !'
In Table A-l we have collected data on the capacity^ output, and
lignite consumption of all major lignite-fired plants in the United
States ifor,three years: I960, 1970, and 1972. The data differ slightly
from Table II-2 in the main body of the text because certain boilers
-using sub-bituminous coal have been included in Table A-l.
2. EXPANSION PLANS OF SELECTED UTILITIES
Annual reports and data published in Moody's Public Utilities
manuals about the six utilities discussed in Chapters I and V show
the following/commitments to lignite-fired expansion: '-,'.'
ง Utility A budgeted over $33 million for construction in 1974. A
new, jointly owned 440-megawatt steam generating plant, of which this
utility will own 47 and 1/2%, will be on-line in 1975,and is expected to
cost about $148 million. The utility's forecasts of its construction
budget for 1975 and 1976are about $19 million and $11 million,
respectively, with 1974-78 construction budgets expected to total about
$113 million. This utility is also sharing the construction costs of a
450-megawatt plant due to go on-stream in 1981. Utility A has issued
pollution control revenue bonds. It also issued first mortgage bonds,
pollution control series, in February 1974, for $13.3 million to be
used to cover the company's share of air and water pollution control
facilities at its plant due for completion in 1975. The budget presently
does not include provisions for S02 control, but includes provisions for
an electrostatic precipitator for particulate control.
A-l ' -"'
-------
unmn-nnp truM-mcme rum, m masuavM ABB uarm consagSBB
1972
I960 J
Inatalled Kซv Pover Lignite Inetalled
Generating Generation Conauaptlon Generating
Capacity Oปr) ซ0ฐkvh) (M>3 Ton*) Capacity (Mป)
vmmcm crsnAi.
tUmttftm
OttarTaU rover Co.
toot Laka
Otter Tall rovmr Co.
Crookatoa
Octar TaU rover Co.
OtcooTllle
rubllc Service Deft.
NaoititU
ctfc Dakota
Mont-Dak. CtU. Co.
laulala
Mซt-C.k. DtU. Co.
Itverck
Moot- Dak. OtU. Co.
XlaeaU
Hrat-Dik. ntU. Co.
Bttkatt
K*. State* rover Co.
Ha. State* rover Co.
Oraai Torka
a. State* rover Co.
Ileoa
Otter Tail rover Co.
ftrrll* Uka
Otter Tall rower Co.
jMMiteva
Otter Tall rover Co.
Otter Tell rover Co.
KUier
Valley City Km. CtU.
Valley City
Buln tltc. Tower Cooj.
I/Onni 01<1ซ - .
W.J. Kซal
Ktnnkota rover Coo;.
r.r. wood
Mimlau rower Coop.
. Towns-Center
Oalted rover Aara.
StentoB
Sauta Dakota
lick Kill* rover * light
Jen French*
lack Hill* rower * Light
Wtk*
tent-Cak. t>tU. Co.
VUT soura CIMTUL.
Taxaa
Dalle* rover 1 light Co.
Ill Irova
tmtru.iv
MMtna
Hont-Dak. CtU. Co.
Uvi* ซ Clark
lack nuia rover'* tight
lack Hill* rover t Light
Mall Slป?ปon*
Hoal-Dak. UtU. Co.
ACM
rซci(lc rover t Light
D. Joheatoo*
536.5 2
335.0 1
98.0
61.0
10.0
15.0
12.0
178.5
13.5
10.0.
6.0
25.0
20.0
18.0
10.0
12.5
8.5
8.0
20.5
5.0
_
21.3
""
* f '
38.5
22.0
28.0
8.5
_
"
201.5
so.o
50.0
151.5 -
5.0
12.0
100.0
ซSub-bltMlnoua plant* ปhoซ* fuel input
SOUUCKl *>ซ tl.etrle Mil
,t Coซtrซtto,
,223.3 2
,335
,084.2 1.351
364.3
258.4
15.3
90.1
0.5
^
558.6
47.8
12.3
25.5
136.8
50,7-
41.5
50.8
39.2
37.3
7.1
42.3
7.3
60.0
"""*
161.3
9.4 ,
137.5
14.4
1,139.1
101.2
182.2
956.9
247.1
27.0
16.1
666.7
333
211 ' .
19
101
4
850 .
69
37-
68
145
113
80
77
37
47
14
55
24
:
64
166
5
131
30'
984
187
187
797
226
45
18
508
1.432.3
888.1
173.4
125.0
10.0
16.5
10.0
652.7
13.5
n
~
~"
100.0
20.0
16.0
10.0
12.5
7.3
**"
20.5
3.0
215.7
21.5
172.0
62.0
22.0
31.5
8.5
544.2
50.0
50.0
494.2
34.5
27.7
12.0
420.0
.- _'_
i Coat and Ai
oซal Production
Nev Pover Lignite Inetalled New Pover Lignite
Generation ConauBptlon Generating Generation Coneu^daB
(10* kvfa) /in3 r.1 Capaelty (Mป) (IQ^knh) Qtl3 Tm>
8,350.8
4,908.8
976.4
842.4
38.9
93.2
1.9
3.686.1 .
