-------
arc computed according to actual utility and industrial fuel use in 1973.
The effluent quantities reported could be reduced further if feedwater
solids concentration specifications for utility and industrial boilers
were also considered. However, such figures would be over-refined con-
sidering the precision of the data input. Therefore, the figures pre-
sented are very conservative and represent the highest possible flow
volume.
The total solids or suspended solids concentration of feedwater treatment
waste water is equally difficult to determine. The range illustrated in
Table 99 is based on the concentration stipulated for clarification wastes
from electric utilities and the assumption that effluent concentration
will be reduced since the average industrial feedwater specifications are
liberalized to a large extent.
Boiler Slowdown
Boiler blowdown is practiced in industrial boilers in the same manner as
electric utility boilers. Blowdown is required to limit the concentra-
tion of dissolved and suspended solids in the boiler water. This practice
helps prevent the formation of scale on metal surfaces which otherwise
causes reduced heat transfer efficiency and deteriorated structural
stability. The hazardous constituents found in blowdown include sus-
pended and dissolved solids, hardness, acidity, alkalinity, phosphates,
and silica. All concentrations will be greater than or equal to those
characteristic of utility boiler blowdown due to the less stringent water
specifications for industrial boilers.
There are no data that specifically define the volume and characteristics
of industrial boiler blowdown other than the NPDES permit applications.
As such, the figures presented for industrial boilers in Table 100 are
based on electric utility boiler blowdown quantity and quality. The blow-
down volume reported is proportional to utility and industrial fuel
278
-------
Table 100. INDUSTRIAL BOILER SLOWDOWN, 1973
2.0.00.0.0 Industrial
2.1.00.0.0 External Combustion
2.1.10.0.0 Coal
2.1.11.0.0 Bituminous
2.1.11.1.0 Pulverized Dry
2.1.11.2.0 Pulverized Wet
2.1.11.3.0 Cyclone
2.1.11.4.0 All Stokers
2.1.11.5.0 Overfeed Stokers
2.1.11.6.0 Spreader Stokers
2.1.11.7.0 Underfeed Stokers
2.1.12.0.0 Anthracite
2.1.12.1.0 Pulverized Dry
2.1.12.2.0 Pulverized Wet
2.1.12.4.0 All Stokers
2.1.13.0.0 Lignite
2.1.13.1.0 Pulveri2ed Dry
2.1.13.2.0 Pulverized Wet
2.1.13.4.0 All Stokers
2.1.13.5.0 Overfeed Stokers
2.1.13.6.0 Spreader Stokers
2.1.13.7.0 Underfeed Stokers
2.1.20.0.0 Petroleum
2.1.21.0.0 Residual Oil
2.1.21.0.1 Tangential Firing
2.1.21.0.2 All Other
2.1.22.0.0 Distillate Oil
2.1.22.0.1 Tangential Firing
2.1.22.0.2 All Other
2.1.30.0.0 Gas
2.1.30.0.1 Tangential Firing
2.1.30.0.2 All Other
2.1.41.0.0 Bagasse
2.1.. '.2. 0.0 Wood/Bark
Volume ,
106 gal/yr
3,630
585
560
280
55
17
210
13
190
9
4
0
0
A
17
0
0
17
0
17
0
720
540
85
455
180
30
150
2,215
215
1,900
10
100
TSS,
ai£,/£
30
TDS,.
lug/ 1
150
Ammonia,
mg/ 1
1
Phosphate,
mg/,8
5-50
'
Alkalinity,
nifi/J
10-100
279
-------
consumption. Other values are equal to those presented for electric
utilities. Although the data quality is questionable, these quantities
represent the best available data.
Equipment Cleaning Wastes
Industrial steam generating boilers require periodic cleaning in the same
manner as utility boilers. The water side of industrial boilers requires
preoperational and operational cleaning. The extent and characteristics
of water-side cleaning wastes are independent of the type of fuel used.
Cleaning waste waters can contain excess acidity, alkalinity, phosphates,
organic compounds, copper, iron, hardness, and turbidity. Fire-side boiler
cleaning is also required in the industrial steam generation sector. The
quantity of water and waste is vastly reduced from utility generation due
to the large use of natural gas for fuel. As such, the quantity and impact
of boiler fire-side cleaning waste water is insignificant.
Cleaning waste water disposal methods include controlled periodic release
to a waterway and discharge to a holding tank prior to discharge to am-
bient water. As in utility boiler cleaning, federal regulations pro-
hibit controlled release without a permit so that holding and sedimenta-
tion is the predominant control method. Where cleaning is done by an
outside firm, waste water may be trucked away to appropriate land disposal.
The characteristics of equipment cleaning waste water appear in Table 101.
The volume is derived from the amount associated with electric generation
utility boilers and is based on the proportion of fuel consumption within
each sector. Pollutant concentrations existing in electric utility clean-
ing waste water are reported for industrial cleaning waste water and, there-
fore, represent a very conservative estimate of emissions. However, these
values are currently the best available data to adapt for industrial
boiler cleaning.
280
-------
Table 101. INDUSTRIAL EQUIPMENT CLEANING WASTE WATER, 1973
2.0.00.0.0 Industrial
2.1.00.0.0 External Combustion
2.1.10.0.0 Coal
2.1.11.0.0 Bituminous
2.1.11.1.0 Pulvarized Dry
2.1.11.2.0 Pulverized Wet
2.1.11.3.0 Cyclone
2.1.11.4.0 All Stokers
2.1.11.5.0 Overfeed Stokers
2.1.11.6.0 Spreader Stokers
2.1.11.7.0 Underfeed Stokers
2.1.12.0.0 Anthracite
2.1.12.1.0 Pulverized Dry
2.1.12,2.0 All Stokers
2.1.13.0.0 Lignite
2.1.13.1.0 Pulverized Dry
2.1.13.2.0 Pulverized Wet
2.1,13.4.0 All Stokers
2.1.13.5.0 Ovsrfeed Stokers
2.1.13.6.0 Spreader Stokers
2.1.13.7.0 Underfeed Stokers
2.1.20.0.0 Petroleum
2.1.21.0.0 Residual Oil
2.1.21.0.1 Tangential Firing
2.1.21.0.2 All Other
2.1.22.0.0 Distillate Oil
2.1.22.0.1 Tangential Firing
2.1.22.0.2 All Other
2.1.30.0.0 Gas
2.1.30.0.1 Tangential Firing
2.1.30.0.2 All Other
2.1,41.0.0 Bagasse
2.1.42.0.0 Wood/Bark
Volume,
106 gal/yr
1,210
195
187
92
18
6
71
4
64
-3
2
0
2
6
0
0
6
0
6
0
240
180
28
152
60
10
50
740
74
666
5
30
Hardness,
nZ/Jt
4,000
TS,
n>3/.e
9,130
TSS,
mg/^
130
1
IDS,
n>3//
9,000
281
-------
FUEL STORAGE AND HANDLING
Coal use represents 16 percent of fossil fuel consumption by the indus-
trial combustion boilers considered in this document. Industrial boilers
burning coal are responsible for all fuel handling wastes. Emissions
from industrial petroleum and natural gas storage are negligible. Indus-
trial coal handling practices do not differ appreciably from methods
followed by electric utilities. However, the industrial sector does not
require storage facilities as extensive as electric utilities require.
52
A storage capacity of 10 to 30 days' coal supply is recommended.
Storage requirements shown in Table 102 were calculated on the basis
of a 30-day storage requirement, 15-feet storage depth, and a density
of 75 Ib/cubic foot.
Wastewater Emissions
The volume of coal pile drainage shown in Table 102 was determined for a
40-inch average yearly rainfall. The concentration of individual pollu-
tants in the coal drainage will be equal to figures previously presented
in Table 69 for utility coal handling. This is the case because the
relative mix of bituminous, anthracite, and lignite coal consumption in
both the utility and industrial sectors is the same.
The extent of coal drainage collection and treatment within the industrial
sector is unknown. It is assumed that industrial boilers of greater than
500 x 10 Btu/hr capacity have collection and treatment corresponding to
utility practices. This accounts for 25 percent of industrial steam
generation capacity using coal for fuel.
Air Emissions
Air emissions from industrial coal pile storage and handling, shown in
Table 102, were calculated in the same manner as for utilities. A factor
282
-------
Table 102. INDUSTRIAL COAL HANDLING EMISSIONS, 1973
2.0.00.0.0 Industrial
2.1.00.0.0 External Combustion
2.1.10.0.0 Coal
2.1.11.0.0 Bituminous
2.1.11.1.0 Pulverized Dry
2.1.11.2.0 Pulverized Wet
2.1.11.3.0 Cyclone
2.1.11.4.0 All Stokers
2.1.11.5.0 Overfeed Stokers
2.1.11.6.0 Spreader Stokers
2.1.11.7.0 Underfeed Stokers
2.1.12.0.0 Anthracite
2.1.12.1.0 Pulverized Dry
2.1.12.2.0 Pulverized Wet
2.1.12.4.0 All Stokers
2.1.13.0.0 Lignite
2.1.13.1.0 Pulverized Dry
2.1.13.2.0 Pulverized Wet
2.1.13.4.0 All Stokers
2.1.13.5.0 Overfeed Stokers
2.1.13.6.0 Spreader Stokers
2.1.13.7.0 Underfeed Stokers
2.1.20.0.0 Petroleum
2.1.21.0.0 Residual Oil
2.1.21.0.1 Tangential Firing
2.1.21.0.2 All Other
2.1.22.0.0 Distillate Oil
2.1.22.0.1 Tangential Firing
2.1.22.0.2 All Other
2.1.30.0.0 Gas
2.1.30,0.1 Tangential Firing
2.1.30.0.2 All Other
2.1.41.0.0 Bagasse
2/1.42.0.0 Wood/Bark
Storage requirements
103
tons stored
- 5,000
5,000
4,700
2,300
4,500
150
1,800
120
1,603
80
50
0
0
50
250
0
0
250
0
250
0
NAa
NA
NA
NA
L;ind area
rrquirrj,
acres
200
200
190
95
19
6
70
4
63
3
2
0
0
2
8
0
0
8
o
8
0
NA
NA
NA
NA
Volume
equircd ,
cru-ft
3,000
3,000
2,950
1,400
280
90
1,030
65
970
45
30
0
0
30
120
0
0
120
0
120
0
NA
SA
NA
NA
fiater emissions
Co.-il dr:i in.ir;c,
R.-il/yr x !()'>
220
220
210
105
20
5
80
5
72
3
2
0
0
2
8
0
0
8
0
8
0
KA
NA
NA
NA
Air emissions
103 Ibs of
particulatcs/yr
18
18
17
8.6
1.6
0.4
6.5
0.4
5.9
0.25
0.16
0
0
0.16
0.65
0
0
0.65
0
0.65
0
NA
NA
NA
NA
"NA - Not applicable.
283
-------
of 0.0035 lb/ton/yr53'54 is used and is applied to a total of 5 x 10
ton/yr of coal stored.
SOLID WASTE COMBUSTION
In the past several years interest in the burning of waste products as
1 8
fuels has increased due to the high cost of disposal and scarcity of
suitable landfill sites. There are currently four methods of utilizing
solid wastes as fuels for the production of steam or electricity for
industrial use. These are:
• The incineration of municipal refuse (MR) to
provide steam for industrial purposes.
• The supplemental firing of waste fuels in
industry to provide heat and/or steam.
• The firing of sugar cane wastes, bagasse, to
produce steam.
• The firing of wood, bark wastes or wood
products to produce heat or process steam.
Waste products are used for fuel primarily because they represent a
18
disposal problem and are available at minimum costs. Table 103
contains a listing of the heating values of various waste products.
The firing of wastes to provide energy for industry is carried out on a
comparatively small scale; i.e., each plant burns its own wastes for
disposal and to meet part of its own energy requirements. The exception
is the firing of MR as a fuel where large collection and firing facilities
are an economic necessity. The small size of individual contributors to
solid waste combustion makes inventorying each contributor difficult, if
not impossible.
284
-------
Table 103. TYPICAL INDUSTRIAL WASTES WITH
SIGNIFICANT FUEL VALUE18
Waste
Gases :
Coke-oven
Blast-furnace
Refinery
Liquids :
Industrial sludge
Black liquor
Sulfite liquor
Dirty solvents
Spent lubricants
Paints and resins
Oily waste and residue
Solids :
Bagasse
Bark
General wood wastes
Sawdust and shavings
Coffee grounds
Nut hulls
Rice hulls
Corn cobs
Average heating
value (as fired),
Btu/lb
19,700
1,139
21,800
3,700- 4,200
4,400
4,200
10,000-16,000
10,000-14,000
6,000-10,000
18,000
3,600- 6,500
4,500- 5,200
4,500- 6,500
4,500- 7,500
4,900- 6,500
7,700
5,200- 6,500
8,000- 8,300
For clarity, each method of solid waste firing for industrial purposes
will be discussed separately.
Bagasse Combustion
Bagasse is the fibrous waste produced from the processing of sugar cane.
n I
It has an average heat content of 4,600 Btu per pound, and has been
burned to provide energy for electric power generation in Hawaii since
shortly after the turn of the century. Generally, every cane sugar fac-
tory produces power for its own use and some supplemental power. The
power output ranges from 2.3 to 17.0 MW.25 Stack gas emissions have not
been studied to any great extent although the EPA is now conducting tests
in Hawaii and Florida to determine emission factors for bagasse combustion.
285
-------
However, because of the low sulfur content of bagasse, S02 emissions should
be low. NO levels are expected to be small because of the low flame tern-
X
peratures. The major pollutant loading comes from particulate emissions.
The variations in the properties of the bagasse fuel and boiler design
result in large fluctuations in the level of emissions (1.8 — 20.0 mg/m )2^
and corresponding changes in particle size distribution of the fly ash.
The fly ash is usually returned to the field for cultivation.
3
Table 104 lists the emissions from bagasse burning facilities. The
emissions for bagasse were taken from the 1972 NEDS Report because of
the lack of information from any other sources.
Table 104. TOTAL STACK EMISSIONS FROM BAGASSE BURNING FACILITIES'
1.2.4.1 Bagasse
Tons
fuel
-
io12
Btu/yr
-
Emissions, 10^ tons/yr
Particulates
42
so2
0
NOX
5.5
CO
5.5
HC
5.5
The Incineration of Municipal Refuse
Facilities for the disposal of solid waste and the production'of process
steam are more numerous than for the production of electricity. Table 105
lists the facilities presently in operation or planned for the near
future that plan to use MR fuel combustion to generate steam for distribu-
tion. The chemical and physical properties of municipal refuse have been
documented in Section II. As noted, the heating value of MR is too low
and variable for utility use.
The steam generating plant in Saugus, Mass., will be discussed below as
a general example of industrial steam generation from wastes. The Saugus
plant utilizes a water wall boiler. The basic requirements of the
plant are to accept an average of 1200 tons per day of domestic and
286
-------
Table 105. PLANNED OR EXISTING REFUSE TO ENERGY SYSTEMS
55
00
Location
Saugus, MAM.
Iralntree, Mau
Harrlaburg, Pa.
Chicago, 111,
Nashville, Ttnn.
Norfolk, Va.
Portsmouth, Va.
Akron, Ohio
Cleveland, Ohio
Palner Township, tit
Brockton, Mass.
Chicago, lit.
Bridgeport, Conn.
Hennstead, N.T.
New Britain, Conn.
Lane County, Ore.
ttackpnsnck Koadovlandfli N.J.
HUvauVfe, Wise.
Washington, D.C.
Montgomery County, Md.
Madison, Wise.
Us Angelra, Calif.
Honolulu, I1.iw.ill
Housalonlc Valley, Conn.
Number
of
bollera
2
2
2
t
2
t
I
Rofuae
(erd rate.
ton/hr
62. S
10
10
66.67
30
it
«.u
StlMffl
r.itp,
Ih/hr
370,000
60,000
185,000
Uu.OOO
270,000
100,000
40,000
Sl.-.im
twn|i.,
°P
S75
-405
465
414
600
~4»
-1*0
St ciin
prennurc,
P«l«
KVO
250
250
2JJ
400
27S
US
5 team uae
Onmncretal *
G. E.
Commercial
(heating
and cool-
ing)
U.S. Navy
Ship*
R«'flU!0
prev'-'r^tlitn*
A.C.
0
0
0
0
0
0
S.
X
-0
X
X
0
X
M.
X
0
X
0
0
0
Other
fuel
Oil
Caa
Oil
Caa
.Oil
Furnace
type
Moving
ern'e
Traveling
grate
Recipro-
cating
grate
Crate
Moving
grate
Recipro-
cating
graC*
Grata,
Enlsslon
control
ayscea
E.S.P.
E.S.P.
E.S.P.
E.S.P.
Wet
scrubber
K.S.P. and
Multi-
cyclone
Status
UC 197S
0? 1971
OP 1972
OP 1970
OP 1974
OP 1967
UC 197S
DSC
rsc
rsc
ss
UC
C Awd.
C Awd.
C N«g.
PDC
FSC
FSC
US
US
US
US
US '
us
*A.C. Air Clasalfler
S. Shredder
«. Hignelic separator.
*UC Under Construction PSC - Feasibility Study Coop lets C Nag. • Contract under Negotiation
0? Operating SS • Eyetm Shakedown In progm* ?DC » Preliminary Deiiga CoaplcU
BM Dealgn Study Couplet* C Awl. • Contract Awarded US • Under Study.
-------
commercial refuse and to provide steam at 652 psig and 785 F to 825 F
to a nearby General Electric Plant. Operation is 7 days/week and
24 hours/day with a minimum of 2 billion pounds of steam to be delivered
annually. Refuse is burned on a Wheelabrator/Von Roll moving grate sys-
tem. Combustion temperatures are in the range 1000 to 1800°F. Cooled
reaction gases pass through two Wheelabrator-Lurgi electrostatic pre-
cipitators which are designed to reduce particulate emissions to 0.025
grains/scf. Fly ash is passed through a magnetic separator and sent to
landfills. Quench water is discharged in wet ash or evaporated. Blow-
down water is almost entirely consumed by transferring it to quench tanks.
There is not, as yet, any specific information on air emissions for waste
to energy facilities. However, there is roughly a 1 to 1 correspondence
between the emissions from incineration only and waste to energy incinera-
tion processes. Consequently, although air emissions from waste to
energy facilities are not known, they can be deduced from the known prop-
erties for normal incineration facilities. Tables 106 and 107 list
the air emissions to be expected from waste to energy steam-producing
facilities. Because refuse is a low sulfur fuel, typically of ~0.1 per-
cent sulfur content, no S0? scrubbing is performed on the stack gases.
£ C*^
NO emissions ar?. expected to be below 0.5 pounds per 10 Btu heat input. ''
X
Table 107 demonstrates the change in trace element emissions to be ex-
pected from the use of different control equipment. Using the emission
factors of Tables 106 and 107, pollutant loadings from the firing of MR
for the production of steam for industrial purposes can be calculated,
and these are given in Table 108.
The extent of potentially hazardous substances from waste to energy in-
cineration processes has not yet been measured. Odors arising from the
refuse are destroyed at the incineration temperatures used. Of special
concern in waste to energy processes is the occurrence of pollutants not
normally found in conventional energy generating processes. For example,
the following compounds have all been found in incinerator stack gases:
288
-------
Table 106. AIR EMISSIONS FROM REFUSE INCINERATORS
3'58
Pollutant
1.
2.
3.
4.
5.
6.
7.
8.
9.
Mineral particulate
Ib/ton of refuse
Ib/ton of ash (ex. glass, metal)
Combustible particulate
Ib/ton of refuse
Ib/ton of volatile carbon
i
Carbon monoxide
Ib/ton of refuse
Nitrogen oxides (as NC^)
Ib/ton of refuse
Ib/MM Btu
Hydrocarbons
Ib/ton of refuse
Polynuclear hydrocarbons
Ib/ton of refuse x 1(P
Ib/ton of volatile carbon x 1(P
Sulfur oxides (as 802)
Ib/ton of refuse
Ib/ton of sulfur in refuse
Hydrogen chloride
Ib/ton of refuse
Ib/ton of PVC resin
Volatile metals (as lead)
Ib/ton of refuse
Ib/ton of metals in refuse
Furnace type and average capacity
Rocking
grate,
350 tons/day
13.6
250
2.70
14
.1.
20.59
3.53
0.40
1.58
2.94
15.2
3.94
4000
0.99
1180
0.032
0.4
Reciprocating
grate,
350 tons /day
28.1
517
2.70
14
20.59
3.53
0.40
1.58
2.94
15.2
3.94
4000
0.99
1180
0.032
0.4
Traveling
grate,
350 tons/day
12.8
236
2.70
14
20.59
3.53
0.40
1.58
2.94
15.2
3.94
4000
0.99
1180
0.032
0.4
Suspension
burning ,
300 tons/day
48.9
900
1.93
10
14.72
3.44
0.39
1.13
2.10
10.8
3.94
4000
0.99
1180
0.032
0.4
N>
00
Variations in composition of refuse may produce different values.
-------
Table 107. EMISSION FACTORS FOR MUNICIPAL INCINERATORS
59
Element
Be
Cd
Mn
Hg
Ni
V
Pb
Sample conditions
Uncontrolled
After ESP
Uncontrolled
After wet scrubber
Uncontrolled
After ESP
Uncontrolled
After wet scrubber
Uncontrolled
Uncontrolled
Emission factor,
Ib/ton refuse burned
0.00003
0.00003
0.003
0.0008
0.03
0.007
0.001
0.003
0.001
0.032
Table 108. TOTAL STACK EMISSIONS FOR BURNING MUNICIPAL REFUSE*
2.2.40.0.0 Refuse
Tons
fuelb
1.88 x 106
io12c
Btu/yr
15
103 ton/yr
d
Particulate
1.3
so2
3.7
NOX
3.1
CO
17.6
HC
1.35
2.2.40.0.0 Refuse
ton/year
Polynuclear
hydrocarbons
0.003
HC1
0.93
Be
0.03
Cd
2.82
Mn
6.58
Hg
0.94
Ni
2.82
Pb
30.08
V
0.94
Calculated from information supplied in Tables 106 and 107.
The plants included in this category are (see Table 105): Saugus, Ma.; Braintree,
Ma.; Harrisburg, Pa.; Chicago, II.; Nashville, Tn.; and Norfolk, Va.
^
Assuming 1 pound refuse = 4000 Btu, and 8760 operating hours at capacity.
Assuming 95 percent particulate removal efficiency.
290
-------
formic, acetic, palraetic, stearic and oelic acids; methyl and ethyl ace-
tate and ethyl stearate; formaldehyde and acetaldehyde; hydrocarbons; and
phenols. However, incineration of municipal refuse in stationary sources
is not now judged to be a significant contributor to total air hydrocarbon
emissions.
Water pollutants from waste to energy facilities, using the Saugus Plant
as a benchmark, are expected to be minimal. This is because the water
handling system is essentially self-contained with make-up water being
supplied from the municipal water supply, and only small amounts of cool-
ing water are needed for process steam systems. Leachates from the wet
ash should pose the only threat to water quality. However, the use of
landfill liners should alleviate any problem that may exist. Typical
refuse ash composition is listed in Table 109. Reductions in volume
of municipal refuse by as much as 90 percent will minimize most solid
waste disposal problems associated with the volume of the waste.
Table 109- AIR CLASSIFIED REFUSE ASH COMPOSITION
(WEIGHT PERCENT)
60
P 0
2 5
Si02
Al O
^23
TiO-
Fe-0,
2 3
CaO
MgO
so3
K20
Na2°
Sn02
CuO
ZnO
PbO
Average
1.43
49.90
11.38
0.87
7.89
12.21
1.29
1.48
1.57
8.82
0.05
0.32
0.41
0.19
Maximum
2.04
58.10
26.90
1.52
22.19
15.80
2.32
3.75
2.91
19.20
0.10
1.74
2.25
0.73
Minimum
0.99
39.90
6.10
0.07
3.03
8.51
0.22
0.54
0.92
3.11
0.02
0.08
0.09
0.04
291
-------
The Supplemental Firing of Industrial Wastes
At present, the only large scale practitioners of supplementary firing of
liquid fuels are petroleum refineries. Liquid and sludge petroleum
refinery wastes are mixed with either oil or gas and fired in conventional
or modified boilers mainly for process steam generation and heat. Com-
plete inventories of the facilities utilizing the supplemental firing of
industrial wastes are not available. However, an industry survey has
recently been made and, while not complete, can serve as a lower limit
of the pollutant loadings to be expected.
are listed in Table 110.
61
These pollutant loadings
Table 110.
TOTAL STACK EMISSIONS FOR BURNING WASTE FUELS IN
PETROLEUM REFINERIES
2.2.43.0.0 Industrial wastea
Tons
fuel
KA
10"
Btu/yr
of waste fuel
3.8
Emissions, 10^ ton/yr
Particulate
0.83
S02
15.13
KOX
12.8
CO
0.36
HC
-
All calculations based on information given in reference 61.
In interpreting the data presented in Table 110 it should be noted that
the emissions reported are for burning gas or oil and the supplementary
waste fuel. Generally, this mixture is -70/30 on a li&at basis.
Wood Wastes as a Fuel
Pulp and paper industries are the main users of wood wastes for supple-
mentary fuel. Secondary users of wood wastes are the logging and wood
manufacturing industries that burn bark and wood wastes in specially
62
designed boilers.
Table 111 lists the stack emissions from wood wastes. The consumption of
3
wood was calculated from the emissions reported in the 1972 NEDS Report.
292
-------
The consumption figure was then updated using a growth factor of 0.012
for 1975. The updated consumption data were used to calculate the emis-
sions. The emission factors were taken from reference 28.