77.1
~
"""
364.8
. . 38.9
65.8
29.7
40.6
43.0
~
. 13.3
8.7
. 1,542.4
1.4
1.027.J
246.3
125.4
104.7
16.2
'__
._
' 3,442.0
337.3
337.3
3,104.7
235.8
177.2
28.6
2,663.1
to lignite.
Zxpeaae*, federal roMr Cam
7.148
4,533
869
705
47
111
6
3,429
127
~~
~
520
72
101
40
61
58
~~
18
29
1,298
2
854
235
107
94
34
_ _
_ .,
2,615
321
321
2.294
220
192
30
1.832
lielon. 1960.
3.164.5 13.137.3 ,
1.107.2
203.9
125.0
10.0
15.0
25.0
. 841.3
13.5
100.0
12.5
7.5
20.5
5.0
215.7
21.5
234.6
172.0
62.0
22.0
31.5
8.5
1,186.8
1,186.8
1,186.8
.
870.5
' 50.0
50.0
820.5
34.5
27.7
8.0
750.3
1*70, cad 1*72
6,608.5
952.3 ' .
831.6
30.9 .
88.5
1.3
5,443.2
64.0
^^
612.9
-. ~ ':..
'
47.7
42.7
~~
23.4
3.5
1,575.4
3.0
1.841.8
1.041.9
213.0
108.7
102.6
1.7
2,460.6
2,460.6
2.A60.6
340.8
340.8
3,727.4
231:1
184.1
28.4
3,283.8
data.
10.783
5.8*2
836
6*7
33
101
3
4,836
> 101
", m '
ซ "
sn .
'
'
~
76-
3*
m*m
31
1*
, 1,316
1.6M
837
200
83
' 102
. 13
^-^-'
1.790
.1,7*0
1,7*0
3,101
120
320
: 2,763
Zl*
1*8
30
2.3M
A-2
-------
Company A also issued pollution control bonds for retrofit expenses
to be incurred in 1974 and 1975.
Utility B is sharing 20% of the costs of the 440-megaWatt facility
.being completed in 1975 with A, and a third utility which is to own the
remaining 32.5%. Utility B's share of the new lignite-fired facility will
cost about $30 million. It also will share the 450-megawatt facility due
in 1981. This company planned to issue an aggregate of $16 million to
cover pollution control expenditures already incurred or to be made in 1974
and 1975 at three facilities. The utility's 1974 construction budget was
$27.4 million. Construction estimates beyond 1974 are not available.
Utility C (a holding company for three large utilities) outlined ,
a three-year construction program for the years 1974 through 1976 of
$1,457 million, of which $821 million will be used to build production
facilities, with most of the latter amount committed to lignite-fired .
facilities. The company is spending $68 million on developing lignite-
fuel facilities (i.e., mines). Besides seven lignite-fired facilities
due to begin operation between 1975 and 1980, the company is adding
two shared nuclear-powered generating units by 1981.* The estimated
construction expenditures for lignite-fueled generating units, nucjear-
fueled generating units and for additional items contributing to the
protection of the environment will be about $72 million over a three-
year period. They _are appqrti oned to the three ut i1ities owned by the
parent as shown: _
ff . ' -, ' ' ' ' .'.'"-' -
One of the companies is adding an additional lignite-fired unit that
will not be shared by the other two.
A-3
-------
Millions of Dollars
C(l)
C(2)
C(3)
TOTALS'
Electric Power Cooperative
1974
2.0
2.3
5.7
10.0
D has a
1975
5.4
5.8
15.6
26.8
1976 Total
9.1
- -
26.1
35.2
460-megawatt addition
1615
8.1
47.4
72.0
to
lignite-fired capacity scheduled for 1975 operation. This facility*
scheduled for 1975, required supplemental financing of $30 million from
REA to finance "additional cost overruns, facilities modifications,
and additions to Unit 2 facilities." Company D expects to spend $6
million for retrofit pullution control equipment.
Electric Power Cooperative E is adding 435-megawatts of lignite
capacity due to be completed by 1976. They have just spent $4.75 million
to install a precipitator on an'existing site., and will install a preci-
pitator on the new plant.
t E1ectr ic Power CooperatiVeF is adding'significantly to its own
lignite-fired capacity and to that of another power cooperative which
did not have any lignite burning plants in 1974. As project manager, it
is overseeing the addition of 1,000 megawatts more lignite capacity in
1979. In December of 1973, it borrowed $4.6 million to finance pollution
control equipment for existing lignite-fired facilities. They (F and
partner cooperative) borrowed $85 million to finance 1,000 megawatts
*An additional stack and electrostatic precipitator were added to an
existing unit.
A-4
-------
of new facilities from REA at 5%. The balance of the $454million needed
to complete; the project is guaranteed by REA, but will be borrowed from
private sources.
These expansion plans contribute to the expected fourfold increase
in lignite capacity illustrated in Figure A-1. "
3. FINANCIAL RESOURCES ,
The financial resources, borrowing power, and ability to sustain
capital expansion of a utility company are dependent both upon the indi-
vidual company and the type of utility. The lignite-fired electric
generating "industry" has been analyzed by examining six of the eight
' /"'',.- ' ,"
utilities previously listed in Table 1-2. For the purposes of discussion*
we have divided the utilities into two distinct classes from which finan-
cial data and future construction plans have been assembled through a
review of their annual reports and discussions with their corporate ;'.
management and various state regulatory authorities.*
The designation, Class I, refers to investor-owned utilities, which
use long-term public and private debt placement and/or equity to finance
their capital expenditure programs for capacity expansion. Three such
utilities (Companies A, B, and C) have major buildings programs for
lignite-fired generating capacity. The designation, Class II, refers, "
to rural electric cooperatives. Three such cooperatives (Companies,
D, E, and F), herein discussed, have lignite-fired capacity.
fA third class, comprised of two very small, municipally-owned utilities
that use lignite fuel, was reviewed and excluded. The electric revenues
of the two utilities combined were less than $4 million, their net pi ant:was
less than $10 million, and they have no announced plans for capacity expansion.
. A-s :. . :.''' '...'
-------
ป>'*
' 12,000
11,000
10,000
9,000
8,000
"g 7,000
"ง 6,000
S
-^-r-*r-r^5^7 ^%^ '^%/ ^%> ^Z//
\f s r Xrซ'/'S(St'S\('f'S
-------
Class II utilities differ from Class I utilities in that they may
either borrow directly from the REA (at significantly lower rates that
investor-owned utilities) to finance construction or may ask for REA
guarantees on loans from other sources. Class II utilities are typically
smaller ir< tarsus of their generating capacity and invested capital.
The basic financial dsrca for the three investor-owned electric
utilities and the three electric power cooperatives were taken from
Moody's Public Utilities Manual and annual reports, and are shown in
Tables A-2 and A-3 respectively. One of the independently-owned
utilities, Company C, dwarfs the others, and it should be noted that the
financial data shown in Table A-2 for this utility are for the parent
company which owns ibree lar^e subsidiary utilities. . :-
The capitalization of Class I utilities is fairly evenly divided
between debt and equity financing,*. Future capital expansion plans show
that A plans to spend $103 million from 1974-78, B plans to spend $27.4'-'
million In 1974 alone and C plans to spend $1,457 million from 1974-76.
Each of the three Class I utilities has been able to adjust its rates
to cover increase in costs of constructions purchased power, labor,
materials, and borrowed money. When contacted, each of them also indi-
cated that further increases win be necessary to assure coverage of the
interest charges for the new financing planned principally to support
their construction programs.
"Debt is that amount of outstanding capitalization which is held by other
Institutions (including REA) and upon which interest is paid. Equity
consists of coETSROfi stock and earned surplus.
A-7
-------
TABLE A-2
INVESTOR-OWNED UTILITIES (CLASS I),
COMPANY:
Revenues: 1970
1971
1972
1973
Net Plant (1973)
Accumulated Depreciation
Capitalization:
Long-Term Debt
Equity3
Preferred
Total
Interest:
Long-Term Debt
Other Debt
Allowance for Funds Used
Construction
Total
Moody 's Bond Rating
Net Operating Earnings
After Taxes
Times Interest Rate
(Coverage Ratio)
Capital Expansion:
Last five years
Future
(Millions of
A
$ 34.5
38.1
41.7
44.5
$146.1
$ 54.0
59.4
49.9
15.5 65'
$124.8
$ 3.52
.90
During
$ 3.42
A
$ 7,92
2.3
66.0
113.0 (5
BASIC FINANCIAL DATA,
Dollars)
I
Elec. Gas
$24.3 $31.1
25.2 32.9
27.0 36.1
28.7 37.1
$199.4
95.7
84.3
73.9
4 19.2 93J
$177.4
$5.569
.749
$6.318
-1.054
$5.264
A
$11.829
2.25
,
92.7
yrs) 27.4 (1974)
1973 .
C_
$ 453.0
483.4
563.3
615.1
$2,219.2
$ 552.5
993.9
857.2
298.0 1155<2
$2,149.1
$56.44 ,.
87
$57.31
Aaa,Aa
$163.5
2.85C
1,011
1,475 (3 yrs)
Common stocks and earned surplus, etc.
b
Includes surplus reserves.
c
2.51 coverage after transfer of surplus reserves. *
Source: Moody's Public Utilities Index, 1974, and annual reports.
A-8
-------
TABLE A-3
.RURAL ELECTRIC COOPERATIVES (CLASS II). BASIC FINANCIAL DATA, i '
'. '-"' '-'10.9 ".-' '.;. .- ,' :
13.5 16.8 .