Table 111. TOTAL STACK EMISSIONS FOR BURNING WOOD WASTES
2.2.42.0.0 Wood/Bark
Tons
fuel,
106 ton/yr
163
10"
Btu/yr
-
Emissions, 10^ ton/yr
Particulate
210
SO 2
18
NOX
140
CO
44
HC
31
293
-------
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12. Natural Gas Production and Consumption, 1973. Mineral Industry
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294
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14. Energy Perspectives. U.S. Department of the Interior. February
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19. McGowin, C. R. Stationary Internal Combustion Engines in the
United States. Shell Development Company. April 1973.
20. Barrett, R. E. et al. Field Investigation of Emissions From
Combustion Equipment for Space Heating. U.S. Environmental Pro-
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Intermediate-Size Fossil Fuel Combustion Equipment. U.S. Environ-
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July 1971.
22. Paddock, R. E. and D. C. McMann. Distributions of Industrial and
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Publication No. EPA-650/2-75-021. February 1975.
23. C-E Bark Burning Boilers. Combustion Engineering Inc. Windsor,
Connecticut.
24. Flood, B. W. Emissions from Bagasse Fired Boilers. Clean Air.
February 1974.
25. Eller, W. M. Power Generation in Cane Sugar Factories. Combustion.
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26. Liabilities into Assets. Environmental Science and Technology.
March 1974.
27. Plant Design Report. Power. November 1973.
28. Compilation of Air Pollutant Emission Factors. U.S. Environmental
Protection Agency Pub. AP-42. Research Triangle Park, N. C.
April 1973.
295
-------
29. Steam Plant Air and Water Quality Control Data Summary Report for
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Washington, D.C. June 1974.
30. Westram, Leonard. Personal Communication. U.S. Bureau of Mines.
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31. Shelton, E. M. Burner Fuel Oils, 1974. Bureau of Mines. U.S.
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32. Hangebrauck, R. P., D. J. von Lehmden, and J. E. Meeker. Sources
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33. Magee, E. M., H. F. Hall, and G. M. Vaige, Jr. Potential Pollutants
in Fossil Fuels. U.S. EPA Report No. R2-73-249. Prepared by ESSO
Research and Engineering Company, Linden, N. J. June 1973.
34. Zubovic, D. P., et al. Distribution of Minor Elements in Some Coals
in the Western and Southwestern Regions of the Interior Coal
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35. Kessler, T., A. G. Sharrey, and R. A. Friedel. Analysis of Trace
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36. Ruch, R. R., H. I. Glusroter, and N. F. Shimp. Occurrence and
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Interim Report. Illinois State Geological Survey. April 1973.
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Determination of Trace Elements in Coal, Fly Ash, Fuel Oil and
Gasoline - A Preliminary Comparison of Selected Analytical Techniques.
Analytical Chemistry. 46:239. February 1974.
38. von Lehmden, D. J. Personal Communication. June 1975.
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Units at Big Brown Steam Electric Station. Proceedings: Bureau of
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May 1973.
40. Validation of Neutron Activation Technique for Trace Elements
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August 1973. API 4188.
296
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41. Davis, D. D., G. W. Sonal et al. Study of the Emissions from Major
Air Pollution Sources and Their Atmospheric Interactions. University
of Maryland, Department of Chemistry Progress Report. November 1
1972 - October 31, 1973.
42. Anderson, D. Emission Factors for Trace Substances. U.S. Environ-
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Reuse Program - Residue Management. Draft Final Report. GCA Cor-
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44. Bartz, D. R. et al. Control of Oxides of Nitrogen From Stationary
Sources in the South Coast Air Basins of California. KVB Engineering,
Inc. , for California Air Resources Board, Sacramento, California.
Report No. PB-237-688. September 1974.
45. Stratton, C. L.- and G. F. Lee. Cooling Towers and Water Quality.
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Environmental Age. Environmental Science and Technology. 5:(1)
30-38. January 1971.
47. Feedwater Quality in Modern Industrial Boilers - A Concensus of
Profile Current Operating Practices. Preliminary Report. Indus-
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Water in. Thermal Power Systems. April 1975.
48. Packaged Firetube Boiler Engineering Manual. First Edition.
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American Boiler Manufacturers Association. 1971.
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New York. June 1964.
50. National Pollution Discharge Elimination System Permit Program.
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Publication No. 1294. 1966.
53. Blackwood, T. R. and A. W. Wachter. Source Assessment of Coal
Storage Piles. U.S. Environmental Protection Agency Contract
No. 68-02-1874.
297
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54. Development of Emission Factors for Fugitive Dust Sources. Midwest
Research Institute. U.S. Environmental Protection Agency. Publi-
cation No. EPA-450/3-74-037. 1974.
55. Huang, C. J. and C. Dalton. Energy Recovery from Solid Waste.
Volume 2, Technical Report. Prepared by University of Houston
for Lyndon B. Johnson Space Center, National Aeronautics and Space
Administration. NASA Report No. CR-2526. April 1975.
56. MacAdam, W. K. Design and Pollution Control Features of the Saugus,
Massachusetts, Steam Generating Refuse-Energy Plant. (Presented at
the 67th Annual Meeting of the Air Pollution Control Association.
Denver, Colorado. June 9-13, 1974.)
57. Control of Environmental Impacts from Advanced Energy Sources.
Prepared by Stanford Research Institute for U.S. Environmental
Protection Agency. Publication No. EPA-600/2-74-002. March 1974.
58. Systems Study of Air Pollution from Municipal Incineration.
Arthur D. Little, Inc. Report to National Air Pollution Control
Administration, U.S. Department of Health, Education and Welfare.
Contract No. CPA-22-69-23. March 1970.
59. Anderson, David. Emission Factors for Trace Substances. U.S. En-
vironmental Protection Agency. Publication No. EPA-450/2-73-001
December 1973.
60. Klumb, David L. Solid Waste Prototype for Recovery of Utility Fuel
and Other Resources. Union Electric Company. May 1974.
61. Mather, Gopal K. Identification and Characterization of the Use
of Mixed Conventional and Waste Fuels. M. W. Ke.1 log Company, Re-
search and Development, Houston, Texas. Prepared for the U.S. En-
vironmental Protection Agency. Publication No. EPA-650/2-75-017.
February 1975.
62. Hendricksen, E. R. et al. Control of Atmospheric Emissions in
the Wood Pulping Industry. Volumes I, II, and III. Report No.
PB 190 351. March 15, 1970.
298
-------
SECTION IV
COMMERCIAL/INSTITUTIONAL COMBUSTION SOURCES
The commercial/institutional sector consists of all activities not
classified as electric utility, mining, manufacturing, transportation,
or residential. It includes farms, wholesale and retail trade, office
buildings, hotels, restaurants, hospitals, schools, museums and govern-
ment facilities. -Fuel consumed by the commercial/institutional sector
during 1973 was used for space heating (82 percent), water heating
(12 percent), cooking (3 percent), and air conditioning (3 percent).
Essentially all the coal and oil was used for space heating. Natural
gas was used for space heating (66 percent), water heating (23 percent),
cooking (6 percent), and air conditioning (5 percent). Estimated 1973
fuel consumption by the commercial/institutional sector (external com-
bustion) is presented in Table 112: approximately 3 percent of the com-
2-6
mercial fuel was coal while 44 percent was oil and 53 percent was gas.
The greatest commercial/institutional application of internal combustion
engines is for the pumping of municipal water and sewage. Internal com-
bustion engines are also used commercially to power pumps, compressors,
and emergency power generators.
COMBUSTION EQUIPMENT AND FUEL USAGE
Commercial/institutional combustion units range in size from 0.3 x 10
Btu/hr to units greater than 100 x 10 Btu/hr. The biggest units are
used at large hospitals, office complexes, and government facilities
such as military bases. Past studies have limited the term commercial
299
-------
ft 78
to boilers in the size range 0.3 to 10 x 10 Btu/hr. ' However, fuel
use data are only available for the total commercial/institutional sector,
so GCA attempted to define the emissions and boilers associated with the
available fuel use data. All boilers in the size range 0.3 to 10 x 10
Btu/hr were assumed to be commercial boilers. The commercial/institu-
tional boiler population in the size range above 10 x 10 Btu/hr was
estimated from NEDS data. Since only boilers emitting more than 100
tons/year of one of the five criteria pollutants are included in the
NEDS system, the minimum size of boilers included depends on the fuel
used and the average yearly load factor. In practice, some smaller
boilers are included, and the NEDS system covers 40 percent of the coal,
5 percent of the oil, and 8 percent of the gas burned by sources classi-
9
fied as commercial/institutional boilers.
Table 112. COMMERCIAL/INSTITUTIONAL FOSSIL FUEL CONSUMPTION, 1973
.
3.0.00.0.0
3.1.10.0.0
3.1.11.0.0
3.1.12.0.0
3.1.13.0.0
3.1.20.0.0
3.1.21.0.0
3.1.22.0.0
3.1.30.0.0
Commercial/ Institutional
Coal
Bituminous
Anthracite0
Lignite
Petroleum
Residual oild
Distillate oil6
Gasf
Total -
all uses,
101 Btu/yr
5,436
156
100
55
1
2,379
1,269
1,110
2,901
Space
heating,
1012 Btu/yr
4,449
156
100
55
1
2,379
1,269
1,110
1,914
External combustion only.
b22.4 x 106 Btu/ton.
c 6
26.0 x 10 Btu/ton.
146,000 Btu/gal.
e!40,000 Btu/gal.
f 3
Includes 8.5 percent LPG — 1,020 Btu/ft (gas), 90,000 Btu/gal
(liquid).
300
-------
The number, capacity, and fuel consumption of the commercial boilers in-
cluded in the NEDS system are summarized in Table 113. We estimated fuel
use by commercial/institutional boilers as a function of size by assuming
that the boilers above 10 x 10 Btu/hr included in the NEDS system repre-
sented all the coal-fired boilers, one-half the oil-fired boilers, and one-
quarter of the gas-fired boilers (see Table 114) in that size range.
Commercial/institutional sector fuel use by combustion system category is
presented in Table 115. Bituminous coal-fired commercial boilers above
10 x 10 Btu/hr were estimated to be 2 percent pulverized wet and 35 per-
cent pulverized dry, based on our recent survey of NEDS data. All other
bituminous coal-fired boilers are stokers. Anthracite coal is usually
burned only in stokers; the high ignition temperature of anthracite does
not allow the employment of spreader stokers. Only a very small amount
of lignite is burned by commercial users, probably in small stokers. The
amount of residual oil burned in tangentially-fired boilers was calculated
by assuming that boilers above 100 x 10 Btu/hr were similar to utility
boilers. Because only a small fraction of oil utilized by the commercial/
institutional sector is burned in boilers above 100 x 10 Btu/hr, less
than 1 percent is burned in tangentially-fired units. A similar analysis
of gas-fired boilers indicated that less than 4 percent of gas is burned
in tangentially-fired units. The figure for wood/bark combustion repre-
sents data on file in the NEDS system and may repres2nt only a very small
fraction of the wood burned by the commercial/institutional sector. Inter-
nal combustion fuel use was estimated by updating municipal internal com-
bustion fuel use data from 1973. The fuel used is 50 percent oil —
50 percent gas.
EMISSION SOURCES
Because oil and gas are clean fuels relative to coal, and because of the
small boiler sizes considered, many pollutant waste streams appear to be
301
-------
Table 113. COMMERCIAL/INSTITUTIONAL BOILERS INCLUDED IN THE
NEDS SYSTEM9
Fuel
Coal
Oil
Gas
Size,
106 Btu/hr
1-10
10-100
> 100
1-10
10-100
> 100
1-10
10-100
> 100
Number
249
355
40
893
779
107
349
288
72
Capacity,
106 btu/hr
1,226
14,186
7,617
2,994
28,080
25,836
732
7,000
27,228
Fuel consumption,
1012 Btu/yr
6.2
37.9
18.8
18.9
70.8
27.4
34.7
38.7
83.8
Table 114. ESTIMATED COMMERCIAL/INSTITUTIONAL FUEL CONSUMPTION
BY BOILERS AS A FUNCTION OF SIZE
Fuel
Coal
Oil
Gas
Size,
10b Btu/hr
0.3-10
10-100
> 100
0.3-10
10-100
> 100
0.3-10
10-100
> 100
Number
40,000
355
40
882,000
1,560
220
578,000
1,160
280
Capacity,
106 Btu/hr
53,800b
14,200
7,600
l,090,000b
56,000
52,000
778,000b
28,000
108,000
Fuel consumption,
1012 Btu/yr
99
38
19
2,184
141
54
1,431
144
339
«a f
The total number of boilers in the size range 0.3-10 x 10
Btu/hr has been estimated as 91,000 to 3,100,000.7 Commercial/
institutional and industrial oil-fired boilers are estimated to
O
number 1,100,000. Industrial boilers represent a compara-
tively small number. GCA estimated 1,500,000 boilers in the
range 0.3-10 x 10° Btu/hr. The number was distributed based on
the fuel burned. Data for boilers above 10 x 10^ Btu/hr are
discussed in the text.
Based on an average yearly load factor of 21 percent.^
302
-------
Table 115. COMMERCIAL/INSTITUTIONAL FUEL USE, 1973*
3.0.00.0.0
3.1.00.0.0
3.1.10.0.0
3.1.11.0.0
3.1.11.1.0
3.1.11.2.0
3.1.11.4.0
3.1.12.0.0
3.1.12.4.0
3.1.12.6.0
3.1.13.0.0
3.1.13.4.0
3.1.13.6.0
3.1.20.0.0
3.1.21.0.0
3.1.21.0.1'
3.1.21.0.2
3.1.22.0.0
3.1.22.0.1
3.1.22.0.2
3.1.30.0.0
3.1.30.0.1
3.1.30.0.2
3.1.40.0.0
3.1.42.0.0
3.2.00.0.0
3.2.20.0.0
3.2.30.0.0
Commercial/ Institutional
External Combustion
Coal
Bituminous^
Pulverized Dry
Pulverized Wet
All Stokers
Anthracite0
All Stokers
Spreader Stokers
Lignited
All Stokers
Spreader Stokers
Petroleum
Residual Oil6
Tangential Firing
All Other
Distillate Oilf
Tangential Firing
All Other
GasS
Tangential Firing
All Other
Refuse
Wood/ Bar kh
Internal Combustion
Petroleum
Gas
Fuel use,
1012 Btu
4,500
4,450
y
156
100
20
1
79
55
55
0
1
1
0
2,379
1,269
10
1,259
»
1,110
11
1,099
1,914
32
1,832
1
1
50
25
25
aPrimarily space heating, except internal combustion
which is primarily water pumping by municipalities
and possibly a small amount of electric generation.
b22.4 x 106 Btu/ton.
C26.0 x 106 Btu/ton.
16.0 x 10 Btu/ton.
e!46,000 Btu/gal.
f140,000 Btu/gal.
gl,022 Btu/ft3.
h!0.0 x 106 Btu/ton.
303
-------
inconsequential and in most cases nonexistent; e.g., cooling water dis-
charge, water treatment wastes, blowdown, etc. Solid waste emissions
resulting from ash handling and coal storage operations are also minor,
due to the small amount of coal used by the commercial/institutional
sector. The principal sources of emissions are from the combustion
stack. However, even though these emissions are uncontrolled, they are
relatively minor in comparison with the electric utility and industrial
combustion areas.
EXTERNAL COMBUSTION SYSTEM EMISSIONS
Total nationwide emission estimates of particulates (including <3 micron
diameter particulates), sulfur oxides, nitrogen oxides, hydrocarbons,
carbon monoxide, polycyclic organic matter, and trace elements are pre-
sented in Table 116 for commercial/institutional stationary external
combustion sources. Commercial/institutional external combustion sources
account for 1.0 percent of total particulates, 4.8 percent of sulfur
oxides, 3.2 percent of nitrogen oxides, 0.1 percent of hydrocarbons, and
0.06 percent of carbon monoxide emissions from all man-made sources.
They account for 4.8 percent of total particulates, 6.8 percent of sulfur
oxides, 7.0 percent of nitrogen oxides, 12 percent of hydrocarbons, and
7.3 percent of carbon monoxide emissions from statiorary combustion
sources as determined by this study. The estimates are based on the
EPA-NEDS emission factors listed in Table 117, and on the methods de-
scribed in the notes following Table 116. To obtain state emission
estimates for purposes of assigning priorities to the various combustion
systems, it will be necessary to prorate the nationwide values by multi-
plying by the ratio of the fuel consumption in a state (ton/year) to the
fuel consumption nationwide (ton/year). Fuel consumption estimates by
state are provided in Appendix B. Additional data on trace element
content are provided in Appendix C.
304
-------
Table 116. FLUE GAS EMISSIONS FROM COMMERCIAL/INSTITUTIONAL EXTERNAL COMBUSTION, 1973£
o
in
3.0.00.0.0 Commercial/ Ins t.
3.1.00.0.0 External Combustion
3.1.10.0.0 Coal
3.1.11.0.0 Bituminous15
3.1.11.1.0 Pulverized Dry
3.1.11.2.0 Pulverized Wet
3. 1.11. A. 0 All Stokers
3.1.12.0.0 Anthracite0
3.1.12.4.0 All Stokers
3.1.12.6.0 Spreader Stokers
3.1.13.0.0 Lignite
3.1.13.4.0 All Stokers
3.1.13.6.0 Spreader Stokers
3.1.20.0.0 Petroleum
3.1.21.0.0 Residual Oild
3.1.21.0.1 Tangential Firing
3.1.21.0.2 All Other
3.1.22.0.0 Distillate Oil6
3.1.22.0.1 Tangential Firing
3.1.22.0.2 All Other
3.1.30.0.0 Gasf
3.1.30.0.1 Tangential Firing
3.1.30.0.2 All Other
3.1.42.0.0 Wood/Bark8
Particulates ,
103 tons/yr
Total
350"
340
0.70
0.50
0.60
4.8
50
21
21
0
0
0
0
150
92
0.73
91
59
0.59
58
9.1
0.39
8.7
1.4
< 3pp
150
150
4.4
3.0
2.0
0.08
0.97
0.41
0.41
0
0
0
0
140
83
0.66
82
53
0.53
52
8.2
0.35
7.9
Gases,
103 tons/yr
sox
1,500
1,500
230
210
4'2
2.1
170
20
20
0
0
0
0
1,300
1,200
9.5
1,200
130
1.3
130
0.56
0.024
0.54
0.10
NOV
ft.
800
770
30
14
2.8
0.14
11
16
16
0
0
0
0
630
320
1.3
320
310
1.6
310
110
4.7
105
0.69
HC
43
41
7.0
6.8
1.3
0.067
5.4
0.21
0.21
0
0
0
0
24
12
0.095
12
12
0.12
12
7.2
0.31
6.9
2.5
CO
83
78
25
23
4.6
0.023
18
' 2.1
2.1
0
0
0
0
32
16
0.13
16
16
0.16
16
19
0.81
18
2.1
Organics,
tons/yr
BSD
20,000
20,000
590
380
76
. 3.8
300
210
210
0
0
0
0
15,000
7,500
70
7,400
7,500
80
7,400
4,000
J.80
3,800
PPOM
6.8
6.8
3.5
2.3
0.44
0.022
1.8
1.2
1.2
0
0
0
0
2.0
1.0
0.008
1.0
1.0
0.01
1.0
1.3
0.056
1.2
BaP
1.7
1.7
0.86
0.56
0.11
Q. 0055
0.44
0.30
0.30
0
0
0
0
0.51
0.26
0.0021
0.26
0.25
0.0025
0.25
0.32
0.014
0.31
-------
Table 116 (continued).
FLUE GAS EMISSIONS FROM COMMERCIAL/INSTITUTIONAL
EXTERNAL COMBUSTION, 1973a
3.0.00.0.0 Conmercial/Inst.
3.1.00.0.0 External Combustion
3.1.10.0.0 Coalj
3.1.11.0.0 Bituminousk
3.1.11.1.0 Pulverized Dry
3.1.11.2.0 Pulverized Wet
3. 1.11. A. 0 All Stokers
3.1.12.0.0 Anthracite1
3.1.12.4.0 All Stokers
3.1.12.6.0 Spreader Stokers
3.1.13.0.0 Lignite
3.1.13.4.0 All Stokers
3.1.13.6.0 Spreader Stokers
3.1.20.0.0 Petroleum
3.1.21.0.0 .Residual Oil1"
3.1.21.0.1 Tangential Firing
3.1.21.0.2 All Other
3.1.22.0.0 Distillate Oiln
3.1.22.0.1 Tangential Firing
3.1.22.0.2 All Other
3.1.30.0.0 Gas£
3.1.30.0.1 Tangential Firing
3.1.30.0.2 All Other
3.1.42.0.0 Wood/Bark8
Trace elements,
tons/yr
Sb
1.8
1.8
0.55
0.48
0.37
0.015
0.09
0.011
0.011
0
0
0
0
1.2
1.2
0.0095
1.2
ND '
ND
ND
As
39
39
28
27
21
0.85
5.0
1.1
1.1
0
0
0
0
11
9.4
0.075
9.3
1.3
0.013
1.3
•
Ba
60
60
40
34
26
1.0
6.6
6.1
6.1
0
0
0
0
20
20
0.16
20
ND
ND
ND
Be
54
54
2.6
2.3
1.8
0.072
0.43
0.31
0.31
0
0
0
0
2.8
2.8
0.022
2.8
Bi
0.96
0.96
0.95
0.95
0.73
0.029
0.19
0.011
0.011
0
0
0
0
B
54
54
50
50
39
1.6
9.6
' 0.11
0.11
0
0
0
0
3.3
3.3
0.026
3.3
Br
160
160
70
68
13
0.68
54
2.2
2.2
0
0
0
0
89
5.3
0.0053
5.3
84
0.83
83
Cd
59
59
0.41
0.40
0.31
0.012
0.016
0.011
0.011
0
0
0
0
59
59
0.47
58
ND
ND
ND
Cl
10,000
10,000
9,900
6,700
1,300
68
5,400
3,200
3,200
0
0
0
0
500
500
5.0
500
Cr
79
79
26
13
10
0.42
2.6
13
13
0
0
0
0
53
53
0.43
53
ND
ND
ND
-------
Table 116 (continued).
FLUE GAS EMISSIONS FROM COMMERCIAL/INSTITUTIONAL
EXTERNAL COMBUSTION, 1973a
3.0.00.0.0 Commercial/Inst.
3.1.00.0.0 External Combustion
3.1.10.0.0 CoalJ
3.1.11.0.0 Bituminousk
3.1.11.1.0 Pulverized Dry
3.1.11.2.0 Pulverized Wet
3.1.11.4.0 All Stokers
3.1.12.0.0 Anthracite1
3.1.12.4.0 All Stokers
3.1.12.6.0 Spreader Stokers
3.1.13.0.0 Lignite
3.1.13.4.0 All Stokers
3.1.13.6.0 Spreader Stokers
3.1.20.0.0 Petroleum
3.1.21.0.0 Residual Oil™
3.1.21.0.1 Tangential Firing
3.1.21.0.2 All Other
3.1.22.0.0 Distillate Oiln
3.1.22.0.1 Tangential Firing
3.1.22.0.2 All Other
3.1.30.0.0 Gas0
3.1.30.0.1 Tangential Firing
3.1.30.0.2 All Other
3.1.42.0.0 Wood/Bark8
Trace elements,
tons/yr
Co
79
79
13
3.5
2.7
0.11
0.66
9.6
9.6
0
0
0
0
66
66
0.52
65
Cu
330
330
20
12
9.4
0.36
2.3
7.9
7.9
0
0
0
0
310
310
2.5
310-
0.66
0.0065
0.65
F
700
700
700
360
59
2.3
100
340
340
0
0
0
0
0.12
0.12
0.0012
0.12
Fe
4,100
4,100
4,100
3,400
2,600
100
660
710
710
0
0
0
0
220
220
1.7
220
Pb
19
19
9.5
8.6
6.6
0.26
1.7
0.94
0.94
0
0
0
0
1.2
1.2
0.0095
1.2
Mn
5.0
5.0
45
44
34
1.3
8.6
1.4
1.4
0
0
0
0
4.7
4.7
0.037
4.7
0.17
0.0017
0.17
Hg
1.7
1.7
1.1
0.57
0.11
0.0057
0.46
0.52
0.52
0
0
0
0
0.61
0.61
0.0061
0.61
ND
ND
ND
Mo
72
72
4.5
3.4
2.6
0.10
0.66
1.1
1.1
0
0
0
0
67
67
0.52
66
Ni
1,500
1,500
18
13
10
0.42
2.6
5.3
5.3
0
0
0
0
1,500
1,500
12
1,500
ND
ND
ND
Se
13.4
13.4
9.1
8.8
1.7
0.092
7..0
0.29
0.29
0
0
0
0
4.3
4.3
0.043
4.3
ND
ND
ND
-------
Table 116 (continued). FLUE GAS
EXTERNAL
EMISSIONS FROM COMMERCIAL/INSTITUTIONAL
COMBUSTION, 1973a
o
CO
3.0.00.0.0 Commercial/Inst.
3.1.00.0.0 External Combustion
3.1.10.0.0 CoalJ
3.1.11.0.0 Bituminousk
3.1.11.1.0 Pulverized Dry
3.1,11.2.0 Pulverized Wet
3,1.11.4.0 All Stokers
3.1.12.0.0 Anthracite1
3.1.12.4.0 All Stokers
3.1.12.6.0 Spreader Stokers
3.1.13.0.0 Lignite
3.1.13.4.0 All Stokers
3.1.13.6.0 Spreader Stokers
3.1.20.0.0 Petroleum
3.1.21.0.0 Residual "Oil"1
3.1.21.0.1 Tangential Firing
3.1.21.0.2 All Other
3.1,22.0.0 Distillate Oiln
3.1.22.0.1 Tangential Firing
3.1.22.0.2 All Other
3.1.30.0.0 Gas0
3.1.30.0.1 Tangential Firing
3.1.30.0.2 All Other
3.1.42.0.0 Wood/Bark8
Trace elements,
ton/yr
Te
- 0.31
0.31
0.31
0.30
0.23
0.0091
0.056
0.011
0.011
0
0
0
0
'
,
Tl
0.12
0.12
0.12
0.095
0.073
0.0029
0.019
0.011
0.011
0
0
0
0
Sn
16
16
1.0
0.90
0.70
0.027
0.17
0.11
0.11
0
0
0
0
15
15
0.15
15
Ti
880
880
620
560
430
18
110
63
63
0
0
0
0
160
160
1.3
160
U
55
55
14
14
11
0.44
2.7
0.29
0.29
0
0
0
0
41
41
0.32
41
V
1,700
1,700
26
26
20
0.78
. 4.7
1.4
1.4
0
0
0
0
1,700
1,700
13
1,700
ND
ND
ND
Zn
30
30
24
21
16
0.62
3.9
3.1
3.1
0
0
0
0
5.6
5.6
0.044
5.6
ND
ND
ND
Zr
49
49
49
44
34
1.4
8.6
5.0
5.0
0
0
0
0
-------
Table 116 (continued). FLUE GAS EMISSIONS FROM COMMERCIAL /INSTITUTIONAL EXTERNAL COMBUSTION, 1973a
Values in the table represent total estimated emissions to the atmosphere from conventional sta-
tionary combustion sources in the United States. An entry of "ND" signifies that a trace element
has not been detected when measured, and an entry left blank signifies that no information is
available. The emission factors used in this table are given in Table 117.