14.2 18J
72.3 64.0
19.4 22.0
72.6 68, la
5.1 5:7
77.7 98.8
2.00 2.24
T.46 1.36
1.37 K65
7.87
27.3 - V
a Current maturities were subtracted from long-term debt to REA,
Source: Moody's Public Utilities Index, 1974, and annual reports,
A-9
-------
Interest coverage ("net operating earnings" divided by interest
charges) is a key test in meeting the provisions of financial agreements,
e.g., indenture restrictions, which may affect the timing and amount of
new financing which can be completed. It is sometimes defined to include
the interest on proposed new debt. However, the figures shown herein
only represent a snapshot in time, and are susceptible to change due to
rate increases and accounting charges. A coverage of 2.00 is typically
the minimum required of investor-owned utilities by the conventional
bond market indenture provisions. This coverage is exceeded by all of
the Class I utilities.
In comparison, interest coverage by the three rural electric coopera-
tives, shown in Table A-3 appears to be lower than for investor-owned
utilities. Indeed, Utility D apparently had a slight deficit in 1973,
after interest deductions. Wherever rate increase approvals are delayed
by regulatory commissions, earnings can be appreciably affected, as
was the case with Company D. However, we hasten to add that there are
significant differences between the financial structures and regulatory
frameworks operative between the various investor-owned rystems and the
rural electric cooperatives. Thus, an interest coverage o-? REA utilities
which is less than 2.00 should not reflect negatively upon the financial
structure of the companies.
4. TMO METHODS OF RAISING CAPITAL FOR CONSTRUCTION
A review of the financial profiles of those utilities of concern
here shows little if any difference between utilities which have no ,
lignite-fired capacity. In terms of total capitalization, debt structure,
A-10
-------
and coverage ratios, both Class I (investor-owned) and Class II (REA)
companies are typical of the utility industry in general.
The six utilities comprising the lignite-fired "industry" are but
a small part of the most capital intensive industry in the United States,
The construction programs required to support new lignite-fired facilities,
are only a minor part of the anticipated construction of new generating
facilities (oil, gas, nuclear, coal, sub-bituminous coal facilities having
been excluded.), If there is one key issue facing the industry at the
present time, it is related to the problem of raising capital for
construction.
The debate now centers on whether to continue to increase rates or_ v
whether to assure the flow of lower cost debt to the industry through v
government credit assistance in the form of insurance and guarantee of
debt securities of investor-owned utilities. This is similar to the
way in which the government now assists the rural electric cooperatives
that benefit from REA financing and guarantees. The latter implies
reduced interest costs to the company and utility rates to the customer.
The second, and more obvious approach is to increase electric rates,
which is an unpopular solution to the consumer but without which the
utilities shall find it hard to cover interest charges in times of
increased costs for capital. Unfortunately, these financiaTproblems
arise at a time when it Ts important to reduce'the nation's, dependence
on oil and to begin to rely more heavily on domestic fuels such as
lignite.
A-ll
-------
The six utilities discussed in this report all commented in their
annual reports on the importance of rate increases to a financially
viable operation. The salient issues regarding their rate situations
may be summarized as follows:
Company A;
Average residential rate 3<ฃ/kWh; sought permission to raise
its electric rates by mid-1974. Based on their 1973 Annual
Report, they paid 7.65% interest on a new bond issue., 5.92%
for interest on pollution revenue bonds, and issued more
common stock, and complain that it is becoming more difficult
jm
for them to cover increased costs, including costs of lignite
fuel.
Company B;
Average residential rate = 2.7$/kWh. Issued debt, asked
for increases in rates to cover higher costs.
Company C:
Their average rates appear comparable to Companies A and B.
Raised its rates in 1972 and filed for rate increases of 9%
to 11% with cities and towns in its service area to cover
increased operating costs,
Companies D and E;
Both sell power wholesale for 0.652<ฃ/kWh and 0.787^/kVlh, respec-
tively. They each have REA financed lignite capacity under con-
struction. D was to effect a 21% rate increase to its wholesale
customers effective with their January, 1975 billing, while E's
member's charge rural residential customers 2.01 to 2.53^/kWh.
t
A-12
-1/4 " ' ' !'''-
-------
Company F: .
Recently received a loan of $36.47 minion from REA at an
interest rate of 5% and payable over 35 years for construction
financing. F's management does not foresee a reversal of econo-
mic conditions to the relatively stable ones it has known ^
before. ..'' :
In summary, it appears that the financial viability of both
Class I and Class II utilities is being undermined by high operating
costs, high finance costs, a possible shrinking availability of debt
and, for investor-owned utilities, the weakness of the present equity
market as well as the need for near-term pollution control equipment
financing. Forces quite outside the utilities' control are requiring
at the same time that these utilities plan for continued
growth in service at reasonable rates.
In general, the Class I utilities appear to have the resources
to service the debt required if the rate making process (or the equiva^
lent mechanism by which the public interest is served and the financial
integrity of the utility is maintained) can respond to assure the utilities
ability to carry out a contemplated construction program. The Class II
companies appear to be in a slightly more flexible position.* In neither^;
case is the cost of NOx control overburdening. '
A more complete treatment of the financing requirements of the principal. -
utilities associated with lignite involves the host of considerations affect-
ing the U. S. electric utilities in general at this juncture. Such a
treatment is well beyond the scope of the present study.
A-13
-------
-------
APPENDIX'S
DATA REDUCTION PROCEDURES
1. Emission index
The emission index E (Ib/million Btu) was calculated from the follow-
ing expression :
E = 1.215xlO~7CFD (1^
where C ป NOX concentration (ppm, dry basis), F is the dry flue gas volume
,(dscf ;per 10 Btu) at zero excess air as discussed above, and D * 2090/ :
IZ&Jelercent 02). The F-factor method was used with F taken to be 98 ;
dscf/lo Btu. Direct measurements of FD using velocity! trav*rsซs and
moisture data were not used in expression (1) because the values were 5 So
16 percent greater than expected from lignite C-H-0 composition forr~V "
all four test series. These direct measurements of FD also exhibited much
were scatter. This is illustrated in Table B-T.i Possible explanations
are as follows:
(1) Measured lignite heating value is lower than tactual".~;
(it) Measured mean stack velocity is higher than actual, due to
swirl component.
(iii) Measured lignite feed rate is lower than actual,
(iv) Stack cross sectional area is lower than assented.
(v) Stagnant zm&s existed and wซre net traversed.
Accordingly the emission index values were calculated using the F-facfdr
method. The use of the F-factor method was later verified in follow-up
tests. One of the lignite-fired steam generators was retested to determine
the probable cause of the discrepancy between the measured gas volume
and gaง volume aง calculate by thi F=fงgfcงr> mtte$: Thiง 1r)vงงl|p|fงR
det@fffliHงd that thง 0aง vง1eeity itieeisuiซettiงritง were ih erren duง to i
interference between the thermocouple and the pitot tube of the contractor's
B-l
-------
Table 13-1 SYSTEMATIC ERROR IN FLUE GAS
VOLUME PER BTU
Volume per Btu
Volume per Btu
using stack velocity
(dscf/l(nBtu.)
using F-factox-
Di fference
(percent)
Average systematic error
B-2
-------
equipment. The gas volumes calculated from the measured values were,
consequently, in error. Preliminary analysis of the data from the
retest showed excellent agreement between the dry gas volume calcu-
lated by the F-factor method and the measured values. A simpler F-
factor method which gives comparable results was promulgated in the
Federal Reg-ister on October 6, 1975 (40 FR 46250).
2. Uncertainty Analysis
Let us examine the uncertainty in emission index, AE/E, in terms of
the component uncertainties A02/02, AF/F, and AC/C. , Taking the partial:
differentials of expression (1) we can derive the uncertainty: '
(2)
Since 02 was typically 5 percent at the point where NOX measurements
were made, expression (2) reduces to
(AE/E)2 = (AC/C)2 + (AF/F)2 + (0.3 ,A02/02)2 . - (3)
We estimate the uncertainty in reported 02 data of approximately 10
percent of reading (typical value 5.0 ฑ .5 percent): ,
A02 = 10 percent
ฐ2
This is based on (a) observation of 02 drift in the control room, (b)
scatter in the Orsat 02/C02 correlation (See Figure B-l), (c) scatter
in the difference between 02 measured before and after the preheater (See
Figure B-2), (d) readability and precision of 02 instrumentation.
B-3
-------
o
PIT-
'S
-------
CM
o
^
u
3
CO
60AX Plant I
A+.0 Plant II
9% Air
Leakage
Data points with dot above were corrected
for errors due to:
a) Bag leakage prior to Orsat
b) Non-Simultaneous 02 measurements
c) C>2CC>2 inconsistency
Number of data corrected:
17 of 60
_L
_L
3 4
O2 Upstream of Air Preheater (Percent)
Figure B-2 ESTIMATION OF PREHEATER LEAKAGE,
B-5
-------
Based on variations in lignite analyses, we place the uncertainty
in F-factor at 3 percent of reading (typical value 98 ฑ 3 dscf/KTBtu).
This agrees with previous experience of EPA personnel with F-factors.
^&- = 3 percent
The uncertainty in NO (ppmj dominates the emission factor uncer-
rt
tainty and critically affects the standard setting process in that (a)
some margin is required for NOV guarantees of boilers, and (b) the stand-
X
ard must be based on upper limit emission behavior rather than on the
mean emissions. We estimate the uncertainty in the NOX concentration
measurements conducted in support of this standard at ฑ 8 percent for the
Plants I & II test series, at + 5 percent for the Plant IV series, and
ฑ 4 percent for the Plant III test data.
AC
C
8 percent for Plants I & II
5 percent for Plant IV
4 percent for Plant III
This corresponds to about ฑ 30 ppm for all test series.
Three pieces of evidence support this contention:
Reproducibility: Observed scatter in the current NOX data
(PDS) taken on a given boiler (for a given operating con-
dition) resulted in a standard deviation of 3 to 9 percent,
as shown In Table B-2. It was necessary to discard 29 out of
95 data points in the Plants I & II Series because contamination
of PDS samples and leakage caused anomalous results.