The consumption of bituminous coal was determined by taking the data from Table II, page 39, of .
reference 4 under the column headed "Retail Dealers" and subtracting the calculated residential
consumption. The difference xjas believed to be the consumption by commercial/ institutional users.
The ash content was taken to be 13.8 percent by weight from Table 1-A, page 1, of reference 13.
The sulfur content was taken to be 2.4 percent from Table 1-A, page 1, of reference 13.
Q
The consumption of anthracite was determined by subtracting the residential consumption from the
consumption data given in reference 6. The ash content was assumed to be 10 percent; the sulfur.
content 0.5 percent.
The consumption of residual oil was taken from Tables 6 and 12 of reference 2. The sulfur content
was taken from reference 14 for 1973 oils and averaged 1.87 percent by weight.
Q
The consumption of distillate oil was determined by subtracting the residential consumption from
reference 2. The sulfur content was taken from reference 14 for 1973 oils and averaged 0.225 per-
cent by weight.
The consumption of gas by conventional stationary combustion systems was estimated to be 65 per-
cent of the value, in reference 3, for commercial and other consumers in 1973.
consumption of wood was updated from the emissions in the 1972 NEDS report.
The emissions of BaP and BSO from all fuels were calculated from emission factors in reference 15.
The emissions of particulate polycyclic organic matter (PPOM) from coal were based on a summation
of emission factors for PYRENE, BENZO(a)PYRENE, BENZO(e)PYRENE, PERYLENE, BENZO(ghi)PERYLENE,
ANTHANTHRENE , CORONENE, ANTHRACENE, PHENANTHRENE , AND FLUORANTHENE . PPOM emissions from oil and
gas were calculated by assuming the same ratio to BaP as in the case of coal. Emission factors
were specific to intermediate size combustion equipment. No data were found on emissions of
polyhalogenated biphenyls from commercial/ institutional systems.
-------
Table 116 (continued). FLUE GAS EMISSIONS FROM COMMERCIAL/INSTITUTIONAL EXTERNAL COMBUSTION, 1973a
The amount of each trace element, i, emitted to the atmosphere was calculated as follows:
(1) The amount of i in the fuel, A., was
A± - C± x F±
where C. = concentration of i in the fuel, ppm
F. = yearly consumption of fuel, tons/year.
If A^ was calculated on a regional basis, results were summed to the national level.
(2) The amount emitted to the atmosphere, E , was
co
o E = A. x f.
where f = estimated fraction of i emitted to the atmosphere.
For the coal-fired pulverized dry bottom units f^ = 0.85, for pulverized wet bottom
units f^ - 0.65, and for stokers f^ = 0.05. Exceptions are Br, Cl, and F for which
f.£ = 1.0, Hg for which f± = 0.90, and Se for which f± = 0.70. For oil fi = 1.0.
•^Data for coal were available for each of the coal-producing regions defined by the U.S. Geological
Survey. Sources of trace element concentration data were publications by Magee,^-" Zubovic,^
Kessler,18 Ruch,19 and von Lehmden.20'21
kFor each coal-producing region, concentrations of As, Ba, Be, B, Cr, Co, Cu, F, Pb, Mn, Hg, Mo,
Ni, Sn, U, V, and Zn in bituminous coal were calculated using reference 16 as a primary source
and reference 17 as a supplementary source. For Cl, Br, and Ti, data from Illinois in reference
19 were used as typical of all coal-producing regions. For Sb, Bi, Cd, Fe, Te, Tl, and Zr, con-
centrations were calculated by using reference 18. For Se, the single concentration cited by
reference 21 was used.
-------
Table 116 (continued). FLUE GAS EMISSIONS FROM COMMERCIAL/INSTITUTIONAL EXTERNAL COMBUSTION, 1973a
For anthracite coal, typical trace element concentrations were taken from reference 18.
For residual oil, trace element concentration data were available for As, Sb, Ba, Br, Cr, Mn, Ni,
V, and Zn from reference 22. For the trace elements Be, B, Cd, Co, F, Fe, Pb, Hg, Mo, Se, Sn, Ti,
and U, reference 21 was used as the primary source and references 20, 23, 24, and 25 as supple-
mentary sources.
For distillate oil, reference 22 reported concentrations for As, Br, Cu, Mn, and Sn and reported
that Sb, Ba, Cd, Cr, Hg, Ni, Se, V, and Zn were not detectable.
Hydrocarbon gases were assumed to be free of trace elements.
For coal, emissions of < 3 micron particles were estimated as 2 percent of the total uncontrolled
particulate emissions. For oil and gas, emissions of < 3 micron particles were estimated to be
90 percent of the particulate emissions.
-------
Table 117. EMISSION FACTORS FOR TABLE 116
3.0.00.0.0 Commercial/ Institutional
3.1.00.0.0 External Combustion
3.1.10.0.0 Coalb
3.1.11.0.0 Bituminous
3.1.11.1.0 Pulverized Dry
3.1.11.2.0 Pulverized Wet
3.1.11.4.0 All Stokers
3.1.12.0.0 Anthracite
3.1.12.4.0 All Stokers
3.1.12.6.0 Spreader Stokers
3.1.13.0.0 Lignite
3.1.13.4.0 All Stokers
3.1.13.6.0 Spreader Stokers
3.1.20.0.0 Petroleum0
3.1.21.0.0 Residual Oil
3.1.21.0.1 Tangential Firing
3.1.21.0.2 All Other
3.1.22.0.0 Distillate Oil
3.1.22.0.1 Tangential Firing
3.1.22.0.2 All Other
3.1.30.0.0 Gasd
3.1.30.0.1 Tangential Firing
3.1.30.0.2 All Other
3.1.42.0.0 Wood/Barkb
Particulates3
Total
NA
NA
NA
17A
13A
2A
2A
2A
2A
X
X
X
X
NA
NA
23
23
NA
15
15
10
10
10
15
Gases*
sox
NA
NA
NA
38S
38S
38S
38S
38S
38S
X
X
X
X
NA
NA
159S
159S
NA
144S
144S
0.6
0.6
0.6
1.5
NOX
NA
NA
NA
18
30
10
10
6
6
X
X
X
X
NA
NA
40
80
NA
40
80
120
120
120
10
HC
NA
NA
NA
0.3
0.3
3
3
0.2
0.2
X
X
X
X
NA
NA
3
3
NA
3
3
8
8
8
36
CO
NA
NA
NA
1
1
6
6
2
2
X
X
X
X
NA
NA
4
4
NA
4
4
20
20
20
31
Abbreviations used in the table have the following meanings:
A = Multiply by weight percent ash
S = Multiply by weight percent sulfur
X = Fuel, consumed in this combustion system is small;
emission is assumed to be negligible
NA = Not applicable.
The emission factors for coal and wood/bark give values in terms of pounds of
pollutant per ton burned.
The emission factors for oil give values in terms of pounds of pollutant per
1000 gallons of oil burned.
The emission factors for gas give values in terms of pounds of pollutant per
10^ cubic feet of gas burned.
312
-------
o
Barrett et al. have conducted an EPA-sponsored field test program to
measure criteria pollutant emissions from commercial oil-fired boilers.
A summary of their test data, and a comparison with NEDS emission factors,
is shown in Table 118. The test values were determined in a field study
of eight distillate oil-fired, five residual oil-fired, and seven gas-
fired units.
Table 118. EMISSION FACTORS: OIL-FIRED AND GAS-FIRED
COMMERCIAL/INSTITUTIONAL BOILERS
(lb/106 Btu)
Fuel
Distillate oil
Residual oil
Natural Gas
Data source
Battelle8
EPA10
Battelle8
EPA10
Battelle8
EPA10
Particulate
0.01
0.1
0.26
0.16
0.006
0.02
S02
0.28
0.3a
2.5
1.9b
0.0006
0.0006
NOX
0.11
0.42
0.55
0.42
0.1
0.1
HC
0.001
0.02
0.002T
0.02
0.004
0.008
CO
0.0035
0.03
0.01
0.03
0.02
0.02
o
0.3 percent sulfur.
2.0 percent sulfur.
INTERNAL COMBUSTION SYSTEM EMISSIONS
The greatest commercial/institutional application of internal combustion
engines is for the pumping of municipal water and sewage. Internal com-
bustion engines are also used commercially to power pumps, compressors,
and emergency power generators. In 1971, 167 million gallons of distil-
late oil and 22.5 billion cubic feet of natural gas were used by the
commercial/institutional internal combustion sector.
Total nationwide emission estimates are presented in Table 119. The
estimates are based on the EPA-NEDS emission factors listed in Table 120,
and on the methods described in the notes following Table 119. Commer-
cial/institutional internal combustion sources account for 0.006 percent
313
-------
Table 119. AIR EMISSIONS FROM COMMERCIAL/INSTITUTIONAL INTERNAL COMBUSTION, 1973£
3. 0. 00. 0. 0 Commercial/Institutional
3.2.00.0.0 Internal Combustionb
3.2.20.0.0 Petroleum
3.2.30.0.0 Gas
Particulates,
10-> tons/yr
Total
350
2.1
2.1
0
<3yc
150
Gases ,
10-^ tons/yr
sox
1,500
2.7
2.7
0.00068
NOX
800
33
25
7.5
HC
43
1.7
1.7
0
CO
83
4.5
4.5
0
Organics,
tons/yr
BSO
20,000
PPOM
6.8
BaP
1.7
to
H*
Table 119 (continued). AIR EMISSIONS FROM COMMERCIAL/INSTITUTIONAL INTERNAL COMBUSTION, 1973C
Trace elements,e
tons/yr
3.0.00.0.0 Commercial/Institutional
3.2.00.0.0 Internal Combustion
3.2.20.0.0 Petroleum
3.2.30.0.0 Gas
Sb
1.8
ND
As
39
0.027
0.027
Ba
60
ND
Be
54
Bi
0.90
B
54
Br
160
1.7
1.7
Cd
59
ND
Cl
10,000
ND
-------
Table 119 (continued). AIR EMISSIONS FROM COMMERCIAL/INSTITUTIONAL INTERNAL COMBUSTION, 1973*
3 . 0. 00. 0. 0 Commercial/ Institutional
3.2.00.0.0 Internal Combustion
3.2.20.0.0 Petroleum
3.2.30.0.0 Gas
Trace elements,6
tons/yr
Cr
170
ND
Co
79
Cu
330
0.014
0.014
F
700.
Fe
4,100
Pb
19
Mn
50
0.0039
0.0039
Hg
1.7
ND
ND
Mo
72
in
Table 119 (continued). AIR EMISSIONS FROM COMMERCIAL/INSTITUTIONAL INTERNAL COMBUSTION, 1973'
Trace elements,e
tons/yr
3 . 0 . 00 . 0 . 0 Commercial/ Institutional
3.2.00.0.0 Internal Combustion
3.2.20.0.0 Petroleum
3.2.30.0.0 Gas
Ni
1,500
ND
ND
Se
13
ND
ND
Te
0.31
Tl
0.12
Sn
16
0.24
0.24
Ti
880
U
55
V
1,700
Zn
30
Zr
49
-------
Table 119 (continued). AIR EMISSIONS FROM COMMERCIAL/INSTITUTIONAL INTERNAL COMBUSTION, 1973&
a
Values In the table represent total estimated emissions to the atmosphere from conventional
stationary combustion sources in the United States. An entry of "ND" signifies that a trace
element has not been detected when measured; and an entry left blank signifies that no infor-
mation is available. All emission factors used in this table are given in Table 120.
Data on fuel consumption and capacities are from reference 11 and are based on 1971 values.
Q
No data were available on emissions of < 3 micron particles.
No data were available for emissions of organics.
/a
Trace element emissions were based on consumption data and calculated trace element contents
of the fuel as listed in Appendix C. These concentrations were multiplied by the fuel consump-
tion to determine the total emissions of trace elements. For distillate oil, reference 22
reported concentrations for As, Br, Cu, Mn, and Sn, and reported that Sb, Ba, Cd, Cr, Hg, Ni,
Se, V, and Zn were not detectable. Hydrocarbon gases were assumed to be free of trace elements.
-------
of total participates, 0.009 percent of sulfur oxides, 0.14 percent of
nitrogen oxides, 0.005 percent of hydrocarbons, and 0.003 percent of car-
bon monoxide emissions from all man-made sources. They account for 0.03
percent of total particulates, 0.01 percent of sulfur oxides, 0.3 percent
of nitrogen oxides, 0.5 percent of hydrocarbons, and 0.4 percent of carbon
monoxide emissions from stationary combustion sources. To obtain state
emission estimates for purposes of assigning priorities to the various com-
bustion systems, it will be necessary to prorate the nationwide values by
multiplying by the ratio of the fuel consumption in a state to the fuel
consumption nationwide. Fuel consumption estimates by state are provided
in Appendix B. Additional data on trace element content are provided in
Appendix C.
Table 120. EMISSION FACTORS FOR TABLE 119
3.0.00.0.0 Coroner cial/Institutional
3.2.00.0.0 Internal Combustion
3.2.20.0.0 Petroleum1*
3.2.30.0.0 Gasc
Particulates2
Total
NA
NA
5
14
Gases3
sox
NA
NA
144S
0.6
NOX
NA
NA
68
413
HC
NA
NA
5.6
42
CO
NA
NA
15.4
115
3Abbreviations used in the table have the following meanings:
S = Multiply by weight percent sulfur
NA = Not applicable; emissions for this combustion system were calcu-
lated as the totql of emissions from the appropriate subsystems.
bThe emission factors for oil give values in terms of pounds of pollutant
per 1000 gallons of oil burned.
CThe emission factors for gas give values in terms of pounds of pollutant
per 10^ cubic feet of gas burned.
ASH HANDLING
It has been assumed that, because of the small size of commercial/institu-
tional boilers, dry collection and landfill disposal will be the only method
of bottom ash handling. Fly ash is not a factor since the application of
317
-------
control equipment is negligible in the commercial area except for some of
the larger institutional boilers. Ash generation and air emission esti-
mates from landfill are given in Table 121. The ash generation values
given in the table are based on the difference between the ash content of
the coal and the ash released to the atmosphere through the stack. The
air emission values are based on the application of an emission factor of
1 Ib/ton of ash collected. Solid waste pollutants resulting from leach-
ates from landfill operations can be estimated from the bottom ash compo-
sition data presented in Section II and Appendix C for the coal fuels of
importance. Ash from oil, gas, and other fuels will be negligible.
Table 121. ESTIMATED EMISSIONS FROM COMMERCIAL/INSTITUTIONAL
ASH HANDLING, 1973a
3.0.00.0.0
3.1.00.0.0
3.1.10.0.0
3.1.11.0.0
3.1.11.1.0
3.1.11.2.0
3.1.11.4.0
3.1.12.0.0
3.1.12.4.0
3.1.13.0.0
3.1.13.4.0
3.1.21.4.0
Commercial /Institutional
External Combustion
Coal
Bituminous
Pulverized Dry
Pulverized Wet
All Stokers
Anthracite
All Stokers
Lignite
All Stokers
Residual Oil
Ash
generated,
tons/year
700,000
700,000
700,000
460,000
18,000
2,000
440,000
. 235,000
235,000
5.000
5,000
Nil
Storage
requirements ,
acre feet/year
319
319
319
209
8
1
200
105
105
5
5
Nil
Air emissions
from landfill,**
tons/year
350
350
350
230
9
1
220
110
110
5
5
Nil
See Appendix C for fuel composition of bottom ash.
Based on a landfill depth of 10 feet.
COOLING SYSTEMS
Cooling water requirements are not applicable to the commercial/institu-
tional sector. The majority of commercial/institutional boilers are used
318
-------
for space heating and do not -require the use of cooling water. The cooling
water required for the few larger institutional boilers will be negligible.
OTHER WASTEWATER SOURCES
These emission streams are of minor consequence in this combustion area
where small, low pressure boilers predominate. Estimates of waste volumes
are less than 10 gallons per year.
COAL STORAGE
The coal storage requirements of commercial/institutional combustion sources
are provided in Table 122. These values are based on an average storage re-
quirement of 10 days. Storage pile height has been assumed to be 10 feet.
Air emissions from coal pile storage will be negligible — less than 1 ton
per year. Coal pile drainage volumes have been estimated assuming 50 per-
cent open storage. Coal pile drainage composition can be obtained from data
presented in Section II.
Table 122. COMMERCIAL/INSTITUTIONAL EMISSIONS FROM COAL STORAGE, 1973
3.0.00.0.0
3.1.00.0.0
3.1.10.0.0
3.1.11.0.0
3.1.11.1.0
3.1.11.2.0
3.1.11.4.0
I
3.1.12.0.0
3.1.12.4.0
3.1.13.0.0
3.1.13.4.0
Commercial/ Institutional
External Combustion
Coal
Bituminous
Pulverized Dry
Pulverized Wet
All Stokers
Anthracite
All Stokers
Lignite
All Stokers
Tons
stored
190,000
140,000
29,000
1,000
110,000
'49,000
49,000
1,000
1,000
Storage requirements
Area,
acres/year
12
9
2
-
7
3
3
-
-
Volume,
acre feet/year
120
90
20
-
70
30
30
-
-
Coal pile
drainage,3
10^ gal/year
6,500
4,800
950
50
3,800
1,660
1,660
40
40
Assumed 50 percent open storage.
319
-------
REFERENCES
1. Patterns of Energy Consumption in the United States. Stanford
Research Institute. Office of Science and Technology, Washington,
D.C. January 1972.
2. Sales of Fuel Oil and Kerosene in 1973. Bureau of Mines, U.S.
Department of the Interior. Washington, D.C. 1974.
3. Natural Gas Production and Consumption, 1973. Bureau of Mines,
U.S. Department of the Interior. Washington, D.C. 1974.
4. Bituminous Coal and Lignite Distribution 1973. Bureau of Mines,
U.S. Department of the Interior. Washington, D.C. 1974.
5. Sales of Liquid Petroleum Gases and Ethane in 1973. Bureau of
Mines, U.S. Department of the Interior. Washington, D.C. 1974.
6. Production and Distribution of Pennsylvania Anthracite in 1973.
Mineral Industry Surveys. Bureau of Mines, U.S. Department of the
Interior. 1974.
7. Moscowitz, C. M., R. F. Boland, and D. L. Zanders. Source Assess-
ment Document No. 15 - Oil-Fired Industrial Commercial Boilers
(Draft Report). Monsanto Research Corporation. U.S. Environmental
Protection Agency Contract No. 68-02-1320. March 1975.
8. Barrett, R. E. et al. A Field Investigation of Emissions from Fuel
Oil Combustion for Space Heating. U.S. Environmental Protection
Agency Report No. R2-73-084a. June 1973.
9. Paddock, R. E. and D. C. McMann. Distribution of Industrial and
Commercial/Institutional External Combustion Boilers. Research
Triangle Institute, Research Triangle Park, North Carolina. U.S.
Environmental Protection Agency Publication No. EPA-650/2-75-021.
February 1975.
10. Compilation of Air Pollutant Emission Factors. U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina. Publi-
cation No. AP-42. April 1973.
11. McGowin, C. R. Stationary Internal Combustion Engines in the United
States. Shell Development Company. U.S. Environmental Protection
Agency Report No. R2-73-210. April 1973.
12. Ehrenfeld, J. R., R. H. Bernstein et al. Systematic Study of Air
Pollution from Intermediate-Size Fossil-Fuel Combustion Equipment.
Walden Research. U.S. Environmental Protection Agency, Cincinnati,
Ohio. Report APTD No. 0924. July 1971.
320
-------
13. Steam Plant Air and Water Quality Control Data Summary Report for
the year ended December 31, 1971. Federal Power Commission,
Washington, D.C. June 1974.
14. Shelton, E. M. Burner Fuel Oils, 1974. Bureau of Mines, U.S.
Department of the Interior, Bartlesville, Oklahoma. 1975.
15. Hangebrauck, R. P., D. J. von Lehmden, and J. E. Meeker. Sources
of Polynuclear Hydrocarbons in the Atmosphere. U.S. Department
of Health, Education and Welfare. Publication Number PHS No.
999-AP-33. 1967.
16. Magee, E. M., H. F. Hall, and G. M. Vaige, Jr. Potential Pollutants
in Fossil Fuels. U.S. EPA Contract No. R2-73-249. Prepared by ESSO
Research and Engineering Company, Linden, N. J. June 1973.
170 Zubovic, D. P., et al. Distribution of Minor Elements in Some Coals
in the Western and Southwestern Regions of the Interior Coal Province
Geological Survey Bulletin No. 1117-D. 1967
18. Kessler, T., A. G. Sharrey, and R. A. Friedel. Analysis of Trace
Elements in Coal by Spark-Source Mass Spectrometry. Pittsburgh Energy
Research Center, Pittsburgh, Pa. U.S. Department of Interior, Bureau
of Mines. RI7714.
19. Ruch, R. R., H. I. Glusroter, and N. F. Shimp. Occurrence and
Distribution of Potentially Volatile Trace Elements in Coal. An
Interim Report. Illinois State Geological Survey. April 1973.
20. von Lehmden, D. J., Robert H. Jungers, and Robert'E. Lee, Jr.
Determination of Trace Elements in Coal, Fly Ash, Fuel Oil and
Gasoline - A Preliminary Comparison of Selected Analytical Techniques.
Analytical Chemistry. 46:239. February 1974.
21. von Lehmden, D. J. Personal Communication. June 1975.
22. Validation of Neutron Activation Technique for Trace Element
Determination in Petroleum Products. Gulf Radiation Technology.
A.P.I. 4188. August 1973.
23. Anderson, D. Emission Factors for Trace Substances. U.S EPA
Contract No. 450/2-73-001.
24. Sahagian, J., R. Hall, and N. Surprenant. Waste Oil Recovery and
Reuse Program - Residue Management, Draft Final Report. GCA
Corporation, GCA/Technology Division.
25. Davis, D. D., G. W. Sonal, et al. Study of the Emissions from Major
Air Pollution Sources and Their Atmospheric Interactions. University
of Maryland, Department of Chemistry Progress Report. November 1,
1972 - October 31, 1973.
321
-------
SECTION V
RESIDENTIAL COMBUSTION SOURCES
Total fuel comsumption by the residential sector is estimated to be
12
10,350 x 10 Btu/year, with 78 percent of this total utilized for space
heating. The remainder is used for various purposes such as cooking,
water heating, air conditioning, etc. Fuel consumption estimates for
the major fuel classifications are given in Table 123. The percentage
of each fuel used for space heating is also provided in the table. The
estimate of residential fuel usage is based on procedures described in
reference 2, using information from references 3 to 12. The procedures
involve the apportionment of fuel usage data for the combined commercial/
residential sectors to the residential sector by considering the number
of dwelling units in a state using each fuel, the degree days within
each state, and the fuel requirements per degree day per dwelling unit.
Table .123. RESIDENTIAL FUEL USE, 1973
4.0.00.0.0
4.1.00.0.0
4.1.10.0.0
4.1.11.0.0
4.1.12.0.0
4.1.13.0.0
4.1.20.0.0
4.1.22.0.0
4.1.30.0.0
4.1.42.0.0
Residential
External Combustion
Coal
Bituminous
Anthracite
Lignite
Petroleum3
Distillate Oil
Gas
Wood
Space heating,
1012 Btu/yr
8,057
8,057
192
115
75
2
2,280
2,280
5,450
135
Percent of
fuel used for
space heating
78
100
100
100
100
94
94
70
100
Over 95 percent No. 1 or No. 2 distillate oil.
322
-------
NUMBER AND CHARACTERISTICS OF BOILERS
The literature contains few references to the number and characteristics
of residential combustion sources other than those provided by the Bureau
of Census. The number of individual sources tabulated below has been
estimated from oil-fired equipment data:13
Oil-fired units
Gas-fired units
Coal-fired units
11 x 10
27 x 10*
1 x 10*
6
Total 39 x 10 .