B-6
-------
PDS Accuracy; A recent study12 reports that the accuracy
of the PDS method on coal-f1red bo11er ranges from 3 percent
at 1000 ppm to 10 percent at 100 ppm. At 400 ppm the
accuracy Is about ฑ 5 percent. Fisher18 reports 4 percent
reproducibility of the PDS method on repeat tests of the
same sample, and 5 percent random difference from the NDIR results,
Table B-2 REPRODUCIBILITY OF NCL MEA^UREMlNTS"
, " '
(Lignite-Fired Utility Boilers-, '"
. PDS Method)
* First day; systematic drift gave large "apparent" scatter.
Unit
Plant II
'k:-q ::' " " -;
Plant I "'--..
Plant III
Plant IV
No. samples at
test condition
.... . . 7 ... -...
6
10
7 "-'
13
'''" "5" '-'.' . ' ..
5
5
: 5 ; ' - " ,,
13
9
9
Standard deviation
as percent of mean
'.- -:-; ^- 7.3^ , ''.''
6M
8.6%
7.8%
(16.2%)* i
3.0%
6,0% ';,..,;,..
' .-.'; . ' 3.2% :'._ ..'V/".
3,6%
(6.3%)*
' . . . 5.7% ''.';.':'
3.5% ''.-.;
B-7
-------
Electrochemical Analyzer Accuracy; Although 1t proved useful
to reveal on-slte trends, the continuous monitor as used, was of ;
limited value as a rigorous data source, because of inadequate
protection against thermal drift;, + 5 percent readibility (low
range was 500 ppm), observed calibration adjustment of about +_ "
5 percent, and limitations of the S02 scrubbing solution (if 5G
ppm of S02 gets through the scrubber/ It is detected as NOx).
Based on substitution of these values into expression (3)s ซ,ve esti-
ate emission uncertainty at ฑ 9 percent, ฑ 7 percent, and t 6 percent ,
..... ',\
for the Plants I &'ll, Plant IV, and Plant III series, respectively,
AE/E = 9 percent., Plants. I & II
7 percent. Plant IV
G percent, Plant III
3. Screening and Adjustment oj\J32..anQJLJMl.
The 0 data were criticaTl7 examined using three tests: ?1rst,
Orsat 02 was compared to analyzer 02> expecting a fairly uniform degree
"of Teakage'fpf Plants I ancf II'to "cause a" standard1? pefcent ftg differeilce
(See Figure B-2). Second, abnormally high 0? readings, say in sxcess of
7 percent, were discarded and attributed to Orsat bag leakage, Third9
(09, C09) pairs were plotted to reveal pairs falling unusually far from .
Ct Cm
the straight line expected for lignite (based on 18.5 percent COg at
0 percent 02). An example of this third screening technique is illus-
trated in Figure's-!.
B-8
-------
Of 60 02 data points in the Plants I & II seHes, 17 were adjusted tp
provide internal consistency and satisfy the three criteria above within
0.5 percent 02 (denoted with dots on Figure 6-2).
The NOX data Were reviewed according to the following criteria:
(i) Data taken during a boiler transition (approximately :
" ' , - ' - - - - ' , ' . , , ' . ' - L ','.'':
'..'... 15 min duration) were discarded, ,:
(ii) Method 7 PDS data were discarded when deviating more
than two standard deviations (approximately 70 ppm)
from the mean for a given condition. Flask leakage
and hood contamination gave some quite obvious stray
data for the, Plants I & II tests. These stray data were
discarded. __ "::.-_-!
(iii) Dynasciences NO data were used only when PDS data was
. : : ' : '.-. . . X - / . .-.- :' : -'.' :...: ' : , -. '., . ...:.' :'" ;...'.>
insufficient for a given boiler condition, and then only ,; :
' '..;-.. '..''"- .. ' .' .'"'''''-' : ' ''-. .'';.'.-. . ''. . '
provided the Dynasciences results had shown good corre-
lation with PDS samples of the same day.
Figure B-3""compares the PDS and electrochemical data on NO ; this
' ' ','*-'. ' " - '** - ' ' !
Figure was useful in identifying stray points. The best fit gave PDS :
results 15-50 ppm lower, conceivably due to flask leakage before PDS ;
analysis. Corrections were applied to the electrochemical data to com-r
pensate for this systematic error, as shown in Table B-3.
4. Averaging Procedures
All NO data taken during a fixed boiler operating condition, during
X__ _^_, r ' '"__''---.,--- ' - . ' . '
any one day, were averaged-PDS data only, adjusted as noted above, and
supplemented by electrochemical data where appropriate.
B-9
-------
500
400 -
300 -
m
o
o.