The population of coal- and gas-fired units was estimated by assuming
that the fuel unit population was a direct function of fuel consumption
used for space heating. Sales data by type and size of oil-fired equip-
ment are also provided in reference 13 and are summarized in Tables 124
and 125. Although a general survey of existing burner population by
detailed burner and system type is not available, data presented in
these tables provide guidelines for estimating population and selecting
representative equipment mix. The size distribution -provided in Table 125
can be assumed to be representative of natural gas equipment also, although
variations due to geographic and climatic differences are conceivable.
Table 124. SALES OF DOMESTIC OIL BURNERS BY TYPE
13
Oil burner type
High- pressure gun burners
Low pressure burners
Vertical-rotary burners
Vaporizing burners
Miscellaneous types
1969,
percent
95.0
3.4
0.4
1.2
-
Pre-1941,
percent
71.7
6.2
11.0
10.8
0.3
323
-------
Table 125. DISTRIBUTION OF SIZES OF DOMESTIC OIL-FIRED EQUIPMENT
13
a
By firing rates, gph,
all 1970 installations
Rate
< 1.0
1.0 - 1.35
1.35 - 1.65
1.66 - 2.0
2.01 - 3.0
> 3.0
Percent
32
37
12
7
7
5
By boiler sizes,
103 Btu/hr
Size
< 75
76 - 100
101 - 125
126 - 150
> 150
Percent
3
26
45
16
10
By furnace sizes,
10J Btu/hr
Size
< 50
50 - 75
76 - 100
101 - 125
> 125
Percent
2
11
42
32
13
Gallons per hour.
FLUE GAS EMISSIONS
Total nationwide emission estimates of particulates (including < 3 micron
diameter particulates), sulfur oxides, nitrogen oxides, hydrocarbons,
carbon monoxide, polycyclic organic matter, and trace elements are pre-
sented in Table 126 for residential space heating combustion sources.
The estimates are based on the EPA-NEDS emission factors listed in
Table 127, and on the iaethods described in the notes following Table 126.
Residential combustion sources account for 0.7 percent of total particu-
lates, 4.2 percent of sulfur oxides, 1.5 percent of nitrogen oxides,
0.3 percent of hydrocarbons, and 0.3 percent of carbon monoxide emis-
sions from all man-made sources. They account for 3.3 percent of total
particulates, 6.3 percent of sulfur oxides, 3.2 percent of nitrogen
oxides, 31 percent of hydrocarbons, and 44 percent of carbon monoxide
emissions from the stationary combustion sources considered in this
study.
324
-------
Table 126. FLUE GAS EMISSIONS FROM RESIDENTIAL COMBUSTION, 1973'
u>
ro
Ul
4.0.00.0.0 Residential
4.1.00.0.0 External Combustion
4.1.10.0.0 Coal
4.1.11.0.0 Bit:uminousb>c
4.1.12.0.0 Anthrnciteb»d
4.1.13.0.0 Lignite6
4. 1 .20.0.0 Petroleum
4.1.22.0.0 Distillate Oilf
4.1.30.0.0 GasS
4.1.42.0.0 Wood/Barkh
I'iirt Li'.u l.'Hi'K ,
10* tons/yr
Total
230
230
69
53
15
1.4
82
82
52
25
<3./l
J20
120
1.3
1.0
0.29
0.027
74
74
47
0.49
Gases ,
10-* Lous/yr
SOX
1,400
1,400
240
210
27
1.0
1,200
1,200
1.5
3.7
NOX
350
350
12
7.9
4.3
0.3
98
98
210
25
!1C
110
110
57
53
3.6
0.05
25
25
21
5.0
CO
470
470
370
240
130
0.1
41
41
54
5.0
Organics ,
tons/yr
BSD
69,000
69,000
43,000
26,000
17,000
450
14,000
14,000
12,000
840
PPOM
4,100
4,100
4,000
2,400
1,600
42
11
5.2
6.3
77
BaP
390
390
380
230
150
3.6
1.1
0.50
0.60
7.4
-------
u>
Table 126 (continued). FLUE GAS EMISSIONS FROM RESIDENTIAL
COMBUSTION, 1973a
4.0,00.0.0 Residential
4.1.00.0.0 External Combustion
4.1.10.0.0 Coalk
4.1.11.0.0 Bituminous1
4.1.12.0.0 Anthracite1"
4.1.13.0.0 Lignite"
4.1.20.0.0 Petroleum
4.1.22.0.0 Distillate Oil0
4.1.30.0.0 Gas?
4.1.42.0.0 Wood/Bark
Iracc1 elements, J
Lons/yr
Sh
0.031
0.031
0.031
0.03
0.001
ND
ND
As
1.9
1.9
1.8
1.6
0.15
0.05
0.05
Ba
3.2
3.2
3.2
1.9
0.89
0.42
ND
ND
Be
0.16
0.16
0.16
0.12
0.04
Bi
0.053
0.053
0.053
0.05
0.001
0.002
B
2.7
2.7
2.7
2.6
0.015
0.057
Br
83
83
81
78
2.9
2.0
2.0
Cd
0.021
0.021
0.021
0.020
0.0010
ND
ND
Cl
12,000
12,000
12,000
7,800
4,400
16
Cr
2.4
2.4
2.4
0.7
1.7
0.006
ND
JCD
-------
UJ
NJ
Table 126 (continued). FLUE GAS EMISSIONS FROM RESIDENTIAL
COMBUSTION, 1973a
A. 0.00. 0.0 Residential
A. 1.00. 0.0 External Combustion
A. 1.10. 0.0 Coalk
4.1.11.0.0 Bituminous1
4.1.12.0.0 Anthracite"1
4.1.13.0.0 Lignite"
4.1.20.0.0 Petroleum
4.1.22.0.0 Distillate Oil°
4.1.30.0.0 Gas?
4.1.42.0.0 Wood/Bark
Trace elements,
tons/yr
Co
1.5
1.5
1.5
0.20
1.3
0.005
Cu
1.9
1.9
1.8
0.7
1.1
0.008
0.05
0.05
F
740
740
740
420
320
Fc
280
280
280
180
99
Pb
0.64
0.64
0.64
0.5
0.13
0.009
Mn
26
26
26
23
2.6
0.039
0.006
0.006
Hg
1.4
1.4
•1.4
0.65
0.78
0.002
• ND
ND
Mo
0.35
0.35
0.35
0.2
0.15
0.004
Ni
1.5
1.5
1.5
0.8
0.73
ND
ND
Se
10
10
10
10
0.4
ND
ND
-------
OJ
to
00
Table 126 (continued). FLUE GAS EMISSIONS FROM RESIDENTIAL
COMBUSTION, 1973a
A. 0.00. 0.0 Residential
4.1.00.0.0 External Combustion
A. 1.10. 0.0 Coalk
4.1.11.0.0 Bituminous1
4.1.12.0.0 Anthracite™
4.1.13.0.0 Lignite"
4.1.20.0.0 Petroleum
4.1.22.0.0 Distillate 011°
4.1.30.0.0 GasP
4.1.42.0.0 Wood/Bark
Trace elements,-1
tons/yr
Te
0.021
0.021
0.021
0.020
0.001
Tl
0.006
0.006
0.006
0.005
0.001
Sn
0.18
0.18
0.064
0.05
0.01
0.004
0.12
0.12
Ti
40
40
40
31
8.7
U
0.8
0.8
0.8
0.8
0.004
V
1.6
1.6
1.6
1.4
0.19
0.012
ND
ND
Zn
3.1
3.1
3.1
1.1
2.0
0.018
ND
ND
Zr
3.8
3.8
3.8
2.4
1.4
-------
Table 126 (continued). FLUE GAS EMISSIONS FROM RESIDENTIAL COMBUSTION, 19733
Values in the table represent total estimated emissions to the atmosphere from conventional stationary
combustion sources in the United States. An entry of "ND" signifies that a trace element has not been
detected when measured; and an entry left blank signifies that no information is available. All the
emission factors used in this table are given in Table 127.
The consumption data for anthracite and bituminous coal were calculated according to the formula
described in reference 2. This formula considers the number of dwelling units in a state using
coal as a heating fuel, the degree days, and the coal heating requirement factor of 0.0012 ton coal
per degree day per dwelling unit. State total coal consumed = (Number of dwelling units x degree days X
0.0012) ton/year. The number of heating units was obtained from reference 3 and the degree days from
reference 4. The total residential coal consumption was calculated for the year 1970, for each state
and combined by the geographical regions listed in reference 5. The calculated coal consumption by
households was ratioed to coal received by retail dealers in 1970 according to reference 6 to obtain
the percentage of coal used by residential as opposed to commercial users. This percentage was applied
u> to the 1973 data obtained from reference 7 to obtain a more recent estimate.
to
Anthracite consumption was obtained from reference 8. According to reference 2, in states where
anthracite consumption exceeded the total quantity of coal used in residential heating, the total
consumption was considered as anthracite. In states where anthracite deliveries were less than the
consumption, the difference was assumed to be bituminous coal. In states where anthracite was not
available, the total residential coal consumption was considered to be bituminous coal.
ft
The sulfur content was obtained from reference 5 for individual states.
The sulfur content was assumed to be 0.5 percent.
Lignite consumption was obtained from reference 12. Sulfur content was assumed to be 0.6 percent;
ash content 9.6 percent.
Distillate oil consumption as residential fuel was calculated according to reference 3, by multiply-
ing the number of dwelling units burning oil in a state taken from reference 4 by the degree days and
by the heating requirement factor of 0.18 gallon oil per degree day. State total consumed = (Number of
dwelling units x degree day x 0.18) gal/year. Sulfur content was obtained from reference 9.
-------
Table 126 (continued). FLUE GAS EMISSIONS FROM RESIDENTIAL COMBUSTION, 1973*
g
Natural gas consumption was obtained from reference 10, page 8, under residential use. Combined resi-
dential and commercial LPG consumption data were obtained from reference 11, page 4. The fraction used
in residential units as opposed to commercial units in each state was assumed to be the same as for
natural gas. The emissions were combined for natural gas and LPG.
Wood consumption as residential fuel was calculated according to reference 2, by multiplying the
number of dwelling units burning wood taken from reference 3 with the degree days in a given state
taken from reference 4 and the heating requirement factor of 0.0017 ton of wood per dwelling unit
degree day. State total wood consumed = (Number of dwelling units x degree day x 0.0017) tons/year.
The wood consumption was combined for regions and for the country. The value in the table includes also
emissions from the ten million tons of wood burned in fireplaces annually in the United States,
estimated in reference 15.
"""The emissions of BaP and BSO from all fuels were calculated from emission factors in reference 16.
The emissions from coal of particulate polycyclic organic matter (PPOM) were based on a summation
of emission factors for PYRENE, BENZO(a)PYRENE, BENZO(e)PYRENE, PERYLENE, BENZO(ghi)PERYLENE, ANTHAN-
THRENE, CORONENE, ANTHRACENE, PHENANTHRENE, FLUORANTHENE. PPOM emissions -from oil and gas were cal-
culated by assuming the same ratio of BaP as in the case of coal. Emission factors were specific
to residential size combustion equipment. No data were found on emissions of polyhalogenated biphenyls
from residential combustion.
The amount of each trace element, i/emitted to the atmosphere was calculated as follows:
(1) The amount of i in the fuel, A., was
A. - C± x F.
where C. = concentration of i in the fuel, ppm
F. = yearly consumption of fuel, tons/year.
If A. was calculated on a regional basis, results were summed to the national level.
-------
Table 126 (continued). FLUE GAS EMISSIONS FROM RESIDENTIAL COMBUSTION, 1973a
(2) The amount emitted to the atmosphere, E., was
E± - A. x f.
where f. = estimated fraction of i emitted to the atmosphere.
Values of f.£ were small, as a large fraction of the emissions are soot. For bituminous coal
fi = 0.01, for anthracite f± = 0.005, for lignite f± = 0.014, for distillate oil f± = 0.005.
Exceptions are Br, Cl, and F for which f.^ = 1.0, Hg for which f^ = 0.90 and Se for which
fi = 0.70.
k
Data for coal were available for each of the coal-producing regions defined by the U.S. Geological
Survey. Sources of trace element concentration data were publications by Magee,l' Zubovic,18 Ruch,/-^
and von Lehmden.20>21
OJ ^
M For each coal-producing region, concentrations of As, Ba, Be, B, Cr, Co, Cu, F, Pb, Mn, Hg, Mo, Ni, Sn,
U. V, and Zn in bituminous coal were calculated using reference 17 as a primary source and reference 18
as a supplementary source. For Cl, Br, and Ti, data from Illinois in reference 19 were used as typical
of all coal-producing regions. For Sb, Bi, Cd, Fe, Te, Tl, and Zr, concentrations were calculated by
using reference 22. For se, the single concentration cited by reference 21 was used.
mFor anthracite coal, typical trace element concentrations were taken from reference 22.
nFor lignite, reference 17 supplied the data for North Dakota lignite and reference 18 supplied the data
for Texas lignite. Reference 17 contained data for the elements As, Ba, Be, Bi, B, Br, Co, Cu, Cr, Mn,
Mo, Ni, Sn, V, Zn, and Zr. Reference 18 contained data for the elements Be, Br, Co, Cu, Mo, Ni, Sn, V,
and Zr. A concentration of Cl in lignite was obtained from reference 23. Lignite consumption in 1974
consisted of 6.9 x 10^ tons from North Dakota and 5.7 x 10 tons from Texas, according to reference 11.
°For distillate oil, reference 24 reported concentrations for As, Br, Cu, Mn, and Sn and reported that
Sb, Ba, Cd, Cr, Hg, Ni, Se, V, and Zn were not detectable.
^Hydrocarbon gases were assumed to be free of trace elements.
^Emissions of < 3 microns particulates were assumed to be 2 percent of the total particulate emissions
for coal. For oil and gas, 90 percent of the particulates were assumed to be < 3 microns.
-------
Table 127. EMISSION FACTORS FOR TABLE 126
4.0.00.0.0 Residential
4.1.00.0.0 External Combustion
4.1.10.0.0 Coalb
4.1.11.0.0 Bituminous
4.1.12.0.0 Anthracite
4.1.13.0.0 Lignite
4.1.20.0.0 Petroleum0
4.1.22.0.0 Distillate Oil
4.1.30.0.0 Gasd
4.1.42.0.0 Wood/Barkb
Particulatesa
Total
NA
NA
NA
20
10
3A
10
10
10
10
Gases3
sox
NA
NA
NA
38S
36. 8S
30S
144S
144S
0.6
1.5
NOX
NA
NA
NA
3
3
6
12
12
80
10
HC
NA
NA
NA
20
2.5
1
3
3
8
36
CO
NA
NA
NA
90
90
2
5
5
20
31
Abbreviations used in the table have the following meanings
A = Multiply by weight percent ash
S = Multiply by weight percent sulfur
NA = Not applicable.
The emission factors for coal and wood/bark give values in terms of
pounds of pollutant per ton burned.
c
The emission factors for oil give values in terms of pounds of pollutant
per 1000 gallons of oil burned.
The emission factors for gas give values in terms of pounds of pollutant
per 10" cubic feet of gas burned.
332
-------
A comparison of recent field" measurements (for 30 oil-fired units14 and
2 gas-fired units ) with EPA emission factors25 is presented in Table 128.
Hydrocarbon emissions from oil-fired units appear to be lower than re-
ported EPA emission factors. Recent studies26"28 have provided more data
on residential emissions, including the effects of excess air and burner
modifications. The particle size distribution of emissions from oil-fired
29
units has been measured.
Table 128. COMPARISON OF EMISSION FACTORS FOR
RESIDENTIAL COMBUSTION UNITS
Fuel
Oil-fired units
Reference 14
EPAa
Gas-fired units
Reference 13
EPAa
Emission factors, lb/106 Btu
Particulate
0.06
0.07
0.005
0.02
S02
0.3b
0.3b
0
0.0006
NOX
0.13
0.09
0.08
0.08
HC
0.005
0.02
0.004
0.008
CO
0.06
0.04
0.02
0.02
Reference 25.
For 0.3 percent sulfur.
Most emissions from residential combustion sources constitute minor
fractions of total combustion source emissions. A notable exception in
the case of air emissions is the emission of polycyclic organic matter
(POM). Although the data quality is not high, residential coal-fired
furnaces, because of their low combustion efficiency, are the principal
combustion source of POM. Residential oil combustion is also suspected
29
as a possible cause of high sulfate levels in eastern urban areas.
To obtain state emission estimates for purposes of assigning priorities
to the various combustion systems, it will be necessary to prorate the
333
-------
nationwide values by multiplying by the ratio of the fuel consumption in
a state to the fuel consumption nationwide. Fuel consumption estimates
by state are provided in Appendix B. Additional data on trace element
content are provided in Appendix C.
OTHER EMISSIONS
The only other waste stream contributing to environmental pollution is
that due to ash disposal. However, this is relatively minor since coal
and other high ash fuels are not consumed to any extent for residential
space heating. Total ash produced is about 800,000 tons/year. This ash
will be disposed of as landfill, with the major portion handled by munic-
ipal disposal methods.
334
-------
REFERENCES
1. Patterns of Energy Consumption in the United States. Office of
Science and Technology. Washington, D.C. January 1972.
2. Guide for Compiling a Comprehensive Emission Inventory. U.S. En-
vironmental Protection Agency. Report No. APT 1135. March 1973.
3. 1970 Census of Housing. Detailed Housing Characteristics. HC-B
series. U.S. Department of Commerce, Bureau of Census. Washing-
ton, D.C. 1970.
4. Gas Facts. A Statistical Record of the Gas Industry. American
Gas Association, Department of Statistics. 1973.
5. Steam Electric Plant Air and Water Quality Data. Federal Power
Commission. 1973.
6. Mineral Industry Surveys. Bituminous Coal and Lignite Distribution.
Calendar Year 1970. U.S. Department of Interior, Washington, D.C.
7. Bituminous Coal and Lignite Distribution. Calendar Year 1973.
U.S. Department of Interior, Washington, D.C.
8. Minerals Yearbook 1972, Volume I. Metals, Minerals and Fuels, 1972.
U.S. Government Printing Office, Washington, D.C. 1974.
9. Shelton, E.M. Burner Fuel Oils. 1974 Bureau of Mines. U.S. Depart-
ment of the Interior, Bartlesville, Oklahoma. 1975.
10. Mineral Surveys. Natural Gas Production and Consumption, 1973.
U.S. Department of the Interior, Washington, D.C. August 1974.
11. Mineral Industry Surveys. Sales of Liquified Petroleum Gases and
Ethane in 1973. U.S. Department of the Interior, Washington, D.C.
1974.
12. Westerstrom, Leonard. Personal Communication. U.S. Bureau of Mines,
Washington, D.C. May 1975.
13. Levy, A. et al. A Field Investigation of Emissions from Fuel Oil
Combustion for Space Heating. API Publication 4099. November 1971.
14. Barrett, R. E. et al. Field Investigation of Emissions from Com-
bustion Equipment for Space Heating. EPA-R-2-73-084a. June 1973.
15. Hydrocarbon Pollutant Systems Study. Volume I. Stationary Sources
Effect and Control, M.S.A. Research Corporation. NTIS, U.S. Depart-
ment of Commerce, P.B. 219073.
335
-------
16. Hangebrauck, R. P., D. J. von Lehmden, and J. E. Meeker. Sources
of Polynuclear Hydrocarbons in the Atmosphere. U.S. Department
of Health, Education and Welfare, Public Health Service, PHS-999-
AP-33. 1967.
17. Magee, E. M., H. F. Hall, and G. M. Vaige, Jr. Potential Pollu-
tants in Fossil Fuels. EPA R2-73-249. Prepared by ESSO Research
and Engineering Co., Linden, N.J. June 1973.
18. Zubovic, D. P., et al. Distribution of Minor Elements in Some
Coals in the Western and Southwestern Regions of the Interior
Coal Province. Geol. Survey Bulletin 1117-D. 1967.
19. Ruch, R. R., H. I. Glusroter, and N. F. Shimp. Occurrence and
Distribution of Potentially Volatile Trace Elements in Coal. An
Interim Report. Illinois State Geological Survey. April 1973.
20. von Lehmden, D. J., Robert H. Jungers, and Robert E. Lee, Jr.
Determination of Trace Elements in Coal, Fly Ash, Fuel Oil and
Gasoline - A Preliminary Comparison of Selected Analytical Tech-
niques. Analytical Chemistry. 46:239. February 1974.
21. von Lehmden, D. J. Personal Communication. June 1975.
22. Kessler, T., A. G. Sharrey, and R. A. Friedel. Analysis of Trace
Elements in Coal by Spark-Source Mass Spectrometry. Pittsburgh
Energy Res. Center, Pittsburgh, PA. U.S. Department of Interior,
Bureau of Mines. 7714-
23- McAlpin, W. H. and B. B. Tyus. Design Considerations for 575 MW
Units at Big Brown Steam Electric Station. Proceedings: Bureau
of Mines - University of North Dakota Symposium, Grand Forks, N.D.
May 1973.
24. Validation of Neutron Activation Technique for Trace Element Deter-
mination in Petroleum Products. Gulf Radiation Tech. Aug. 1973.
A.P.I. 4188.
25. Compilation of Air Pollutant Emission Factors, U.S. Environmental
Protection Agency, EPA No. AP-42-A.
26. Combs, L. P., W. H. Nurick, A. S. Okuda. Integrated Low Emis-
sion Residential Furnace. Rockx^ell International. EPA Contract
Nos. 68-02-0017 and 68-02-1819-
27. Hall, R. E., J. H. Wasser, E. E. Berkau. A Study of Air Pollu-
tant Emissions From Residential Heating Systems. EPA-650/2-74-
003. Research Triangle Park, N.C. January 1974.
336
-------
28. Barrett, R. E., D. W. Locklin and S. E. Miller. Investigation
of Particulate Emissions From Oil-Fired Residential Heating
Units. Battelle, Columbus Laboratories. EPA-650/2-74-026.
Research Triangle Park, N.C. March 1974.
29. Air Quality and Stationary Source Emission Control. Report to
Congress. Committee on Public Works. Serial No. 94-4.
March 1975.
337
-------
SECTION VI
TRENDS IN FOSSIL FUEL CONSUMPTION
The prediction of fossil fuel consumption patterns over the next 10 years
is dependent on political (local, state, national and international),
economic, environmental and technological considerations. As an illus-
tration of this complexity, the factors affecting fuel and electricity
supply and demand over the past several years can be examined, since
these factors continue to change and influence the fuel supply and con-
sumption situation. One extremely important factor is the pricing policy
of the Oil Producing and Exporting Countries (OPEC). During the 1-year
period January 1973 to January 1974, OPEC increased the price of crude
oil by a factor of 4, and as a result the price of refined oil as pur-
2
chased by U.S. steam electric plants subsequently tripled (see Figure 30).
The price of oil affected the price of other energy sources, causing
coal and natural gas prices to rise sharply- although not nearly as rapidly
as oil prices. During the 1960's the price of imported oil remained
relatively constant in the range of $1.50 to $1.75 per barrel, and well
3
below the most current price of $13.50 per barrel. Clearly, any studies
conducted during the 1960's to estimate fuel consumption patterns in the
1970's have been invalidated by the sudden changes in 1973.
Federal regulations and policies also strongly affect fuel-use patterns.
In the past, environmental laws encouraged utilities to switch from coal
to oil. At the present time, the Federal Energy Administration is
involved in procedures to force many oil and/or gas burning utility boilers
to switch back to coal and to force some new plants now being planned to
burn coal.
338
-------
HOKIHIT COS! Of fOSSIl fUtlS OUIVtHtO 10 Ui
-ucciftic UIIIIIT rums, zs UN on cnurci
LINE I OIL (ALL TYPES)
LINE a COAL
LINE 3 NATURAL GAS
1974
YEAR 1973
2
tr
i/>
I-
H
UJ
o
J»
H
co
O
o
UJ
O
u.
Figure 30. Monthly cost of fossil fuels delivered
to U.S. steam-electric utility plants,
25 MW or greater
The Federal government is also involved in the pricing of fossil fuels,
thus affecting energy-use patterns. In the spring of 1975 the U.S.
Government imposed a $2.00 per barrel tariff on imported oil which raised
the total price to $13.50 per barrel. At the same time domestic oil was
controlled at a price of $5.25 per barrel. The courts have since de-
clared the $2-.00 per barrel tariff to be illegal. In addition, the
price of domestic oil is scheduled to be decontrolled on August 31, 1975.
These variations in oil prices affect both the oil supply and demand.
Only a few of the many factors affecting fuel-use patterns were discussed
in the above paragraphs. Federal regulations and environmental considera-
tions strongly influence the development of western coal resources through
strip mining. Development of mines, electric power plants and large
339
-------
equipment delivery are subject to very long lead times, in the range of
2 to 7 years. Manpower availability and training also affect the develop-
ment of energy resources. Advanced energy technologies such as coal
gasification or liquifaction, magnetohydrodynamics, solar energy and
fusion power are not expected to produce significant amounts of energy
by 1985, although unexpected technological breakthroughs may alter the
6
situation.
The majority of the trends discussed in this section are based on the
Federal Energy Administration's Project Independence Report published
in November 1974. Many other energy related references were con-
sulted and used to supplement the Project Independence Report, but the
Project Independence Report was judged to be the most recent and reliable
analysis available. However, the Project Independence studies only con-
sidered three prices for imported oil, $4, $7, and $11 per barrel. The
most current price for imported oil is $13.50 per barrel, including the
tariff, and OPEC is considering a 30 to 40 percent increase for the fall
cf 1975. Therefore, the shift toward co;
dieted in the Project Independence Report.
cf 1975. Therefore, the shift toward coal may be stronger than pre-
Analysis of fuel use and trend data indicates that energy use will in-
crease 29 percent from 1973 to 1985 in the conventional combustion sys-
tems considered in this study, as shown in Table 129- Coal use will in-
crease 87 percent, oil use will decrease 2 percent and natural gas use
will increase 13 percent. The large increase in coal consumption will
be confined to the electric utility and industrial sectors while the in-
crease in natural gas consumption will be confined to the commercial and
residential sectors. These trends indicate a potential increase in
those pollutants associated with coal, either as an air, water, or solid
waste pollutant. The actual change in emissions to the air will depend
on coal properties (i.e., ash, trace element, and sulfur content) and
the application and effectiveness of particulate and sulfur oxide control
equipment. Additional water and solid waste pollutants will be generated
by the increased coal combustion and control equipment operation. The use
340
-------
Table 129.
FUEL CONSUMPTION TRENDS: STATIONARY
COMBUSTION SOURCES3
Total
Coal
Oil
Gas
Electric Utilities
Coal
Oil
Gas
Industrial
Coal
Oil
Gas
Commercial /Institutional
Coal
Oil
Gas
Residential
Coal
Oil
Gas
1973b
fuel use,
1012 Btu
38,701C>d'8
10,220
9,958
18,523
15,387
8,502
3,351
3,534
11,300C
1,370
2,060
7,600
4 , 500d
156
2,404
1,939
8,057g
192
2,143
5,450
1985
fuel use,
1012 Btu
49,843e>f'8
19,095
9,801
20,947
22,531e
16,994
3,016
2,485
12,934E
1,945
2,966
7,600
4,941
70
2,019
2,851
9,258s
86
1,800
8,011
Percent
change,
1973b-1985
+29
+87
-2
+13
+46
+100
-10
-30
+14
+42
+44
+0
+10
-55
-16
+47
+15
-55
-16
+47
aElectric generation process steam, space heating, and stationary
engines.
^Utility data represents 1974.
cIncludes 250 x 1012 Btu wood and 20 x 10 Btu bagasse.
dIncludes 1 x 101 Btu wood.
elncludes 36 x 10 Btu refuse.
fIncludes AGO x 1012 Btu wood and 23 x 1012 Btu bagasse.
12
Includes 135 x 10 Btu wood.
341
-------
of western coal (coal supply regions 16 to 23) will increase relative to
eastern coal, possibly causing a decrease in the amount of SC^ emitted
per unit of fuel burned, as discussed in detail in the electric generation
section.
ELECTRIC GENERATION
Fuel Use Trends
During the past 35 years the consumption of fossil fuels for the produc-
tion of electricity has increased at about 7 percent per year with a
doubling interval of about 10 years. ' However, from 1973 to 1974
the consumption of fossil fuel by the electric utility industry declined
1 Q
3.5 percent due to the recession and the sharply increased energy costs.
As shown in Table 129, the consumption of fossil fuel by the electric
utility industry is expected to increase 46 percent from 1974 to 1985, a
growth rate of only 3.5 percent per year compared to the past growth rate
of 7 percent per year. Total electric energy production (including hydro-
power and nuclear) is expected to increase at a higher rate of 5.9 per-
cent per year due to an expected fourteenfold increase in nuclear power.
Coal consumption will increase sharply while oil and gas consumption
will decline. ' ' ' A decline in natural gas consumption was not un-
expected as it is due to limited domestic reserves and was predicted in
Q
1972 before the sudden changes in energy prices. Estimates of the in-
crease in coal consumption range from 50 to 100 percent. Trends in
oil consumption are very uncertain due to the highly volatile price situa-
tion and still developing government programs.
Our estimates of electric utility fuel consumption trends are presented
in Table 130. Specifically, the use of bituminous coal and lignite will
increase sharply while the use of anthracite will decline. Anthracite
consumption by the electric utility industry has declined from 2,240,000
tons in 1964 to 1,460,000 tons in 1974. A study published in 1970
342
-------
predicted that anthracite consumption by the electric utility industry
would decline 6.5 percent per year to the year 2000.11 A more recent
study, based on an $11 per barrel crude oil price, predicted a decline in
demand of about 4 percent per year from 1974 to 1985 or a total decline
1 2
in anthracite consumption of 50 percent. The installed capacity of
lignite-fired electric generation boilers is expected to increase by a
Q
factor of about 10 from 1974 to 1985 and thus the amount of lignite
burned should increase by a factor of 10. We used the Project Indepen-
dence coal estimate of an increase of 100 percent from 1974 to 1985,
based on business as usual with an $11 per barrel world market oil price.
The estimates of a 50-percent decline in anthracite, a tenfold increase
in lignite, and a 100-percent increase in coal, indicate an 81-percent
increase in bituminous coal consumption.
Table 130.
SUMMARY OF ELECTRIC UTILITY FUEL CONSUMPTION
TRENDS TO 1985
1.0.00.0.0
1.1.00.0.0
1.1.10.0.0
1.1.11.0.0
1.1.12.0.0
1.1.13.0.0
1.1.20.0.0
1.1.21.0.0
1.1.22.0.0
1.1.30.0.0
1.1. 40. 0.0
1.2.00.0.0
1.3.00.0.0
1.3.20.0.0
1.3.30.0.0
1.4.00.0.0
1.4.20.0.0
1.4.30.0.0
Electric Generation
External Combustion
Coal
Bituminous
Anthracite
Lignite
Petroleum
Residual Oil
Distillate Oil
Gas
Refuse
Internal Combustion
Turbine
Oil
Gas
Reciprocating.
Oil
Gas
1974
fuel use,
1012 Btu
15,387
14,798
8,502
8,264
38
200
3,039
2,901
138
3,257
0.6
589
515
286
229
74
26
48
1985
fuel use,
1012 Btu
22,531
20,932
16,994
14,975
19
2,000
2,172
2,060
99
1,780
36
1,549
1,467
815
652
82
29
53
Percent
change,
1974-1985
+46
+42
+100
+81
-50
+1000
-29
-29
-29
-55
+6000
+262
+285
+285
+285
+10
+10
+10
343
-------
Assuming business as usual and an .$11 per barrel world market price for
1 o
oil, oil use by the utility industry should be 3,000 x 10 Btu in 1985
12
(down 10 percent from 1974) and gas use should be 2,500 x 10 per year
(down 30 percent). Gas and oil will be burned in conventional steam-
electric plants, combined cycle plants, simple turbines and reciprocating
engines. Reciprocating engines consume a small fraction of utility fossil
fuel (0.5 percent) and the growth has been very slow (50 percent increase
in 25 years). In line with the 1973 to 1974 increase in capacity of
1 percent, GCA estimates that oil and gas use in reciprocating engines
will increase by 10 percent from 1974 to 1985. There is a comparatively
large uncertainty involved in estimating fuel use in turbine systems.
The Project Independence Report estimated that combustion turbine capacity
would increase by a factor of 5 from 1973 to 1985, based primarily on a
very large increase in the use bf combined cycle plants. This type of
plant was first commercially installed in 1971 and 1972, has a higher
efficiency than simple turbines or steam-electric systems, and looked
very promising for intermediate load operation. However, combined cycle
plants use gaseous or premium liquid fuels (which are in short supply and
are high priced) and have a capital cost 2.5 times greater than simple
turbines. During the past few years, new orders for combined cycle
plants have been at a standstill and during 1974 orders for combustion
13
turbines fell sharply. We estimated that the gas turbine growth will
be less than the Project Independence estimate of 500 percent and selected
the growth rate of the past few years (10 percent per year or 280 per-
cent to 1985) . This estimate is based on a linear extrapolation of the
growth rate experienced by gas turbines over the period 1968 to 1974 as
illustrated in Figure 31. The fuel mix was assumed to be the same as the
present mix. The remaining oil and gas use, as estimated in the Project
Independence Report, was assigned to the external combustion category.
Thus, oil burned in utility boilers should decline 29 percent by 1985 and
gas burned should decline 55 percent. The ratio of residual oil to dis-
tillate oil used by external combustion systems in 1985 is assumed to be
the same as 1974.
344
-------
45.000 -
40,000
35,000 -
30.000 -
25,000 -
: 20,000}-
o
u
2
15,000 -
10.000 -
5,000 -
1963 456789 1970 I Z 3 4
Figure 31. Total installed gas turbine generating capacity in
the U.S.
345
-------
The combustion of refuse by utilities' to produce electricity is limited
at this time, with only the Union Electric Meramac Plant in St. Louis
19
County burning significant quantities. At the present time Union Elec-
20
trie can burn about 300 tons per day of refuse. Contracts, however, have
been let for a $70 million project to expand Union Electric's refuse burn-
ing capacity to 8,000 tons per day — the total amount of refuse generated
21
in the St. Louis metropolitan area. Many cities are planning energy
recovery projects but most are not as large as the St. Louis project and
22
are in the early planning stages. It is estimated that refuse combustion
by the utility industry will increase sixtyfold (Union Electric's increase
of 26 times plus a few other systems) from 1974 to 1985.
The most important factor discussed above is the shift from oil and gas
to coal, and the large increase in coal consumption. Coal combustion
produces much more particulate, sulfur, trace element and possibly organic
emissions than natural gas. In addition, coal generally (depending on
particulate or sulfur oxide control equipment and composition of specific
coals and oils) produces more particulates and trace elements than oil and
relatively similar or slightly higher amounts of sulfur oxides. In addi-
tion, coal combustion produces much larger amounts of solid waste and po-
tential water pollutants. Details on the amounts of various pollutants
resulting from the combustion of coal, oil, and gas have been presented
in Section II.
A less significant trend is the relatively greater increase in the combus-
tion of western coal compared to the combustion of eastern coal. The
western coal regions are regions 16 to 23 as presented in Figure 32. The
potential coal supply by region has been estimated for the year 1985 for a
14
business as usual case and an accelerated development case. " The 1985
projected supply and actual 1974 consumption are presented in Table 131.
During 1974, 88 percent of the coal consumed was eastern coal and by 1985
the available supply will be 80 to 81 percent eastern coal. The supply
346
-------
OJ
.p-
Figure 32. Map of the coal-producing districts of the United States
-------
of western coal will increase by a.factor of from 3 to 6 but the per-
centage of the total represented by western coal will only increase from
14
11.6 percent to 19 or 20 percent.
Table 131. WESTERN COAL CONSUMPTION AND SUPPLY
Western
Eastern
Total
1974 consumption
103 tons
71,800
599,200
671,000
Percent
of total
11.6
88.4
100.0
1985 supply:
business as usual
3
10 tons
212,800
887,200
1,100,000
Percent
of total
19.7
80.3
100.0
1985 supply:
accelerated
development
3
10 tons
414,400
1,648,600
2,063,000
Percent
of total
20.1
79.9
100.0
Coal reserves are commonly classified by depth (0 to 1000 ft, 0 to 3000 ft,
0 to 6000 ft) and by reliability of the estimate (measured, indicated, un-
discovered) as well as by specific properties (sulfur content, coal type).
The reserves most likely to be used in the next 10 years and on which the
most data are available are measured and indicated in the depth range of
0 to 1000 feet. The coal reserve base is 433,900 million tons compared
14
to the present yearly consumption of 600 to'700 million tons. Bituminous
coal represents 54 percent, subbituminous 38 percent, lignite 6 percent,
and anthracite 2 percent of the reserves. Western coal (54 percent of the
total reserves) is predominantly subbituminous (76 percent) and lignite
(8 percent).
Western coals contain less ash and sulfur, more moisture, and have a lower
heating value than eastern coal, as shown in Table 132. The major effect
of using western coal instead of eastern coal should be a reduction in the
potential S0? emissions per unit of fuel. Actual SO- emissions will de-
pend on the actual coal mined (as only a small fraction of the reserves
will be used and sulfur content varies from mine to mine) and the applica-
tion of S09 controls. There are extensive reserves (compared to current
348
-------
consumption) of less than 1 percent sulfur coal in the east, but these
reserves have been used primarily for coke manufacture and have been too
24
costly for utility use. The variation in ash content between eastern
and western coal is not significant. Available data on the trace element
25
content of coal show wide variations (one to two orders of magnitude)
within regions, and considering the limited accuracy of the data, there
is no clear difference between eastern and western coal. However, data
on western coal are very limited compared to other coals. The use of
western coal will significantly affect the design and application of
control methods, including particulate, NO , and S09 methods.
X «£>
Table 132. AVERAGE PROPERTIES OF COAL RESERVE BASEC
Western
Eastern
Heat content,
Btu/lb
Dry
12,000
13,300
Raw coal
9,800
12,600
Moisture,
weight
23
5.7
Ash
Weight
7
to
dry
7.2
9.6
lb/106
Btu
6.0
7.2
Sulfur
Weight
7
to
dry
0.58
2.4
Btu
0.48
1.9
aCompiled by GCA from data in reference 14.
Trends in Boiler Population
The trends to 1985 for various boiler types were also estimated and are
presented in Table 133. Based on the average age of stoker-fired boilers
(37 years in'1972) and the normal useful plant life of 35 to 40 years, we
estimated a 50 percent decline in bituminous coal stoker-fired boilers.
New source performance standards limiting N0x emissions from bituminous
coal-fired power plants to 0.7 lb/106 Btu will in effect prohibit the
construction of new cyclone boilers in sizes greater than 250 x 10 Btu/hr,
as NOY emissions from cyclone boilers are in the range of 1.5 to 2.3
X
lb/106 Btu. Many cyclone boilers are relatively new (capacity average
349
-------
Table 133.
ELECTRIC UTILITY FUEL CONSUMPTION TRENDS
TO 1985
1.0.00.0.0
1.1.00.0.0
1.1.10.0.0
1.1.11.0.0
1.1.11.1.0
1.1.11.2.0
1.1.11.3.0
1.1.11.4.0
1.1.12.0.0
1.1.12.1.0
1.1.12.2.0
1.1.12.3.0
1.1.12.4.0
1.1.13.0.0
1.1.13.1.0-
1.1.13.2.0
1.1.13.3.0
1.1.13.4.0
1.1.20.0.0
1.1.21.0.0
1.1.21.0.1
1.1.21.0.2
1.1.22.0.0
1.1.22.0.1
1.1.22.0.2
1.1.30.0.0
1.1.30.0.1
1.1.30.0.2
1.1.40.0.0
1.2.00.0.0
1.3.00.0.0
1.3.20.0.0
1 3.30.0.0
1.4.00.0.0
1.4.20.0.0
1.4.30.0.0
Electric Generation
External Combustion
Coal
Bituminous
Pulverized Dry
Pulverized Wet
Cyclone
All Stokers
Anthracite
Pulverized Dry
Pulverized Wet
Cyclone
All Stokers
Lignite
Pulverized Dry
Pulverized Wet
Cyclone
All Stokers
Petroleum
Residual Oil
Tangential Firing
All Other
Distillate Oil
Tangential Firing
All Other
Gas
Tangential Firing
All Other
Refuse
Internal Combustion
Turbine
Oil
Gas
Reciprocating
Oil
Cas
1974
fuel use,
1012 Btu
15,387
14.798
8,502
8,264
5,971
1,118
1,118
57
38
13
0
0
25
200
120
30
30
20
3,039
2,901
1,128
1,773.
138
54
84
3,257
791
2,466
0.6
589
515
286
229
74
26
48
1985
no I use,
O12 Btu
22,531
20,932
16,994
14,976
11,877
1,952
1,118
29
19
Q
0
o
10
2,000
1,730
220
30
20
2,172
2,060
801
1,259
99
38
61
1,780
356
1,344
36
1,549
1,467
815
652
82
29
53
Percent
cl\;\nK<.',
1974-1935
+ 46
+ 42
+100
+ 81
+ 99
+ 75
+ 0
- 50
- 50
- 30
0
0
- 60
+1000
+1400
+730
+0
0
- 29
- 29
- 29
- 29
- 29
- 29
- 29
- 55
- 55
- 55
+6000
+262
+285
+285
+285
+ 10
+ 10
+ 10
350
-------
age in 1972 was 8 years) and will therefore continue to operate through
1985. It was estimated that the use of cyclone boilers would remain
constant to 1985.
The increase in other bituminous coal-fired boilers was assumed to be
inversely proportional to their average ages (see Table 13), and increases
of 99 percent and 75 percent were calculated for pulverized dry bottom
and pulverized wet bottom boilers, respectively. The population of
anthracite-fired boilers will decline sharply to 1985. Since stoker-fired
boilers are older, it was assumed that they would decline twice as fast as
pulverized-fired boilers.
As shown in Table 130, lignite consumption by the utility industry is
expected to increase 1000 percent from 1974 to 1985. In the past, small
stokers have been mainly used to burn lignite, but more recently the trend
27
has been to large pulverized coal or cyclone boilers. Two new pul-
verized lignite dry bottom boilers with a total capacity of 1,150 MW
began operation in late 1971 and early 1972. These two new boilers burned
about 20 percent of the lignite in 1974. Another recently installed
28
lignite-fired boiler is a 235 MW cyclone. However, the future growth
of lignite-fired cyclone type boilers may be limited by anticipated new
29
source performance standards. We estimated that the use of cyclone type
boilers to burn lignite would not increase to 1985. In addition, it was
estimated that the use of stoker-fired boilers would not increase as the
trend is to larger boilers. Although very little data were available, we
estimated that the growth rate of pulverized dry bottom boilers would
be twice the rate for pulverized wet bottom.
The ages of oil-tangential-fired boilers and other oil-fired boilers were
practically the same, so the same growth rates were assumed for these
systems. Similarly, the ages of gas-tangential-fired boilers and other
gas-fired boilers were the same, so the same growth rate was assumed for
all gas-fired boilers.
351
-------
INDUSTRIAL
Fuel Use Trends
As is the case for the electric utility combustion sector, the forecast-
ing of developments in the industrial combustion sector is extremely dif-
ficult. The changing energy picture, the impact of government regula-
tions, and the availability of clean fuels all contribute to the high
degree of uncertainty involved in forecasting future development. Our
evaluation of industrial fuel consumption trends indicates an increase
from 1973 to 1985 of 14 percent within the categories discussed in this
study. Project Independence predicts that the total industrial energy
consumption (including direct heat, feedstocks and electrical energy)
will increase about 27 percent, with utility generated electrical energy
consumption by the industrial sector increasing nearly 100 percent based
on business as usual and an $ll/barrel price for imported oil. Industrial
fuel consumption trends are presented in Table 134.
Table 134. DETAILED INDUSTRIAL FUEL CONSUMPTION TRENDS TO 1985
2.0.00.0.0
2.1.00.0.0
2.1.10.0.0
2.1.11.0.0
2.1.12.0.0
2.1.13.0.0
2.1.20.0.0
2.1.30.0.0
2.1.41.0.0
2.1.42.0.0
2.2.00.0.0
2.2.20.0.0
2.2.30.0.0
Industrial
External Combustion
Coal
Bituminous
Anthracite
Lignite
Petroleum
Gas
Bagasse
Wood /Bark
Internal Combustion
Petroleum
Gas
1973
fuel use,
1012 Btu
11,300
8,546
1,370
1,320
10
40
1,700
5,200
20
250
2,760
360
2,400
1985
fuel use,
1012 Btu
12,934
10,016
1,945
1,899
2
44
2,448
5,200
23
400
2,922
518
2,400
Percent
change,
1973-19S5
+14
+17
+42
+44
-80
+10
+44
+ 0
+13
+60
+ 6
+44
+ 0
352
-------
In the industrial sector, the use of coal will increase over 42 percent.
This large increase may be attributable to the high price of oil and the
limited availability of natural gas. We estimate that industrial con-
sumption of lignite will increase only 10 percent, as several problems
are involved in utilizing lignite including: limited geographical dis-
tribution of deposits (primarily in North Dakota); shipping difficulties
associated with the large volume required as a consequence of the low
heating value of lignite; and combustion problems (lignite ash tends to
foul heat exchange surfaces). Utilities operating large power plants
can afford to solve lignite distribution and combustion problems. How-
ever, lignite consumption by industrial users will be limited primarily
by distribution problems from producing to consuming areas. Anthracite
consumption has been declining for decades and we adopted the Project
12
Independence estimate of 14 percent/year to 1985 or a total decline of
80 percent. Bituminous coal consumption will increase 44 percent with
the consumption of western subbituminous coal certainly increasing at a
greater rate than eastern coal. Subbituminous coal has drawbacks similar
to lignite although much less severe, and these drawbacks will be compen-
sated for by the low sulfur content. However, the increase in subbitumi-
nous coal consumption will be greater in the utility sector where unit
trains and other options, such as coal slurry pipelines and plant loca-
tion, can be implemented.
Petroleum consumption by the industrial sector will increase 44 percent.
Despite the high price of oil, many industrial consumers limited to choos-
ing between oil and coal will select oil. Oil-fired boilers and auxiliary
equipment are less expensive and easier to operate than coal-fired boilers,
Small energy users will show a particularly strong preference for oil as
the economics will tend to favor oil-fired equipment.
Natural gas resources are limited and a decline in industrial consumption
of 5 percent from 1972 to 1985 was predicted. However, consumption ac-
tually declined 5 percent from 1972 to 1973 so it was estimated that gas
consumption would remain constant from 1973 to 1985.
353
-------
Bagasse (a sugar cane by-product or waste material) is burned to produce
steam and/or electricity. Sugar cane production has fluctuated over the
past 10 years with no clear trends. A growth rate of 1 percent/year
for the combustion of bagasse was selected, yielding a total increase of
13 percent. Wood bark is burned extensively by the lumber and paper in-
dustry, with large amounts consumed in Washington and Oregon as well as
some areas in the south. The lumber industry is expected to grow at a
30
4 percent rate and the paper industry at a 3.6 percent rate to 1980.
In addition, all available waste wood materials are not utilized and the
29
percent utilization will probably increase. A
bark combustion of 4 percent/year was estimated.
29
percent utilization will probably increase. A growth rate for wood
Specific data on fuel use trends for internal combustion equipment were
not available. Overall fuel use trends were applied to the industrial
internal combustion sector.
Trends in Boiler Population
The limited trend data available on those boiler characteristics con-
sidered in this project do not show definitive and significant trends.
We estimate that boiler characteristics in 1985 will be similar to 1973,
and the major changes will be the fuel use trends presented in Table 134.
The growth of particular boiler types should be the same as the growth
of the overall fuel type. Thus, industrial coal-fired boilers will continue
to be predominantly pulverized (57 percent of coal consumed) and spreader
stokers (36 percent of coal consumed). More than 79 percent of the coal
burned in industrial boilers is burned in boilers above 100 x 10 Btu/hr
capacity. These large boilers will continue to be predominantly pulver-
ized coal-fired and spreader stokers although the prevalence of pulverized
coal firing may increase slightly. The smaller boilers (less than
100 x 10 Btu/hr) are primarily underfeed stokers at the present time, but
there is a trend toward more spreader stokers.
354
-------
COMMERCIAL/INSTITUTIONAL
Fuel Use Trends
The commercial sector consumed 12 percent of the fuel consumed by sta-
.tionary combustion sources in 1973 (see Table 129). Commercial fuel was
primarily oil and gas with only minor amounts of coal. Only 1.5 percent
of the coal consumed was consumed by the commercial sector, and coal rep-
resented only 3.4 percent of the commercial sector fuel use. The avail-
able trend data do not distinguish between the commercial sector and the
residential sector, instead both sectors are combined. Our estimates of
commercial fuel consumption trends were based on the assumption that fuel
trends are the same for both sectors. Commercial fuel use trends are
presented in Table 135. The data ;
$ll/barrel price for imported oil.
presented in Table 135. The data are based on business as usual and an
Coal consumption by the commercial residential sector will decline 55 per-
cent from 1973 to 1985. Anthracite consumption will decline sharply in
all consuming sectors. The decline in the commercial sector will be
12
80 percent. Lignite is an extremely minor commercial fuel (represent-
ing only 0.02 percent of commercial fuel) and we estimated no change in
consumption. A decline in bituminous coal consumption of 43 percent from
1973 to 1985 was estimated. The decline in coal consumption is partly
attributable to the convenience of oil and gas for the many small com-
mercial consumers of fossil fuels. However, commercial consumption of
12
oil is predicted to decline 16 percent from 1973 to 1985. Natural gas
is the only commercial residential fuel that is expected to be consumed
in sharply larger quantities by 1985. The change by 1985 is expected to
12
be an increase of 47 percent. Wood is a ver;
no change in consumption to 1985 is estimated.
12
be an increase of 47 percent. Wood is a very minor commercial fuel and
Commercial internal combustion sources are primarily engines used for
water pumping and possibly generating small amounts of electricity. The
355
-------
Table 135. COMMERCIAL/INSTITUTIONAL FUEL USE TRENDS, 1973-1985
3.0.00.0.0
3.1.00.0.0
3.1.10.0.0
3.1.11.0.0
3.1.11.1.0
3.1.11.2.0
3.1.11.4.0
3.1.12.0.0
3.1.12.4.0
3.1.12.6.0
3.1.13.0.0
3.1.13.4.0
3.1.13.6.0
3.1.20.0.0
3.1.21.0.0
3.1.21.0.1
3.1.21.0.2
3.1.22.0.0
3.1.22.0.1
3.1.22.0.2
3.1.30.0.0
3.1.30.0.1
3.1.30.0.2
3.1.42.0.0
3.2.00.0.0
3.2.20.0.0
3.2.30.0.0
Commer c ial / Ins t .