VJ
I
Legend:
PDS Data Accepted
PDS Data Screened Out;
Electrochemical Used Instead
200 300
Electrochemical
400
500
Figure B-3. NOX (ppm, dry) MEASURED BY 'METHOD 7 AMD BY ELECTRQCHEMSCAL AWALYZ5ER
B-10
-------
Table B-3 ADJUSTMENTS APPLIED TO ELECTROCHEMICAL
NO* DATA IN ORDER TO COMPENSATE FOR SYSTEMATIC
DIFFERENCE BETWEEN PDS AND ELECTROCHEMICAL
Unit
TVSrt'i 7"
~ "Flint 1 1^
Measured
electrochemical
NOX (ppm)
385
310
390
365
380
320
345
335
-.._
i
Systematic
difference between
electrochemical and
PDS on that day (ppm)
-45
-15
-50
-50
-50
-20
-20
-20 "".'..';
Adjusted
electrochemical
NOX (ppm)/ :
340
295 '"' ]',"
340 /
sis:
330
300
' ' '
325
315
B-n
-------
We denote this average <, The Og data were also averaged
for each test Interval ind dilution correction? were applied to
rtduce (NO } values to a common dilution condition (3 percent 02).
The 09 and NO samples were not always simultaneous; thus individual
c. **
emission index calculations at a given day and hour were not
possible. The lignite feed rate (ton/hr) and stack gas velocity.
weft also averaged over each test series. From this average datas
ซ representative, dscf/Btu-value was calGi$a&>4 fey both-the direct
and F-factor method.
In additions all baseline (NO., at 3 percent 00) data for a given
X (L
boiler were averaged9 and standard deviations derived (weighted by ths
number of samples per test interval). The values of E(or NO at 3 per-
cent Og)from successive test series were we!1 within the 8 percent esti.-
mated scatter.
B-12
-------
APPENDIX C
COSTS FOR LIGNITE AND COAL FIRED PLANTS : ^ ''
Of the 26 utility owned units1 idenified within the U.S..de-
tailed cost information was collected on 21 units and is summarized ;
in Table C-l. From this 11st, which represents 98% of the installed. :!
generating capacity and 97% of the annual production accounted for
in Chapter II. we derived the folSowiria:. . '
Unit investment cost ($/kW) as a function of total
plant size, and
Unit production costs (mills/kWh) as a function of
annual net generation.
FiguresC-l and C-2 show the installed costs and production
costs respectively of those units for which data was available;thฅser
figures are expressed in 1972 dollars. For comparison, investment and
annual operating costs were assembled for 15 bituminous-fired steam-
electric units between 200 to 1,000 megawatts in size. These data are
shown in Table C-2. ;
C-l
-. - , -.' ' :.-__...: .- V '/
-------
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I O Coal Fired
Lignrte Fired
I
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100
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'"'eoo
200 300 400
Installed Cost"($/kWh).
*
FIGURE C-l INSTALLED COST VS PLANT SIZE FOR REPRESENTATIVE
COAL-FIRED AND LIGNITE-FIRED PLANTS
P-4
-------
10,000
1,000
CO
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C-6
-------
TABLE C-2 (Continued)
' , ' ;
DtUntty:
Mซat: . _' ' .
totalled Generating
' Capacity (megawatts)
Bee Cfenerstion (106kwh)
Ft alt 'Demand on Plant
(ttegiawatts)
First Year of Operation: ,
COST OF PLANT:
land ' .
Structures
Equipment
total Cost
Unit Installed Cost ($/kป) i
total Cost
Equipment Only
SKQDtfCTION EXPENSES:
Operation Supervision
Steam Expenses
Electric Expenses
Misc. Power Expenses
Kaljntananco
Supervision
Structures
Boiler Plant
lectrieal Plant
Structure
Subtotal
fvtfi - ' .
Total Expenses
Fuel Percentage of Total:
Unit Operating Cost Mills:
FtJBt CONSUMPTION
CMl (103 Tons)
(coat/ton)
1 (Btu/lb)
Oil (bbls)
(cost/bbl)
(Btu/gal)
Gaป (Mcf)
(coet/10J Mcf)
(Btu/cub. ft.)
*ปg. Stu/fcwh Net Generation:
\tir'"iฐ AฐnuปA flant EM lelenc-
JgjiSESOTA
No. States
Paper Co.
Allen S. King
. 598.4
3,310.1
NR '
1968
566
15,151
66.215
81,932
137
, 111
124
530
214
317
76
61
864
52
IS
2,316
12,811
15,127
84.7
'4.57
1,476.4
8.68
10,770
9,608
r: .355
(thousands of 1972
MISSOURI
Empire District
Elec. Co.
Asbury
212.8
1,288.7
192.0 .
1970
125
778
25.004
25,907
122
. . . - 118
111
108
116
40
27
12
170
32
620
3,296
3,916
. 84.2
3.04
654.5
5.02
10,434
10,609
.322
dollars)
FUปIDA
Tampa Electric
Co.