External Combustion
Coal
Bituminous
Pulverized Dry
Pulverized Wet
All Stokers
Anthracite
All Stokers
Spreader Stokers
Lignite
All Stokers
Spreader Stokers
Petroleum
Residual Oil
Tangential Firing
All Other
Distillate Oil
Tangential Firing
All Other
Gas
Tangential Firing
All Other
Wood /Bark
Internal Combustion
Petroleum
Gas
1973
fuel use,
1012 Btu
4450
156
101
20
1
80
55
55
0
1
1
0
2379
1269
10
1259
1110
11
1099
1914
82
.1832
1
50
25
25
1985
fuel use,
1012 Btu
4883
70
58
11
<1
46
11
11
0
1
1
0
1998
1066
8
1058
932
9
923
2814
121
2693
1
58
21
37
Percent
change,
1973-1985
+10
+10
-55
-43
-43
-43
-43
-80
-80
0
0.
0
0
-16
-16
-16
-16
-16
-16
-16
+47
+47
+47
0
+16
-16
+47
356
-------
trends for internal combustion were estimated to be the same as the par-
ticular fuels used.
The summation of the above trends, as presented in Table 135, indi-
cates a growth in commercial fuel consumption of 10 percent. Overall
energy consumption by the commercial sector is expected to grow 40 per-
cent, mainly due to a 260 percent increase in electric energy consump-
tion. The most significant point in the commercial fuel use trends is
that only natural gas consumption will increase, and it will increase
sharply (47 percent).
Trends in Boiler Population
Trends in boiler population were assumed to be the same as the fuel use
trends. Data on trends for the specific categories considered in this
project were not available.
RESIDENTIAL
Residential space heating has shown an annual growth rate of 3.4 percent
•30
over the period 1960 to 1968. The estimated fossil fuel consumption
for 1973 (Table 129) shows an increase of 15 to 20 percent from 1968 and
that the historical trend has continued through 1973.
Estimated residential fuel use trends, as shown in Table 136, are based on
Project Independence projections for the commercial-residential sector.
As previously discussed, the Project Independence estimates were based
on business as usual and an $ll/barrel price for imported oil. It was
assumed that the fuel use growth rates were the same for both the com-
mercial and residential sectors.
357
-------
Table 136. RESIDENTIAL FUEL USE TRENDS, 1973-1985*
4.0.00.0.0
4.1.00.0.0
4.1.10.0.0
4.1.11.0.0
4.1.12.0.0
4.1.13.0.0
4.1.20.0.0
4.1.30.0.0
4.1.42.0.0
Residential
External Combustion
Coal
Bituminous
Anthracite
Lignite
Petroleum
Gas
Wood
1973
fuel use,
1012 Btu
8,057
8,057
192
115
75
2
2,280
5,450
135
1985
fuel use,
1012 Btu
9,258
9,258
86
69
15
2
1,026
8,011
135
Percent
change,
1973-1985
+15
+15
-55
-40
-80
0
-55
+47
0
fj
Space heating only. Trends primarily from reference 7.
Fuel use for space heating is expected to increase 15 percent from 1973 to
1985. The growth rate will be 1.2 percent/year compared to the historical
growth rate of 3.4 percent/year. However, when electric energy is in-
cluded, the total energy growth rate for the residential sector will be
3 percent/year,• which is only slightly below the historical trend.
Natural gas is the major residential space heating fuel (68 percent) and
its share of the residential sector will be even larger in 1985 (88 per-
cent). Coal is only a very minor residential fuel (3 percent) and its
consumption will be even less in 1985 (about 1 percent of residential
fuel use). Although there has been an increased interest in the com-
bustion of wood for space heating, we estimate that there will be no real
growth in this area.
SIGNIFICANCE OF TRENDS
Changes and trends in total energy consumption and fuel use patterns have
the potential to affect the amounts and types of air, water and solid
waste pollutants. In addition, the trends discussed in the previous
358
-------
subsections will affect the design,and application of combustion equipment,
air pollution control methods (particulate, SO^ and N(y and water pollu-
tion control methods as well as solid waste practices. The actual future
pollutant quantities will be strongly affected by government regulations.
The most significant trend in the overall picture is the large (87 per-
cent) increase in coal consumption. Increased coal consumption is due
to normal growth and the limited growth of oil (~2 percent) and gas
(+13 percent). Coal combustion tends to generate over 50 times as much
ash and most trace metals (either as an air pollutant or solid waste),
about twice as much NO , and three times as much SO (based on current
average levels of 1 percent sulfur oil and 2 percent sulfur coal) as oil
combustion. With the exception of NO , pollutants generated by gas com-
X
bustion are insignificant compared to those generated by coal combustion.
The impact of ash emissions can be minimized by control equipment. NO
X
emissions from coal can be reduced to levels associated with gas and oil.
SO emissions can, of course, be controlled through the use of low sulfur
X
fuels or SO scrubbers. Scrubbers do create potential water pollution
and solid waste problems.
The significance of increased coal combustion will be amplified in the
electric utility sector where coal consumption is expected to increase
100 percent while oil and gas decline sharply - 10 and 30 percent, re-
spectively. In addition, coal represents over 50 percent of utility fuel
use compared to only 25 percent of the total stationary source fuel use.
The combustion of refuse will show the largest percent change (6000) but
will only be of local significance, as even by 1985, it will represent less
than 0.2 percent of electric utility fuel use. Practically, all electric
utility plants will be subject to Federal and State air and water pollu-
tant regulations. Air and water pollution control measures will play a
large role in the design of new coal-fired power plants. The use of low
sulfur western coal may reduce the apparent need for S02 scrubbers.
However, the use of western coal may adversely affect particulate control
equipment.
359
-------
In the industrial sector the 'use of both coal and oil will increase
40-45 percent while the use of gas will remain constant. As industrial
coal consumption represents only 16 percent of utility consumption, the
increase will be less stringent. However, the overall shift from gas
(zero growth to 1985) will be very significant, tending to increase pollu-
tant quantities.
The majority of pollutants generated by the commercial/institutional
sector will decrease as only the use of natural gas will increase. The
large decrease (55 percent) in coal combustion in the commercial sector
will be of minimum importance as coal is a very minor commercial fuel.
Wood/bark and refuse combustion will increase and may be important in
specific geographic areas.
Residential fuel use trends will be the same as commercial trends and
thus the significance will be similar. However, the decrease in coal
combustion may be important, as the majority of the coal is consumed in
a relatively few states, and the ambient levels of organics (BaP and BSO)
33
have correlated well with residential coal consumption trends.
360
-------
REFERENCES
.1. Ford Foundation. A Time to Choose, America's Energy Future.
Cambridge, Massachusetts. 1974.
2. Federal Power Commission. FPC News. Washington, B.C., June 6, 1975.
3. Ford Plan May Boost Gas Prices. Boston Globe. July 13, 1975.
4. FEA Ordering Many Boilers to Burn Coal Instead of Oil Power. Federal
Energy Administration. July 1975.
5. Ford Veto Expected in Oil Fight. Boston Globe. August 15, 1975.
6. National Academy of Engineering. U.S. Energy Prospects: An En-
gineering Viewpoint. Washington, D.C. 1974.
7. Federal Energy Administration. Project Independence. Washington,
D.C. November 1974.
8. Dupree, W., Jr. and J.A. West. United States Energy Through the
Year 2000. U.S. Department of the Interior. December 1972.
9- Federal Power Commission. Staff Report on Electric Utility Expan-
sion Plans. Washington, D.C. June 1974.
10. U.S. Department of the Interior. Energy Perspectives. February 1975.
11. U.S. Bureau -of Mines. Mineral Facts and Problems. Washington, D.C.
1970.
12. Federal Energy Administration. National Energy Demand Forecasts
(Draft Report), Washington, D.C. August 5, 1974.
13. Plant Design Report. Power. November 1974.
14. Federal Energy Administration. FEA Project Independence Blueprint
Final Task Force Report - Coal. Washington, D.C. November 1974.
15. Abelson, P.H. Absence of U.S. Energy Leadership. Science.
July 4, 1975.
16. U.S. Bureau of the Census. Statistical Abstracts of the United
States: 1974. 95th Edition. Washington, D.C. July 1974.
17. U.S. Bureau of the Census. Statistical Abstracts of the United
States: 1965. 86th Edition. Washington, D.C. July 1965.
18. Federal Power Commission, FPC News, Washington, D.C. June 6, 1975.
361
-------
19. Shannon, L.J., M.P. Schrag, F.I.. Howe, A.D. Bendersky. St Louis/
Union Electric Refuse Firing Demonstration Air Pollution Test
Report. Midwest Research Institute. Prepared for U.S. Environ-
mental Protection Agency, Research Triangle Park, North Carolina.
Publication Number EPA-650/2-74-073. August 1974.
20. Klumb, D.L. Union Electrics Solid Waste Utilization System.
Presented at the 1974 Air Pollution Control Association Conference.
21. Bureau of National Affairs. Refuse. Environmental Reporter.
March 14, 1975..
22. Schweigen, R.G. Power From Waste. Power. February 1975.
23. Environmental Protection Agency. Emissions From Coal-Fired Power
Plants. Publication Number AP-35. 1967.
24. Jimeson, R.M., R.S. Spinot. Pollution Control and Energy Needs.
American Chemical Society. Washington, D.C. 1973.
25. Magee, E.M., H.J. Hall, and G.M. Vanga. Potential Pollutants in
Fossil Fuel. U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina. Publication Number EPA-R2-73-249. June 1973.
26. Standards of Performance for New Stationary Sources. Federal
Register. 36(247). December 23, 1971.
27. Preliminary Edition of Supplement 5 to Compilation of Air Pollution
Emission Factors. U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina. Publication Number AP-42. April 1975.
28. Technology and Use of Lignite. Proceedings: Bureau of Mines -
University of Norfh Dakota Symposium, 1973. Bureau of Mines Publica-
tion IC8650. Washington, D.C. 1974.
29. Personal Communication, R.E. Hall, Combustion Research Section,
Industrial Environmental Research Laboratory, Research Triangle
Park, N.C. October 1975.
30. Federal Energy Administration. The Potential for Energy Conserva-
tion in Nine Selected Industries. Volume 8. Washington, D.C. 1975.
31. Locklin, D.W. et al. Design Trends and Operating Problems in Com-
bustion Modification of Industrial Boilers. EPA-650/2-74-032,
Research Triangle Park N.C. April 1974.
32. 1970 Census of Housing, "Detailed Housing Characteristics," HC-B
series. U.S. Department of Commerce, Bureau of Census,
Washington, D.C. 1970.
33. Faero, R.B. Trends in Concentrations of Benzene Soluble Suspended
Particulate Fraction and Benzo(a)pyrene. JAPCA, 24(6). June 1975.
362
-------
SECTION VII
ON-GOING AND PLANNED ACTIVITIES
This section, summarizing on-going and planned activities, is based on a
review of current EPA contracts, the use of information retrieval services,
and contact with industrial and trade organizations concerned with emis-
sions from conventional stationary combustion sources. Because of the
magnitude of the task, omissions undoubtedly have occurred.
The major emphasis of previous studies dealing with the emissions
assessment of combustion sources has been placed on air emissions, and
their control, from electric utility plants. These air emissions and con-
trol data are, in part, embodied in the National Emissions Data System
(NEDS). However, existing NEDS emission factors, while generally good
to ± 25 percent for criteria pollutants, are based on limited test data
generally dating back to the 1960's. Updating of these emission factors,
particularly for those combustion systems which predominate, should be
and is being undertaken to an increasing extent. There is also a need
for expansion of NEDS to include potentially hazardous pollutant emissions,
and a new data handling system (HATREMS) is being developed for this
purpose.
Although combustion source test data dealing with air, water, and solid
waste emissions are being collected at an ever increasing rate, most of
this information is not available in a central location for further analy-
sis. Much of it is collected by utilities or industrial firms concerned
with compliance with state or federal regulations. A centralized EPA
system, Source Test Data System (SOTDAT), has been developed to assemble
363
-------
air emission data which can be used to determine accurate emission fac-
tors for criteria or other pollutants and evaluate control device per-
formance, but remains to be effectively implemented. A major shortcoming
of this system, however, is its reliance on Source Classification Codes
(SCC) to identify the combustion systems. The Source Classification Code
falls short of identifying all furnace and boiler characteristics which
can affect emissions.
Water emission data for most utilities and large industrial sources are
available in the National Pollution Discharge Elimination System (NPDES) .
This information, however, is scattered throughout the various EPA regions
and has not been fully assembled and analyzed. Limited information on
cooling water, boiler water blowdown, and ash pond discharge is available
also for electric utilities from the FPC. The FPC is also a source of
information for solid waste from ash and boiler water blowdown.
Table 137 lists the organizations that were contacted for information
concerning on-going and planned activities. In addition, numerous EPA
contractors were contacted. The identification of on-going activities
sponsored by EPA was a difficult task since only project titles were
readily available. Thus, some confusion exists with regard to specific
program objectives and emphasis, and some pertinent programs may not have
been included. It should be noted that a good indication of participa-
tion in on-going activities can probably be made by a perusal of refer-
ences provided in this text. Companies which have contributed to past
programs are most likely still engaged in similar study areas, and their
noninclusion within this section probably represents errors of omission.
The following discussions will highlight the present emphasis now being
placed on the environmental aspects of stationary combustion sources.
Companies and organizations now engaged in these activities will be iden-
tified, a brief abstract of program objectives will be presented, and
364
-------
Table 137. SUMMARY OF PERSONAL COMMUNICATIONS'
Organization
1. American Boiler Manufacturers Association
2. American Petroleum Institute
3. American Society of Mechanical Engineers
4. Eabcock and Ullcox
5. Batteile Colun.bus
6. Battelle Northwest
7. Betz Laboratories
3, h'ireau of Mines
9. Ci.arUs T. Main
10. Ccrbust ion engineering
11, Ldis^n Electric Institute
12. Electric Pcwer i'.osearch Institute
13. Energy Research and Development Administration
14. Exxun Corporation
15. Federal Energy Administration
Office of Fuel Utilization
Environmental Branch
F.e3''urce Developr.ent
Industrial Technology
16. Federal Power CorjBission
17. Foster Wheeler
13. University of Colorado
19. University of Illinois
20. University of Maryland
21. University of Notre Dams
22. Hit:ran Associates
23. Institute of Can Technology
2i. KVS
25. Massachusetts Institute of Technology
26. National Academy of Sciences
27. t.at io;vil Coal Association
23. NUS Corporation
29. Oak P.u!;',e National Laboratory
30. Saratoga Associated
31. Tennessee Valley Authority
32. U.S. KnvLronnu-ntal Protection Agency
Office of Solid Waste Mmagcment, Washington, D.C.
Office of Planning anil Management, Washington, D.C.
ICRI,, Research Triangle I'ark, N.C.
llier:..il Pollution Section, Corvailis, Oregon
Hazardous Waste Research Laboratory, Cincinnati
SOT DAT
Source Testing
Person contacted
William Axtiiwm
Krnie ditton, Walter Illsteaii
I'aul Colilsteln
Thomas MrN.iry, Nick Brovitch
W.irrt'ii Uerry
Heu .!.ihn:;ot\, Robert Dillon
.loo Sluu-k
X.ane Murphy, I..L. Fanelli, lly Schultz
George Kru!u-n
I'.iul llry.mt, Peter llavitch, Fred llanzalek
Dirk Thor.sell, Cordon Olsen, Bob Palladino, Steven Barusch
CurL Yi'aj'.er, H.irry Kornlierg, Tom'Castle, Don Anson
Paul Jiinlan, Richard Corey, Howard Smith
W. Dartok
Judy l.ersli, Susan Phillips, John Deane
Ki-n WtiodiN.'ck
111 11 Porter
Ken I- reela hie
Bob .1 fitsicson , Alex Catnur
Henry Phillips
J, Ka;ikinen
U. Natuscli
n. Gordim, W. Zoller
T. Tin-is
Doug Harvey
Frank Srhora
Dick Tlioiiipson
I.. Cl l<-k':ni.in. Dr. Havleman, Dr. Jirka
llunry Barker (Ind. Boilers), Bob Crozier (Utilities), Earl Evans, Ted Schad (Env. Studies)
Joe Mullens
D.I-.. Simon
ilill FulK'rsrm
D.III Wxzt-ik (Power Plant Siting)
U.C. Ni-Kinney, Bill Fulkerson
Koheit Lowe, M;irsha Evarston, D, Sussman, Robert Holloway
J im S|)i re
Hoberl Hall , I.es Sparks
Frank itaiawater
Mike Run Her
(Ireg liujewskl
lid McC.iuU-y
alhls table is a summary of organizations and people contacted during this project as part of the effort of outlining neu projects as well as
the effort to obtain recent research unJ develu;inont data. Additional organizations were contacted and are mentioned throughout the report.
GCA/Technology is in continual contact with many lil'A personnel and I'.I'A rxnt raciors,- and trade, organizations, and did not list all these people,
-------
the responsible personnel involved will be identified whenever possible.
Discussions are presented for the following areas of activities which
include all the major unit operations contributing to emissions:
e Combustion
0 Flue Gas Emissions
General
Particulate
Criteria Pollutants (Cases)
Polycyclic Organic Materials
Trace Elements
a Ash Handling
« Cooling Systems
0 Boiler Water Treatment
9 Fuels and Fuel Handling
9 Flue Gas Desulfurization
o Particulate Control Devices.
Many programs, of course, are concerned with several of the areas listed.
These programs are included in a general category or are listed in what
was felt to be the area of most significant interest.
COMBUSTION
Activities in the combustion area are concerned with the design of new
furnaces, boilers, or internal combustion engines, or the modification
of existing units to improve combustion efficiency, lower pollutant
levels, or to allow the burning of different fuels. An improvement in
combustion efficiency can either reduce pollutant emissions (e.g., HC,
CO, POM) or increase them (e.g., NO ).
X
The design of combustion units is an activity that is largely carried
out by industrial manufacturers or trade organizations such as the
Electric Power Research Institute, the American Gas Association, the
366
-------
American Petroleum Institute, etc. However, their activities are to
some extent directed by existing and proposed emission regulations which
have been responsible, for example, for many developments in the design
of combustion units to meet NO regulations.
-Jv
Many of the programs are concerned with the use of synthetic fuels
(solvent refined coal, low or high Btu gas, etc.) through the design of
advanced combustors or the modification of existing units. Others are
concerned with new combustion concepts such as magnetohydrodynamic power
generation. These aspects of combustion are not included in Table 138,
which lists on-going and planned conventional combustion studies, the
supporting agency and contractor, the project manager, and a brief ab-
stract of the program. Additional combustion studies, aimed at control
of specific pollutants, will also be found in other appropriate
subsections.
367
-------
Table 138. ON-GOING AND PLANNED ACTIVITIES: COMBUSTION
Title:
Contract No.:
Boiler Firing Test with Coal/Oil Emulsion
RP 527
Supporting Organization: EPRI
Performing Organization: General Motors
Principal Investigator:
Project Description:
Unknown
The objective of this 1-year project is to
test an 80,000 Ib/hr steam plant, firing a
coal/oil emulsion fuel. The test will assess
the stability of the fuel, thermal performance,
stack emissions, ash removal, fouling and slag-
ging characteristics, and economic feasibility.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Engineering Evaluation of Atmospheric Fluidized
Bed Combustion (AFBC)
RP 412
EPRI
Babcock and Wilcox
Unknown
The objective of this 16-month program is to
evaluate the adequancy of available informa-
tion for commercialization of the AFBC process.
The program includes a study of existing de-
signs of uitlity boilers using FBC.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Boiler Combustion Modifications
68-02-1415 (EPA), RP 200 (EPRI)
EPA and EPRI
Exxon Research and Engineering Company
W. Bartok
U.S. Environmental Protection Agency and EPRI
are jointly funding a program to determine the
effectiveness of combustion modification tech-
niques to control pollutant emissions from
utility boilers. Pollutants of interest are
oxides of nitrogen, sulfur dioxide, hydrocar-
bons, carbon monoxide, and combustible and non-
combustible particulates. The project will be
completed by May 1977.
368
-------
Table 138 (continued). ON-GOING AND PLANNED ACTIVITIES: COMBUSTION
Title:
Contract No. :
Advanced Gas Turbine Development
RP 359
Supporting Organization: EPRI (D. Texeira)
Performing Organization: Solar Div. of International Harvester
Principal Investigator: Unknown
Project Description:
This 15-month program will develop a combustion
process for conventional fuels to minimize for-
mation of NOX, carbon monoxide, and unburned
hydrocarbons from gas turbines while maintain-
ing satisfactory performance parameters.
Scheduled to be completed by June 1976.
Title:
Contract No. :
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Gas Turbine-Steam Boiler Repowering
RP 528
EPRI (D. Texeira)
Westinghouse Electric Corporation
i-
Unknown
Results of this 1-year project will include
heat balances, required modifications, and cost
estimates for a representative (ca. 300 MW)
steam boiler. Principal fuels to be treated in
the study are natural gas and fuel oil. Sev-
eral plants utilizing the heat in gas turbine
exhaust gases have been constructed and oper-
ated for over 10 years. However, these plants
were "grass roots" installations, and not re-
powered systems. The utilization of the hot
turbine exhaust (ca. 1000°F) in retrofit appli-
cations poses unique problems. NOX reduction
is expected. Scheduled to be completed by
August 1976.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Effects of Mixing on Kinetic Processes in
Pulverized Coal Combustion
RP 364
EPRI (R. Carr)
Brigham Young University
Dr. L. D. Smoot
369
-------
Table 138 (continued). ON-GOING AND PLANNED ACTIVITIES: COMBUSTION
Project Description:
This 38-month project will employ a small lab-
oratory combustor to determine the effect of
turbulent mixing on the kinetics of pulverized
coal and char combustion at atmospheric pres-
sure. Scheduled to be completed by December
1977.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Combustion Dynamics as Related to Air Pollution
BR - 26 - 1
AGA
University of Michigan
Unknown
An analytical and experimental study of pollu-
tants resulting from the combustion of natural
gas.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Design and Scale-Up of Low Emission, High
Efficiency Boilers
68-02-1488
U.S. EPA (G. B. Martin)
Ultra Systems Inc.
M. Heap
Title: Combustion Process Analysis
Contract No.:
Supporting Organization: U.S. EPA
Performing Organization: University of Wisconsin
Principal Investigator: H. K. Newhall
Project Description:
Work related to NOX and particulate formation
in diffusion flames.
370
-------
Table 138 (continued). ON-GOING AND PLANNED ACTIVITIES: COMBUSTION
Title:
Contract No.:
Supporting Organization:
Performing Organization;
Principal Investigator:
Project Description:
Field Testing - Application of Combustion Modi-
fications to Control Pollutant Emissions from
Industrial Boilers
68-02-1074
U.S. EPA (R. E. Hall)
KVB Engineering, Inc.
.G. A. Cato, D. R. Bartz, C. Devito, B. G. Morton,
and L. J. Muzio
A determination of NOX and other pollutants
emitted by industrial boilers and a study of
control measures through testing of about 70
boilers.
371
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FLUE GAS EMISSIONS - GENERAL
This subsection discusses programs which involve the characterization
of flue gas emissions in general from combustion sources rather than
emphasizing the measurement of a specific pollutant. An attempt has
been made to determine the thrust of specific programs and to list
them under appropriate pollutant subsections. The programs listed in
Table 139 are studies which involve an overall characterization of
emissions, including in many cases hazardous and trace material.
372
-------
Table 139. ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS EMISSIONS - GENERAL
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Systems Evaluation of the Use of Low Sulfur
Western Coal in an Existing Small and Inter-
mediate Size Boilers
68-02-1863
U.S. EPA (D. G. Lachapelle)
KVB Engineering Inc.
K. L. Maloney
KVB will survey and compile information on
small and intermediate size boilers, emphasiz-
ing those that can burn western coal. Detailed
emissions.and performance tests will be con-
ducted on selected boiler/fuel combinations in-
cluding both eastern and western coal. Sched-
uled completion is October 1977.
Title:
Contract No.:
Stationary Source Assessment Documents
68-02-1320
Supporting Organization: U.S. EPA
Performing Organization: Monsanto Research Corporation
Unknown
Principal Investigator:
Project Description:
In-depth environmental assessment on air emis-
sions from combustion and other sources.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Modeling of Air Quality Impact of Selected
Power Plants
68-02-1480
U.S. EPA (Hears)
Walden Research, A Division of Abcor
P. Morgenstern
373
-------
Table 139 (continued). ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS EMISSIONS - GENERAL
Title: Field Testing of Industrial Sources
Contract No.:
Supporting Organization: U.S. EPA
Performing Organization: Monsanto Research Corporation
Principal Investigator: W. R. Feairheller
Project Description: This 3-year program involves the testing of
28 or more sources for mercury, acid mist,
fluoride or lead and many gaseous materials.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Domestic and Commercial Heating
U.S. EPA
EPA, IERL, RTP
R. E. Hall
A study of the effect of operational variables
and boiler components to determine particulate
and NOX emissions from residential and commer-
cial heating equipment using oil or gas as a
fuel. A complete investigation will be made of
boiler types, burners, and fuels used in com-
mercial heating to select typical units for
future testing.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Characterization and Control of Air Pollutant
Emissions from Combustion of Fuels
U.S. EPA
EPA, IERL, RTP
G. B. Martin
A 5-year study of air pollutants from all fuels
and their potential for control using appropri-
ate combustors under controlled laboratory
conditions.
374
-------
Table 139 (continued).
ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS EMISSIONS - GENERAL
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Effluents from Coal-Fired Power Plants and
Their Interaction with the Atmosphere
RP 330
EPRI
University of Washington
Unknown
A 3-year program to characterize emissions from
the Centralia, Washington, 1400 MW coal-fired
power plant. Stack and plume measurements of
particulates (particle size) and gaseous
pollutants.
Title:
Contract No. :
Performing Organization:
Principal Investigator:
Project Description:
Determination of the Feasibility of Ozone
Formation in Power Plant Plumes
RP 572
Supporting Organization: EPRI
Meteorology Research, Inc.
Unknown
This 8-month project will determine the
extent of ozone formation in power plant
plumes. Research will include a literature
survey, airborne plume monitoring at several
coal- and gas-fired power giants in dry
and humid regions of southern and south-
western United States, and development and
validation of a plume chemistry computer model,
Title:
Contract No. :
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Atmospheric Dispersion and Interaction of
S02, H2S04, NO
X,
and Particulates of
Stack Emissions from Coal-Fired Power Plants
U.S. EPA
TVA
T. L. Montgomery
A Study of emissions as determined by plant
operations and the changes in composition
which occur as a function of time.
375
-------
Table 139 (continued). ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS EMISSIONS - GENERAL
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Fossil Fuels, General Combustion, Environmental
Exxon Corporation
Exxon Corporation
N. Alpert
R&D leading to novel processes and techniques
for cleaner combustion of fossil fuels. In-
cludes control of SOX, NOX, particulates, noise,
odor, etc.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Technology Assessment and Planning Support
U.S. EPA
Aerospace Corporation
J. Meltzer
Characterization of emissions from sources and
their relevant control technology, evaluate
their effect on ambient air quality and identify
control technology gaps.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Emissions from Major Air Pollution Sources and
Their Atmospheric Interactions
U.S. National Science Foundation
University of Maryland
G. E. Gordon
376
-------
FLUE GAS EMISSIONS - PARTICULATES
The measurement of particulate emissions from electric utilities has been
an active area for many years and the data reported is probably good to
within ± 25 percent despite variations in test procedures. The present
activity is being carried out by many testing and utility firms inter-
ested in compliance testing. EPA is also conducting or sponsoring test
programs aimed at evaluating the effects of fuel, boiler design, and
control device performance. In recent years the emphasis has shifted
from the measurement of total particulate to a determination of fine par-
ticle distributions and the emissions of potentially hazardous trace me-
tals and organic materials. The interest in fine particulates basically
stems from their respirable nature and the tendency of many hazardous spe-
cies to be concentrated in the fine particle fraction. Activities dealing
with these hazardous emissions will be discussed later in appropriate
subsections.
An extensive analysis of particulate emissions has been carried out by
Midwest Research Institute (MRI). At the time of the initial study,
MRI estimated that most particle size data had been obtained by tech-
niques unsuitable for sampling and sizing particulates below 2 microns
in diameter. Accordingly, it was necessary to extrapolate data for large
particles down to the size range of fine particulates. A subsequent re-
vision of this study is based on recent tests using cascade impactors to
determine size distributions and the fractional efficiency of control
devices down to about 0.2 microns. Recent and on-going studies have
adopted the use of impactors to determine fine particulates, and several
companies including SRI, KVB, and GCA have used condensation nuclei
counters to measure particles as small as 0.01 micron diameter.
377
-------
EPA at Research Triangle Park is currently undertaking studies aimed at
the overall fine particulate problem, including health effects, formation
and transformation, source identification, measurement, and control.
Proposed activities involve further characterization of emissions from
combustion sources and the evaluation of novel control devices.
Although somewhat beyond the scope of this program, there is a strong
interest now in the behavior (and formation) or particulates leaving the
stack. Plume reactions and subsequent transformation and transport phe-
nomena are now being studied by several research organizations. Aircraft
are being used by organizations such as Washington University, St. Louis,
Missouri, and Brookhaven National Laboratories, New York, to monitor
emissions downwind-of a coal-fired utility boiler and an oil-fired util-
ity boiler stack, respectively.
Current programs dealing with particulates are listed in Table 140. This
listing is a brief one, since many of the current activities are to be
found in preceding subsections and in subsequent subsections dealing with
trace elements, POM, and control devices.
378
-------
Table 140. ON-GOING'AND PLANNED ACTIVITIES: FLUE GAS
EMISSIONS - PARTICULATES
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Development of an In-Stack Impactor/Precipita-
tor for Sizing Submicron Particles
RP 463
EPRI
Meteorology Research, Inc.
Unknown
Development of an electrostatic impactor with
a particulate size analysis range from 0.03-30
microns would serve at least two functions.
It would enable utilities to completely charac-
terize the fly ash emissions at a specific site,
thereby eliminating some of the guesswork in
purchasing particulate cleanup devices. Also,
it would permit the characterization of par—
ticulate removal devices at the time of check-
out to ensure that the devices meet system
guarantees. Scheduled to be completed by March
1976.
Title:
Contract No. :
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Particle Formation in High Temperature Systems
Public Service Co. of New Hampshire
University of New Hampshire
G- D. Ulrich
A correlation of fly ash properties from com-
mercial coal- and oil-fired boilers as a func-
tion of fuel composition and time-temperature
history.
379
-------
FLUE GAS EMISSIONS - SULFUR OXIDES
There is general agreement that almost all (-90 percent) of the sulfur
contained in the fuel is emitted from the stack. This is generally true
for all fuels with the exception of some high mineral content fuels such
as certain lignites which can bind and retain up to 50 percent of the
sulfur in the ash. Therefore, the emphasis has been on research to either
eliminate the sulfur prior to combustion or to control its emissions by
flue gas desulfurization.
There is general agreement that most of the sulfur oxides emitted are
largely S0? (-98 percent). However, some SO is emitted directly. In
general, the leaner the fuel mixture, the more SO is formed. SO forma-
tion is also a function of boiler design and method of firing. Smaller
furnaces, such as those used in the commercial and residential sectors,
emit more SO relative to SO than do larger size installations. The
reported emissions of SO are reportedly higher for oil than for coal,
and oil combustion has been postulated as a major source of acid mist
which is found in high concentrations in the oil-burning eastern states.
The importance of SO,, emissions is highly speculative since the entire
question of SO,-, atmospheric transformation'and transport is still largely
unresolved. Further work in this area is needed. Instrumentation and
measurement techniques for S0?, sulfates and sulfuric acid are areas also
requiring additional study.
Table 141 lists a few pertinent studies with only one involving the
determination of sulfur distribution within a power plant.
380
-------
Table 141. ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS EMISSIONS - SO
Title:
Contract No,:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Sulfur Balance Study
New York Electric and Gas Corporation
Battelle Memorial Institute
Unknown
A study to determine sulfur losses in a coal-
fired power plant. Sulfur losses will be
determined during pulverized coal firing and
distributions determined in fly ash, bottom
ash, and fireside deposits.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Sulfur Dioxide Oxidation Rate in Oil-Fired
Power Plant Plumes
RP 382
EPRI
State University of New York, Albany
Unknown
The oxidation of S02 on solid surfaces will be
studied in the laboratory, using molecular beam
techniques. Reaction products and rates will
be determined by mass spectrometry and Auger
spectroscopy on a variety of well-characterized
surfaces. Pure metal/metal oxides, and even-
tually carefully studied fly ash from oil-fired
power plants will be used.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Preliminary Assessment of Sulfate Emissions
from Space Heating and Other Small Combustion
Devices
RP 574
EPRI
KVB Engineering Inc.
Unknown
381
-------
Table 141 (continued).
ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS EMISSIONS - SO
x
Project Description:
The primary task of this 4-month project is to
measure sulfur dioxide and sulfates in flue
gases of operating residential space heating
and other small boilers in New York City. In
addition, a limited literature survey on sulfur
oxide conversion mechanisms in fossil-fueled
boilers and examination of sulfur dioxide and
sulfate data in New York City for the last 10
years will be performed.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Interaction of Sulfuric Acid Mist and Nitrogen
Dioxide
RP 201
EPRI, National Coal Association
Hazelton Laboratories, Inc.
Unknown
For several years Hazelton Laboratories, Inc.
has been conducting a study to determine the
physiological effects on monkeys and guinea
pigs of various concentrations of sulfur diox-
ide, sulfuric acid mist, and fly ash, and their
mixtures. This recent effort addresses the
possible interaction between sulfuric acid mist
and nitrogen dioxide. Since these two pollu-
tants rarely occur at levels known to be haz-
ardous to humans, reported detrimental effects
in humans may be due to combined action of the
pollutants.
382
-------
FLUE GAS EMISSIONS - NO
2l
The reduction of NO emissions from combustion sources is an active area
X
of study. Programs are underway in such areas as collecting basic kinetic
data concerning fuel conversion and decomposition effects, boiler modifica-
tion and variation in operating parameters (staged combustion, low excess
air, flue gas recirculation, etc.) on emissions, and noncombustion con-
trol measures such as catalytic stack gas removal, scrubbing, and alter-
natives to water injection (turbines). Table 142 lists some of these
projects.
383
-------
Table 142. ON-GOING'AND PLANNED ACTIVITIES:
FLUE GAS EMISSIONS - NO..
Title:
Bench Scale Studies of New Scrubbing Techniques
for the Abatement of NOX
Contract No.:
Supporting Organization: U.S. EPA \
Performing Organization: U.S. EPA
Principal Investigator: L. H. Garcia
Project Description:
The objective is to screen a variety of processes
for the abatement of NO emissions
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Analysis of Flue Products from Gas-Fired
Appliances
EP-1-23
AGA
AGA
P. E. Suney
Development of burner designs to minimize flue
gas emissions. Measurements of gas emissions
are being obtained for a variety of furnace and
burner designs.
Title:
Measuring the Environmental Impact of Domestic
Gas-fired Heating Systems
EP-94-1
Contract No.:
Supporting Organization: AGA
Performing Organization: The Research Corporation of New England
Principal Investigator:
Project Description: A measurement and diffusion modeling study of
gas-fired home heating systems, largely dealing
with NO emissions.
304
-------
Table 142 (continued). ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS EMISSIONS - NO
Title:
Grant No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Reduction of Nitric Oxide with Metal Sulfides
R-800682
U.S. EPA
Montana State University
Dr. F. P. McCandless
Investigation of reaction kinetics of nitric
oxides with metal sulfides to determine those
most effective in nitric oxide removal.
Title:
Grant No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Analysis of Test Data for NOX Control of
Utility Boilers
R-802366
U.S. EPA (R. E. Hall)
Aerospace Corporation
D. Dykema
A program to correlate gas- and oil-fired
boiler operation with NOX and other emissions
and to determine the effect of NOX control
measures on combustion.
Title:
Grant No.:
Supporting Organization:
Estimation of Combustion and Nitric Oxide
Kinetics
R-800798
U.S. EPA (S. Lanier)
Performing Organization: Stanford Research Institute
Principal Investigator: R. Shaw
Theoretical study of NOX formation mechanisms
Project Description:
and kinetics.
385
-------
Table 142 (continued). ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS EMISSIONS - NO
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Aerodynamic Control over Emissions of Nitrogen
Oxides and Other Pollutants from Fossil Fuel
Combustion
68-02-0216
U.S. EPA (D. G. Lachapelle)
. Institute of Gas Technology
D. H. Larson
A 5-year study to minimize NOX emissions from
gas-fired boilers while maintaining system
efficiency.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Evaluation of the Effectiveness of Fuel Addi-
tives in Reducing Emissions in Coal and Oil
Combustion
68-02-0262
U.S. EPA (W. S. Lanier)
Battelle Memorial Institute
D. W. Locklin, R. D. Giammar
The objectives of this program are to assess
the effectiveness of fuel additives in reducing
emissions, to assess the potential to improve
thermal efficiency, and to determine the effect
of fuel and combustion conditions on emissions
of polycyclic organic materials.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Pilot Field Test Program to Study Methods of
NOX Formation in Tangentially Coal-Fired Steam
Generating Units
68-02-1367
U.S. EPA (D. G. Lachapelle)
Combustion Engineering Inc.
A. Selker
An evaluation of NOX reduction methods followed
by experimental measurements on a modified
pilot plant unit.
336
-------
Table 142 (continued). ON-GOING AND PLANNED ACTIVITIES-
FLUE GAS EMISSIONS - NO
: . X
Investigation to Determine the Effects of De-
sign and Operating Variables on NOX Formation
in Coal-Fired Furnaces
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
68-02-0634
U.S. EPA (D. G. Lachapelle)
Babcock & Wilcox Company
W. L. Sage
Experimental study (5 years) to reduce NOX
emissions from wall-fired coal boilers.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Control of NOX Formation in Wall-Fired Coal
Utility Boilers
Interagency Agreement (IAG) - 137D
U.S. EPA (D. G. Lachapelle)
U.S. Tennessee Valley Authority
J. Hollinden
The purpose of this study is to investigate
biased firing techniques and their effects on
NOX emissions, boiler corrosion, slagging,
thermal efficiency, and operational performance.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Research Initiation - Nitric Oxide Formation
in Pulverized Coal Flames
National Science Foundation
Purdue University
N. M. Laurendeau
A study of the physical and chemical mechanisms
controlling NO formation in coal burners.
387
-------
Tabie 142 (continued)'. ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS EMISSIONS - NO
x
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Catalysis Studies Directed Towards the Reduc-
tion of Nitrogen Oxides, Sulfur Dioxide, and
CO Emissions from Stationary Sources
University of Southern California
University of Southern California
J. M. Whelan
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Nitric Oxide Reduction Test - Reeves, Person
and San Juan Station
Public Service Company of New Mexico
J. Grossman
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Catalytic Reduction of Nitrogen Oxides
BR-96-2
AGA
University of California
A study of the reduction of NOX with reductants,
such as NH^, CO, and hydrocarbons on catalysts.
388
-------
Table 142 (continued). ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS EMISSIONS - NO
Title:
Contract No.:
Supporting Organization:
Performing Organization;
Principal Investigator:
Project Description:
Organic Nitrogen Compound Contribution to NOX
in Flat Flames
RP 223
EPRI
University of California, Berkeley
Unknown
The major goals of this effort by the Univer-
sity of California, Berkeley, are to determine:
(1) the mechanism of conversion of certain fuel-
bound nitrogen compounds to oxides of nitrogen;
(2) the percentage of organic nitrogen con-
verted to NOX; and (3) the fate of nitrogen
that is not converted to NOX. Expected to con-
tinue through 1977.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Determination of the Effects of Low NOX Firing
on the Corrosion, Slagging, and Other Opera-
tional Aspects of a Utility Boiler Firing
Western Coal
RP 529
EPRI
Arizona Public Service Company,
KVB Engineering Inc.
Unknown
EPRI will sponsor a 1-year program to evaluate
any of the potential side effects resulting
from low NOX fuel-rich firing techniques on low
sulfur western coal. The program intent is to
study the long-term effects of NOX control on
one of the 755 MW Babcock & Wilcox units at the
Four Corners Power Plant in Farmington, New
Mexico. Several wall tube test sections will
be installed in the unit, and tube wall thick-
ness measurements made prior to initiation of
fuel-rich firing and after several months of
low NO operation. Scheduled to be completed
by March 1976.
389
-------
Table 142 (continued). ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS EMISSIONS - NO
x
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Effectiveness of Gas Recirculation into the
Combustion Air for Reducing NOX on a Large
Coal-Fired Utility Boiler
RP 530
EPRI
KVB Engineering Inc., Allegheny Power, B & W
Unknown
This 3-month program will determine the feasi-
bility of utilizing windbox gas recirculation
as a NOX reduction technique on coal-fired
utility boilers. This will provide insight
into alternative methods of fuel-rich firing
techniques for meeting New Source Performance
Standards of 0.7 lb/106 Btu for coal-fired
boilers. The program will also determine if
fuel-rich firing NOX reduction techniques can
be enhanced with gas recirculation and will
expose any operational problems that may re-
sult. Scheduled to be completed by December
1975.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Field Testing: Application of Combustion
Modification to Control NOX Emissions from
Power Generation
68-02-1415 (EPA), RP 200 (EPRI)
U.S. EPA (R. E. Hall) and EPRI (R. Carr)
Exxon Research and Engineering Company
W. Bartok
Basically a long-term corrosion test on eastern
coal using NOX reduction processes.
390
-------
Table 142 (continued). ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS EMISSIONS - NO
Title:
Contract No.:
Oxides of Nitrogen Decomposition in Reducing
Environments
RP 461
Supporting Organization: EPRI
Performing Organization: KVB Engineering Inc.
Principal Investigator: Unknown
Project Description:
An alternative to processes that limit the
formation of NOX are processes that lead to
the destruction of NOX, usually, in the past,
by means of catalytic devices. Recent labora-
tory tests, however, have documented the occur-
rence of NOX decomposition without catalytic
materials present. Although application of the
technique to full-scale systems is still far
off, the results to date are encouraging.
Scheduled to be completed by January 1976.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Fate of Fuel Nitrogen in Backmixed Combustion
RP 241
EPRI
Washington State University
Unknown
In a 1-year study, Washington State University
will investigate the degree of conversion of
various fuel-bound nitrogen compounds to oxides
of nitrogen in a well-stirred laboratory com-
bustion reactor. Scheduled to be completed by
September 1975.
391
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FLUE GAS EMISSIONS - HYDROCARBONS AND CARBON MONOXIDE .
Table 143 lists three EPA projects dealing with hydrocarbons. The hydro-
carbons (except for polycyclic organic materials) emitted from stationary
combustion sources do not make a large contribution to ambient hydrocarbon
levels and are not considered a problem. Stationary combustion sources
are also minor sources of carbon monoxide. Most programs dealing with
NO reduction by combustion modifications will measure hydrocarbons and
X
carbon monoxide since some modifications (e.g., low excess air) will tend
to reduce combustion efficiency and raise hydrocarbons and carbon monoxide
emission levels.
392
-------
Table 143. ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS EMISSIONS -
HYDROCARBONS AND CARBON MONOXIDE
Title:
Contract No.:
Supporting Organization
Performing Organization
Principal Investigator:
Project Description:
Development of Methodology to Determine
Organic Composition of Particulates
U.S. EPA
Dr. E. Sawicki
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Laboratory Analysis of Nonmetallic Elements
in Particulates
U.S. EPA
J. D. Mulik
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Sampling System for Organic Products of
Combustion
RP 383
EPRI
Battelle, Columbus Lab.
Unknown
This 4-month project will develop a simple and
efficient sampling device for the collection of
organic components of stack gases from combus-
tion sources.
393
-------
FLUE GAS EMISSIONS - POM
In addition to the new or continuing projects cited in Table 144, there
are other EPA investigations now underway to determine the vapor phase
and particulate emissions of POM (and PHH) from stationary sources.
These include work being conducted by Monsanto Research Corporation (MRC)
for preparation of stationary source assessment documents, a recently
completed study of "Hazardous Emission Characterizations of Utility
Boilers by Midwest Research Corporation" (EPA-650/2-75-066), and the
Great Northern Plains Study of western coal-fired boilers (Radian Corpo-
ration). Midwest Research Corporation (MRC) is also conducting a field
evaluation of a sampling procedure for POM emission measurements from
stationary sources (EPA Contract No. 68-02-2203). Battelle, KVB Engi-
neering, Meteorology Research, Inc., and others are active in this area.
A number of long-term studies dealing with the analysis of POM compounds
are being conducted at EPA-RTP, with C. Golden, J. Sigsby, and Dr. E.
Sawicki listed as principal investigators.
No specific references to the measurement of POM from small residential
and commercial systems have been found other than some earlier laboratory
studies by Battelle and some work by KVB Engineering described previously.
394
-------
Table 144. ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS EMISSIONS - POM
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Instrumentation and Methodology for Assay of
Individual Polynuclear Aromatic Hydrocarbons
68-02-0653
U.S. EPA
Exxon Research and Engineering Company
R. A. Brown
A study to develop instrumentation and meth-
odology for several POM compounds.
Title:
Contract No.:
Supporting Organization:
Performing Organization;
Principal Investigator:
Project Description:
A Study of Fine Particulate Sulfates and Poly-
cyclic Organics
68-02-0752
U.S. EPA
Battelle Memorial Institute, Columbus Lab.
W. Henry
A study of the chemical composition of
respirable particulates.
Title:
Contract No.
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Matrix Isolation Analysis of Pollutant Emissions
from Coal Conversion and Utilization Processes
RP 332
EPRI
University of Tennessee
Unknown
The class of chemical compounds known as poly-
cyclic organic matter (POM) presents many dif-
ficult analytical problems. Various combinations
of spectroscopic techniques coupled with matrix
isolation will be investigated as an analytical
tool to determine if samples can be characterized
with less extensive preparation than is currently
required.
395
-------
Table 144 (continued). ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS EMISSIONS - POM
Title: Development of Sampling Procedures for POM
and PCB
Contract No.: 68-02-1255
Supporting Organization: U.S. EPA
Performing Organization: Langston Laboratories
Principal Investigator: T. S. Herman
Project Description: A program to design and test manual sampling
procedures for both POM and PCB.
396
-------
FLUE GAS EMISSIONS - TRACE ELEMENTS '
Recently a great deal of emphasis has been placed on the determination of
trace elements resulting from combustion of fossil fuels. The variations
in fuel composition and problems encountered in sampling and analysis of
trace elements present significant difficulties. Recent and on-going
activities have emphasized the material balance approach, requiring the
sampling and analysis of input fuel and effluent streams, bottom and fly
ash. Organizations active in this area in recent years, in addition to
EPA, have included: the Tennessee Valley Authority; the Universities of
Illinois, Colorado, Maryland, and West Virginia; the Bureau of Mines;
MRC; MRI; KVB; Battelle; GCA; Radian; and other government contractors.
The general consensus of opinion by those presently active in this area
is that air emissions from combustion sources do not add significant
quantities of most trace elements to the atmosphere. Only beryllium was
cited in a recent Midwest Research Institute Report (EPA Contract No.
68-02-1324, Task Order No. 27) as potentially significant. However, the
observed enhancement of many trace elements in the fine particle fraction
of fly ash, while not significant in terms of the total mass distribution
of trace elements, may pose health hazards due to the respirable nature
of fine particulates. The control of fine -particulates and certain vola-
tile elements; e.g., msrcury, selenium, etc., will require the development
of more efficient control devices. Control may be important, also, from
the standpoint of plume and atmospheric transformation processes, such as
minimizing the catalytic transformation by metals (e.g., vanadium) of S02.
The changing energy picture has increased the interest in the trace ele-
ment area because of the trend to greater use of coal. As a result, tests
have been conducted on boilers burning eastern coal and are now being con-
ducted in the Great Northern Plains study on two subbituminous-fired units
and one lignite-fired unit by Radian Corporation. Fuel switching also
will affect control device performance due to changes in fly ash resistivity.
397
-------
Combustion system type will also influence emissions, including trace
element emissions. Consideration should be given to the importance of
combustion system type in the design of future experimental programs.
Table 145 lists some on-going projects.
393
-------
Table 145. ON-GOING AND PLANNED ACTIVITIES: FLUE GAS
EMISSIONS - TRACE ELEMENTS
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Environmental Pollutants from Electric Power
Generation Facilities
U.S. Energy Res. & Dev. Admin.
University of California
R. E. Ragaini, D. Jones, E. Morimoto, R. Ralston,
D. Garvis
A study of the environmental impact (trace metal
emissions) of coal-fired power stations and
nuclear power stations (radionuclides).
Title:
Contract No. :
Trace Elements
Supporting Organization: Southern California Edison Co.
Performing Organization: Southern California Edison Co.
Principal Investigator:
Project Description:
J. B. Moore
Identification of concentration of trace ele-
ments leaving the stack of fossil-fueled plants
as well as the concentration of elements in
bottom ash, precipitator ash, etc. Development
of control methods if required, include preven-
tion of leaching .from ash.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Trace Elements in Combustion Systems
RP 122
Electric Power Research Institute
Battelle Memorial Institute
A. Levy and R. W. Coutant
A determination of the concentration of trace
elements in boiler slag, precitator ash, and
in fly ash and flue gas for four coals and one
oil. This will be done in the Battelle furnace
facility.
399
-------
Table 145 (continued). ONGOING AND PLANNED ACTIVITIES: FLUE GAS
EMISSIONS - TRACE ELEMENTS
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Trace Elemental Analysis by Means of Heavy
Particle-Induced X-rays
International Atomic Energy Agency
International Atomic Energy Agency
Dr. S. Johansson, T. B. Johansson, R. Akselsson,
M. Ahlberg, and K. Malmovist
Title:
Contract No.:
To Conduct Research Relating to Toxic Metals
in Atmospheric Aerosols
Supporting Organization: Louis & Maud Hill Family Foundation
Performing Organization:
Principal Investigator:
Project Description:
Oregon Grad. Ctr. Stu. & Res.
Unknown
Title:
Survey of Relative Burdens of Atmospherically
Borne Metals in Britain
Contract No.:
Supporting Organization: United Kingdom Government
Performing Organization: University of Wales
Principal Investigator: Unknown
Project Description:
400
-------
Table 145 (continued). ON-GOING AND PLANNED ACTIVITIES: FLUE GAS
EMISSIONS -' TRACE ELEMENTS
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Correlation of Hazardous Compounds in Coal,
Coal Ash, Fly Ash, and Other Emissions from
Combustion
U.S. Department of the Interior
U.S. Department of the Interior
R. A. Friedel, A. G. Sharkey, R. G. Lett,
and J. L. Shultz
Title:
Removal of Trace Elements from Combustion
Products
Contract No.;
Supporting Organization: U.S. Department of the Interior
Performing Organization: U.S. Department of the Interior
Principal Investigator: D. Bienstock, J. J. Demeter and C. R. McCann
Project Description:
Title:
Contract No.:.