Big Bend
445.5
1,976.5
382.0
1970
3,931
14,372
53.999
72,302
162
121
127
261
.191
239
56
28
593
151
_งi
1,734
8,314
10,048
82.7
5.08
929.0
8.95
11,255
10,581
.323
ซl*.a
-------
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APPEND! X-D ;
FUEL-NITROGEN CONTENTS OF LIGNITES
Table D-l lists literature values for ths average fuel-nitrogen
content of Texas and North Dakota lignites. All values have been
recalculated as necessary to express percent nitrogen on a common,
moisture and ash free basis. Specific references have also been
listed with each entry in Table D-l to allow quick verification of
sources.
Table D-l. FUEL-NITROGEN CONTENT OF NORTH DAKOTA AND TEXAS LIGNITE
Percent Fuel-Nitrogen on a
Moisture and Ash Free Basis
I exas
Reference
North Dakota
1.4
1.4
1.3
1
1,1
44:
45
43
Table D-l shows that North Dakota lignite does not contain sub-
stantially more fuel-nitrogen than Texas'lignite as some utilities claim.
However, it should not be concluded that Texas lignite has significantly
more fuel-nitrogen either. Reference {43} which is specific for North
Dakota lignite is an exhaustive study In which over 500 separate
analyses were performed. Consequently, the apparent difference between
the. fuel-nitrogen content of Texas versus North Dakota lignite may only
be the result of possessing a smaller amount of data for Texas lignite.
D--1
-------
Table D-2 gives the average fuel-nitrogen content for the ten
major North Dakota lignite mines. Variation of the average fuel-
nitrogen content among these ten mines is slight. In order to test
the hypothesis that there is no appreciable difference between fuel-
nitrogen contents of various North Dakota lignites, the Chi Square
Test has been applied to the data in Table D-2. The Chi Square Test
indicates the probability that deviation from an average value (0.6%
N2 as received in this case) was caused by some factor other than
chance or sampling error. Letting "f" equal the average percent fuel-
nitrogen per mine on an as received basis, the Chi Square for the
data in Table D-2 is:
X2 = S [(0.6 - f)2/f] = 0.0829.
Comparing the calculated Chi Square to a standard table of Chi Squares,
there is less than a 1 percent chance that the observed deviations
46
occurred due to some factor other than chance or sampling error.
Thus, statistically, there is no reason to assume that the average
fuel-nitrogen content of North Dakota lignite varies significantly
between mines.
D-2
-------
Ta bl e D-2. FUEL-NITROGEN CONTENT OF VARIOUS _N_QRTH: DAKOTA
Mine
South Beul ah
North Beul ah
Indianhead
Glenharold
Dakota Star
Velva
Baukol-Noonan
Kincaid
Gascoyne
Savage
Average % FueT-Nitrotftk W- v.
As Received
0.7
0,6
0.6
0.6
0.5
0.7
0.7
0.6
0.5
0.6
Water and | $ fy Fre^
,..;.-. -0:V/ -
1,06
. - - .
I '* EpB' ' * s-
'"'*.' r'"'1 ' '
- -\'$'3?$v: . '*
,' ; . 0.9 ''
' '- - ^ .' ...
" . " -1V2; ''-''-.
' : !.:'.".- 1 J ". - ;'.'
. "'"! ;:"-l'.P'1 '",-.:;
1.1 ;
"D-3
-------
TECHNICAL REPORT DATA
(Please read fastzuctions on the reverse before completing)
1. REPORT NO.
S*-A-.450/2~76-030a
3. RECIPIENT'S ACCESSION'NO.
4. TITLE AND SUSTP.
Standards Support and Erwironmental Impact Statement,
Volume 1: Proposed Standard of Performance for
Lignite-Flrec! Steam Generators
s. REPORT DATE
December 1976
6. PERFORMING ORGANIZATION CODE
7.
8. PSRROHMING ORGANISATION JRBPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
U. S, Environuental Protection Agency
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
10. PROGRAM ELEMENT NO. .
11. CONTRACT/GRANT NO.
12. SPONSORING AGENCY NAME ANC ADDRESS
13. TYHH OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
I
NOTES VoTutneT discusses the proposed standards and the resulting .
environmental and economic effects. Volume 29 to be published when the standards are
protnulgated, will contain public comments on the proposed standards EPA responses9
and a discussion of differences between the proposed and promulgated \
standards. '
A stanaard of performance for the control of emissions of nitrogen oxides from
new and modified lignite-fired steam generators is being proposed under the authority
of section 111 of the Clean Air Act. When standards of performance for large steam
generators were promulgated under Subpart D of Part 609 lignite-fired units wer^
exempted from the nitrogen oxides standard (the sulfur dioxide and particulate
matter standards are applicable to lignite-firing) because of a lack pfdata oh
attainable levels of emission from such units. Since thens sufficient data has-been
obtained to propose a standard. This document contains the background information., ,
environmental impact assessments and the Rationale for the derivation of the proposed
standard.
HEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air pollution
Pollution control
Standards of performance
Fossil-fuel fired steam generators
Nitrogen oxides
Air pollution control
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)'
Unclassified
21. NO. OF PAGES
190
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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