Supporting Organization: U.S. EPA
Performing Organization:
Principal Investigator:
Project Description:
Potential Radioactive Pollutants Resulting
From the Expanded Energy Programs: Quality
Assurance Aspects
RFP Cl 75 0261
401
-------
Table 145 (continued).' ON-GOING AND PLANNED ACTIVITIES: FLUE GAS
EMISSIONS - TRACE ELEMENTS
Title:
Contract No.:
Trace Elements in Coal
Supporting Organization: Ohio State Government
Performing Organization: State Department of Natural Resources
Principal Investigator: N. F. Knapp
Project Description:
Title:
Evaluation of Pollution from Trace Elements
in Coal
Contract No.:
Supporting Organization: U.S. Department of the Interior
Performing Organization: U.S. Department of the Interior
Principal Investigator: A. W. Deurbrouck
Project Description:
Title:
Contract No.:
Supporting Organization: U.S. EPA
Performing Organization:
Principal Investigator:
Project Description:
Analytical Support to Include Comprehensive
Analysis of Hazardous Substances in Residual
Oil
RFP DU-75-4321
402
-------
ASH HANDLING
Coal combustion accounts for about 99 percent of all ash generated by
stationary combustion sources; almost all a product of electric utility
and industrial combustion. Only a small percentage (-15 percent) of this
ash is utilized and the remainder constitutes the predominant source of
solid waste attributable to combustion processes. Although ash handling
procedures are moderately.well defined for utilities, industrial practices
remain obscure and the present data base is poor. There are a substantial
number of studies underway dealing with fly ash and bottom ash, primarily
in the area of ash utilization. Other studies, such as those concerned
with trace emissions, indirectly address the ash problems by providing
information concerning control device efficiency, fly ash and bottom ash
distribution, and chemical composition of ash fractions as a function of
fuel used, control device, and boiler type.
Work in the areas of ash pond effluents, leachates and fugitive emissions
from ash transport and storage is limited. EPA and other government agen-
cies, such as the Army Corps of Engineers, Department of Interior, TVA,
etc., do have a number of on-going or planned activities dealing with
leachates, fixation processes, use and durability of pond liners, etc.
Many are studies dealing with predictive models and laboratory measurement
of migration rates and concentration of metals and anions, effect of heavy
metals on various types of soil receptors, and interactions of metals and
organics. Most of these studies are laboratory programs and the results
need to be correlated with field tests.
A listing of some individuals presently involved in these areas of activ-
ity, their affiliations, and a brief description of their current activ-
ities follows:
403
-------
Leachates
Dan Kranczk, EPA Corvallis - Chemical composition
of leachates based on equilibrium concentrations
which predict the concentration of metals and anions
as free ions, bound species, and precipitated solids.
Walt Sanders, Southeast Water Lab., Athens, Georgia -
Similar to above study involving kinetics.
Mike Roulier, EPA, Cincinnati and George Pinder,
Princeton University - Migration rates of leachates.
Model development based on soil column experiments.
D. Whittemore, Kansas State University - Program
sponsored by Department of Interior to study effect
of combustion and landfill operations on water quality.
Fixations and Liners
Carlton Wiles, EPA, Cincinnati; Bob Landreth, EPA,
Cincinnati; Rich Tabakin, Edison Laboratory;
Dr. Richard Gullich, Richmond Field Station, Berkeley,
California; TRW, Redondo Beach, California; and
Metrecon, Oakland, California..
Table 146 lists projects dealing with the problems of ash handling and
utilization.
404
-------
Table 146. ON-GOING AND PLA1IN3D ACTIVITIES: ASH HANDLING
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:-
Project Description:
Characterization of Effluents from Coal-Fired
Power Plants
U.S. EPA
Unknown
Unknown
This is a project consisting of six different
tasks. Three of those tasks are related to the
FGD waste disposal program: (1) Assessment of
pH Adjustment on Ash Pond Effluent, (2) Design
of an Effective Monitoring Program for Ash Pond
Effluent, and (3) Assessment of the Effect of
Ash Leachate on Ground Water. The monitoring
program design is expected to be completed in
late 1975. The pH adjustment study should be
completed by late 1976. The ash leachate/ground
water study will be related to the EPA work with
the U.S. Army (Dugway); the in-situ ash pond
leachate and ground water characterization study
should be complete by early 1977.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Geochemical Controls on Trace Element Concentra-
tions in Natural Waters of a Proposed Coal Ash
Landfill Site.
U.S. Department of the Interior; Office of
Water Research and Technology
Kansas State University
D. 0. Whittemore
Trace element concentrations will be determined
in surface and ground waters in the drainage
basins of a proposed landfill site. Models of
the hydrologic cycle will be prepared.
A 05
-------
Table U6 (continued). Oil-GOING AND PLANNED ACTIVITIES: ASH HANDLING
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Particle Characterization and Utilization of
Fly Ash Resources in Illinois
State of Illinois
State Geological Survey
R. D. Harvey
The variable character of fly ash produced in
coal-fired power plant is being examined to
determine potential uses.
Title:
Contract No. :
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Chemical and Physical Examination of Ash, Slag
and Fireside Reports from Lignite and Other
Western Coals
Bureau of Mines, Grand Forks,.N. D.
Bureau of Mines
W. W. Fowkes
A study to obtain fundamental data concerning
the properties and composition of coal ash
which influence deposition for a broad spectrum
of western coals.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Western Coal Ash
Bureau of Mines, Washington, B.C.
Bureau of Mines
Unknown
Research to develop fundamental data on the
composition and properties of western coal ash
and to define mechanisms for removal of objec-
tionable materials.
406
-------
Table 146 (continued). ON-GOIIIG AND PLANNED ACTIVITIES: ASH HANDLING
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:.
Project Description:
Improve the Thermal Efficiency and Availability
of Boilers Burning Western Coals and Lignite
Bureau of Mines, Grand Forks, N.D.
Bureau of Mines
,E. A. Sondreal
A commercial pulverized coal-fired boiler is
being used to study fireside ash deposition.
Chemical analyses of coal and ash are being con-
ducted to establish the mechanism of fouling.
Title:
Contract No.:
Performing Organization:
Principal Investigator:
Project Description:
In Vitro Toxicity Studies on Fly Ash Extracts
RP 483
Supporting Organization: EPRI
Battelle Columbus Laboratories
Unknown
The objective of this 1-year project is to de-
termine the toxicity of extractable fractions
from fly ash samples from both the combustion
of coal and residual fuel oil. In addition,
possible synergistic effects of NOX and SOX and
polycyclic organic materials (POM) applied in
conjunction with the fly ash extracts will be
investigated.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Pilot Model Study - Ash Pond Water Recirculation
TVA
TVA
W. S. Wilburn
A model study will be made at Shawnee to deter-
mine problems anticipated in recirculating high
pH ash pond water prior to installation of a
full scale system.
407
-------
Table 145 (continued). ON-GOING AMD PLANNED ACTIVITIES: ASH HANDLING
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Studies of Methods to Prevent Saturation of
Closed-Loop Ash Pond Systems
TVA
TVA
B. G. McKinney
A study of method to desaturate closed-loop
ash pond systems to prevent scaling.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Title:
Contract No.:
Supporting Organization:
i
Performing Organization:
Principal Investigator:
Project Description:
Effects of Coal By-Products in Soil
RP 202
EPRI
Radian Corporation
Unknown
The purpose of this research is to determine
the amounts of toxic elements in scrubber sludge
and fly ash and their leachability in various
types of soil.
Fly Ash Characterization and Disposal
U.S. EPA
TVA
Unknown
This is an expansion of a continuing project
at TVA to characterize coal, ash, and ash ef-
fluents. Data will be compiled and summarized,
emphasizing the quantity and physical/
chemical characteristics. An extensive
effort will be conducted for complete
characterization of physical properties and
chemical constituents of coal, ash, and ash
effluent. A study of ash sluice water
treatment methods, which would allow recycle/
re-use, will be made. Promising methods for
disposal and utilization of flyash will be
identified based on results of the efforts
just described.
408
-------
COOLING SYSTEMS
Current research into cooling systems for conventional combustion instal-
lations is quite diversified. The principal organizations doing investi-
gations include the Electric Power Research Institute (EPRI), the Energy
Research and Development Administration (ERDA), the Environmental Protec-
tion Agency (EPA), the Battelle Memorial Institute, and various colleges
and universities. The major emphasis of current projects centers upon
the reduction of water consumption, the elimination of salt drift, and
the reduction of thermal pollution and chemical contamination in water.
Battelle Memorial Institute is currently involved in studies on dry cool-
ing methods. The "investigations cover a variety of aspects of dry cooling,
including an assessment of the state-of-the-art, optimum design of heat
exchangers, and proposed advanced concepts. Battelle is currently oper-
ating a dry cooling test facility at the 30 MW Neil Simpson power plant
in Wyodak, Wyoming, owned by the Black Hills Power and Light Company.
The Environmental Protection Agency is sponsoring a number of studies on
dry and wet/dry cooling methods. The emphasis of the investigations is
on optimization of design and operating characteristics from the view-
point of economics, efficiency, and reduction of environmental impact.
The programs are mainly demonstration projects which attempt to augment
and verify existing information on dry and wet/dry cooling towers in order
to optimize tower operation.
Salt drift or fallout from cooling tower plumes is a significant problem
in the localized area of the tower. This has been a much investigated
problem in the recent past. Further work is presently being done at the
Turkey Point Plant in Florida where a mechanical draft wet tower is used
for cooling condenser water. This report will be available in the near
future. In order to prevent drift and associated land and vegetation
409
-------
damage, various organizations are looking into the improvement of mechan-
ical drift eliminators, and the use of dry cooling towers.
A great deal of investigation and modeling of thermal water pollution is
currently being done. Researchers at the Massachusetts Institute of Tech-
nology are very active in the field. The major emphasis of current studies
concerns flow modeling, heat dissipation, and induced currents. There is
also interest in determining near and far field heat distribution asso-
ciated with various cooling water discharge schemes. The objective is to
prevent the use of heated ambient water. In respect to this problem, MIT
will be developing near and far-field thermal diffusion models at the
Pilgrim Power Station in Plymouth, Massachusetts. In addition, studies
will be carried out to develop circulation models in Boston Harbor.
Table 147 lists on-going activities in the cooling system area.
410
-------
Table 147. ON-GOING AND PLANNED ACTIVITIES: COOLING
Title:
Contract No. :
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Cooperative Salt Water Cooling Tower
Environmental Effects Study
U.S. Nuclear Regulatory Commission
Maryland State Government
Unknown
Cooperative study of the measurement of salt
drift and resulting salt deposition from the
operation of a large natural draft salt water
cooling tower.
Title:
Contract No.:
Chalk Point Cooling Tower Drift Study
Supporting Organization: U.S. Nuclear Regulatory Commission
Performing Organization: Environmental Systems Corporation
Principal Investigator: F. M. Shofner
Project Description:
The study provides a demonstration of the
drift performance of large natural draft
cooling towers fitted with improved drift
eliminators. Favorable drift performance,
along with evidence that expected drift levels
will not have unacceptable environmental
impacts, will enhance the acceptability of
such salt water cooling towers systems for
use in future power plants, and will facili-
tate the siting of power plants in areas
where water supplies have high salt content.
The study will consist of: a. Direct measure-
ments of drift rates at the large hyperbolic
natural draft salt water cooling tower at the
Chalk Point Power Station (Unit #4). b. Sup-
porting measurements in the tower and power
plant needed for analyses and interpretation
of the drift measurement data. c. Acquisi-
tion of data from a nearby meteorological
tower and atmospheric soundings, as required
for the analyses of general plume behavior
and predictions of salt deposition, d. De-
tailed meteorological measurements of the
cooling tower plume itself to thoroughly
characterize plume rise. e. Analyses of
data obtained during the course of the field
measurement study.
411
-------
Table 147 (continued). ON-GOING AND PLANNED ACTIVITIES: COOLING
Title:
Contract No. :
Salt Water Cooling Tower Study
Supporting Organization: Jersey Central Power & Light Company
Performing Organization: Jersey Central Power & Light Company
Principal Investigator:
Project Description:
J. F. McConnell
Investigation of engineering and environ-
mental feasibility of salt water cooling
towers for Forked River Unit #1. Measure-
ment of drift from existing fresh water
towers in order to predict drift from salt
water towers and apply results to determine
environmental effects. Investigation of
blowdown and chemical treatment effects and
establishment of general engineering refer-
ence design.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Cooling Tower Salt Drift, Post Operation
Monitoring Program
Atlantic City Electric Company
Atlantic City Electric Company
R, J. Waukner
J. Kovago
Atlantic City Electric Company completed
erection of the first sea water cooling tower
in the country in December 1974.
Ambient salt concentration and deposition
caused by natural conditions has been exten-
sively monitored for 1 year pre-op in order
to establish firm background information.
This salt monitoring will be continued in
the first year of tower operation and its
results will be compared to the natural
salt deposition data. It is expected that
this study will reveal the true environ-
mental impact, if any, of a neutral draft,
sea water cooling tower.
412
-------
Table 147 (continued). ON-GOING AND PLANNED ACTIVITIES: COOLING
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Research Initiation - Improvement of
Evaporative Cooling Tower Performance
U.S. National Science Foundation
Division of Engineering
Drexel University
School of Engineering
C. W. Savery, Thermal & Fluid Sciences
The objective of the program is to study the
processes occurring in evaporative cooling
towers. The first phase of this research has
been devoted to analytical and experimental
study of packing performance. Current
research concentrates on the problem of cool-
ing tower drift, with emphasis on methods of
reduction of drift particles containing dis-
solved salts which are emitted by cooling
towers circulating salt water. The research
will include modeling of drift entrainment,
transport and deposition. Experiments will
involve the use of drift eliminator devices
in conjunction with a model cooling tower.
Title:
Effects of Cooling Tower Slowdown
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Wisconsin State Government
University of Wisconsin
School of Engineering
G. F. Lee
The primary objective of the project is to
determine the characteristics of blowdown
from cooling towers. The project is moti-
vated by questions of whether the utilization
of once-through cooling and the associated
heating of the waters in the region of the
discharge has a greater environmental impact
than the discharge of blowdown from cooling
towers used for waste heat dissipation. The
study consists of monitoring cooling tower
blowdown from a wide variety of cooling
towers located in the upper Midwest.
413
-------
Table 147 (continued). ON-GOING AND PLANNED ACTIVITIES: COOLING
Title:
Cooling Tower and Cooling Pond Atmospheric
Impact
Contract No. :
Supporting Organization:
Performing Organization:
Principal Investigator: M. A. Wolf
Project Description:
U.S. Nuclear Regulatory Commission
Battelle Memorial Institute
Efforts range from a comprehensive state-of-
the-art review of pertinent research to
consideration of potential methods for
modifying recognized consequences. Emphasis,
however, is placed on field studies for the
acquisition of an adequate data base to pro-
vide an understanding of the interaction with
the atmosphere of cooling towers and cooling
ponds. Current models for the prediction of
plume rise and dispersion, cloud formation,
fogging, and icing are evaluated with these
data and adapted as necessary. Additional
models are developed where appropriate. The
field portion focuses attention on the plume
dynamics and on the microphysical and chem-
istry properties of the plumes. Thus, a
variety of measurement techniques are
utilized in the definition of plume character-
istics on the meso- and microscales.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
A Study of the Plume From a Brackish Water
Natural Draft Cooling Tower and Its Effects
On the Environment
U.S. Nuclear Regulatory Commission
University of Maryland
Water Resources Research Center
J. Pell
The object of this study is to completely
characterize the effluent plume discharged
into the atmosphere from a natural draft,
evaporative, cooling tower employing brackish
water and to determine the plume's effect on
the vicinity's meteorology, air quality,
vegetation, and soils. Measurements will be
made from the top of the tower where the
414
-------
Table 147 (continued) . ON-GOING AND PLANNED ACTIVITIES: COOLING
plume enters the atmosphere, rather than
just above the fill. Laser light scattering
will be used for the measurement of droplet
size distribution of the saline drift. This
data will be complemented by isokinetic and
sensitive paper sampling. Measurements will
also be made of the vertical updraft velocity,
and plume temperature and water vapor content.
Metric quality photographs of the plume will
also be taken. A microwave tower, in the
vicinity of the plant, will be equipped with
instrumentation to measure local meteorologi-
cal data. Vegetation and soil samples will be
taken before and after the cooling tower start
up to determine the effects of the plume.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Thermal Studies - Atlantic Generating Station
Public Service Electric and Gas Company,
New Jersey
Massachusetts Institute of Technology
Prof. D. R. F. Harleman
Prof. K. D. Stolzenbach
Experimental studies will determine the inter-
action of the ocean bottom with heated sur-
face ana suosurface discharges. The objec-
tive is to develop analytical or numerical
techniques for predicting near and far-field
temperature distribution in coastal waters.
Results of measurements of ocean currents and
temperature distribution and dye diffusion
observations at the proposed site have been
incorporated into a mathematical model of the
far-field temperature distribution. Statisti-
cal characterization of receiving water states
are being developed in conjunction with the
application of this model. The project is
scheduled for completion December 1975.
415
-------
Table 147 (continued). ON-GOING AND PLANNED ACTIVITIES: COOLING
Title:
Contract No. :
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Dynamic of Shallow Cooling Ponds
Stone & Webster Eng. Corp. and
Virginia Electric Power Company
Massachusetts Institute of Technology
Prof. D. R. F. Harleman
Prof. J. J. Connor
Dr. G. H. Jirka
(1) Basic study of the buoyance driven verti-
cal circulation of cooling water into long
shallow side arms of cooling ponds. (2) De-
velopment of a transient cooling pond model
for heat distribution in shallow cooling
ponds with lateral and vertical restrictions.
This includes the development of a two-
layered finite element model for solution of
the mass heat and momentum conservation
equations. Specific application of this
investigation is the North Anna Cooling Lake
in Virginia.
Title:
Contract No.:
Diffuser Induced Circulations in Shallow
Coastal Zones
Supporting Organization: Waste Heat Management Research Program of the
MIT Energy Laboratory
Performing Organization:
Principal Investigator:
Project Description:
Massachusetts Institute of Technology
Dr. D. R. F. Harleman
Dr. G. H. Jirka
Dr. J. G. Steele
Submerged multiport diffusers for the dis-
posal of waste heat from thermal-electric
power generating facilities discharge a con-
siderable amount of cooling water with sub-
stantial momentum. In shallow coastal waters
these diffusers have the potential of
inducing currents of considerable magnitude.
An understanding of the induced current
pattern is necessary to assess potential heat
re-entrainment and the effect on coastal
morphology. A theoretical investigation com-
bined with a series of basic experiments is
planned.
416
-------
Table 147 (continued). ON-GOING AND PLANNED ACTIVITIES: COOLING
Title: Design of Environmental Monitoring Programs
Contract No.:
Supporting Organization: MIT Energy Laboratory
Performing Organization: Massachusetts Institute of Technology
Principal Investigator: Prof. S. F. Moore
Project Description: Development of quantitative methodologies for
the design of hydrothermal and biological
monitoring programs for waters subject to
heated water discharges.
Title:
Contract No. :
Supporting Organization;
Performing Organization;
Principal Investigator:
Program Description:
Physical, Chemical, and Biological Effects
of Heat Added to Missouri River by Lignite-
Fired Power Stations Near Stanton, North
Dakota
Basin Electric Power Corporation, Inc.
University of North Dakota
J. K. Neel
Title:
Contract No.:
Supporting Organization;
Performing Organization;
Principal Investigator:
Project Description:
Power Plant Waste Heat Rejection System Using
Dry Cooling Tower
EPRI
Union Carbide, Linde Division
Unknown
This 1-year project will establish the
economic feasibility of a dry cooling con-
cept that utilizes advanced heat transfer
technology to achieve high heat transfer
rates, incorporating enhanced heat transfer
surfaces in conjunction with a phase change
of the dense fluid transporting heat between
the steam condenser and the cooling tower.
417
-------
Table 147 (continued). ON-GOING AND PLANNED ACTIVITIES: COOLING
Title:
Contract No. :
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Cooling Water Discharge
RP 49
EPRI
Johns Hopkins University
Unknown
Since 1962, the electric utility industry
has sponsored studies at Johns Hopkins
University on the effects of power plant
cooling water discharge on rivers, lakes,
and other bodies of water. Fish entrap-
ment and the entrainment of organisms are
also under investigation.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Program Description:
Agricultural Waste Water for Power Plant
Cooling
RP 373
EPRI
California Department of Water Resources
Unknown
This 2-year project will: (1) develop an
economical and reliable pretreatment method
for agricultural waste water to reduce its
scale-forming tendencies; (2) develop
methods for allowing a cooling tower to
operate with a large concentration ratio;
(3) further the concentration of cooling
tower blowdown to a high total dissolved
solids level; and (4) study regeneration of
the reactants used in the pretreatment
process.
418
-------
Table 147 (continued). ON-GOING AND PLANNED ACTIVITIES: COOLING
Title: :
Contract No. :
Performing Organization:
Principal Investigator:
Project Description:
Cherne Thermal Rotor Test Program
RP 420
Supporting Organization: EPRI
Cherne Industrial, Inc.
Unknown
The 8-month test program will be carried
out at a utility plant site and will involve
a significantly large installation and
requisite instrumentation to establish the
interference effects, wind sensitivity, plume
characteristics, and drift performance, as
well as the heat dissipative capacity, of the
Cherne Thermal Rotor System.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Thermal Discharge State-of-the-Art
RP 283
EPRI
Environmental Analysts, Inc.
Unknown
Environmental Analysts, Inc., is studying the
current state of technology on waste heat
management in electric power plants. It will
include: (1) blowdown disposal; (2) waste
water utilization; (3) strategies in obtain-
ing low- or zero-discharge cooling systems;
(4) thermal discharge simulation; (5) field
monitoring; and (6) dry cooling systems.
Title:
Contract No. :
Supporting Organization;
Performing Organization:
Principal Investigator:
Project Description:
Performance, Economics, and Reliability of
Cooling Tower-Cooling Pond Mix
RP 321
EPRI
Auburn University
Unknown
This 1-year study will evaluate the perform-
ance and cost of employing a cooling tower-
cooling pond mix and compare the results by
using towers and ponds separately. The study
419
-------
Table 147 (continued). ON-GOING AND PLANNED ACTIVITIES: COOLING
will also determine the geographic regions of
the U.S. where the mixed-cooling concept might
be employed.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Forecasting Power Plant Effects on the
Coastal Zone
RP 575
ERPI
EG&G, Environmental Consultants
Unknown
The objective of this on-going project is to
advance understanding of far-field dispersion
of emissions from power plants on an open
coast as affected by physical oceanographic
processes. Air and sea temperatures and
current, wind, and tide data have been taken
for an area offshore the Pilgrim Power Station
near Plymouth, Mass. The study will provide
for verification of mathematical models of
the coastal dispersion sites.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Cooling Tower/Stack Gas Plume Interaction
EHB 540 77ADA, Task 1
EPA, EPRI, State of Maryland
Unknown
Unknown
The purpose of this airborne monitoring project
is to: (a) Characterize the heat and water
vapor plume emitted from a natural draft cooling
tower. (b) Evaluate the interaction between
the cooling tower plume and three adjacent
fossil fuel power plant stack plumes to deter-
mine formation and fate of acid droplets.
(c) Evaluate aircraft safety relevant to turbu-
lence, icing potential, and visibility impair-
ment produced by the plume. The study will be
done at Potomac Electric Power Company's Chalk
Point Power Plant and will run from June 1975 to
June 1976.
420
-------
Table 147 (continued). ON-GOING AND PLANNED ACTIVITIES: COOLING
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Optimizing Wet/Dry Cooling Towers for Water
Conservation and Plume Abatement
EHB 531 77AAY, Task 3
U.S. EPA
United Engineers, Inc.
Unknown
Assessment of the technical and economic feas-
ibility of minimizing water use and reducing
vapor plume discharges from wet/dry cooling
towers. Analyses will be conducted at five
sites in the western U.S. and will include
consideration of meteorology, water quantity,
and water quality. The project will be active
from June 1975 to June 1976.
Title:
Contract No. :
Principal Investigator:
Project Description:
Demonstration of a Wet/Dry Cooling Tower
EHB 531 77BBE, Task 3
Supporting Organization: U.S. EPA
Performing Organization: TVA
Unknown
The project will provide technical and economic
data on wet/dry cooling tower performance with
regard to wet/dry heat transfer mechanisms,
plume abatement, water conservation, and energy
requirements. An extensively instrumented wet/
dry tower of highly variable operating capability
will be used. The project is intended to yield
data to augment and verify analytical data pre-
sently available. The project began in May
1975 and is scheduled for completion in June 1977,
421
-------
Table 147 (continued). ON-GOING AND PLANNED ACTIVITIES: COOLING
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Optimizing Design Specifications for Large
Dry Cooling Systems
1 BB 392 21 AZU, Task 33
U.S. EPA
PFR Engineering Systems, Inc., Marina Del Key, Ca.
Unknown
The project is intended to develop a rigorous
and optimal procedure for evaluating dry cool-
ing tower performance and economics. Mechanical
draft dry cooling towers and direct contact jet
condensers will be studied. Variables consid-
ered will include tower height, water flow rate,
module design on bus-bar cost, and others. The
project began June 10, 1975 and is scheduled
for completion August 10, 1976.
Title:
Contract No.
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Dry Cooling Tower Demonstration and Performance
Study
EHB 531, 77AAY, Task 2
U.S. EPA
Town of Braintree, Massachusetts
Unknown
The project will demonstrate the use of a dry
cooling tower on a combined cycle (gas turbine/
steam cycle) power plant in order to evaluate
operating performance and environmental conse-
quences of the plant. The study will assess
steam flow and distribution and temperature to
help define optimal design characteristics.
The project will also investigate meteorological
effects, noise generation, and air quality in
order to determine the economic impact of design
and operational factors. The project began in
June 1975 and is scheduled for completion some-
time in 1979.
422
-------
BOILER WATER TREATMENT AND OPERATION
Modern boilers operate at high steam pressures and, therefore, are sus-
ceptible to a variety of hazards associated with the use of unacceptably
contaminated feed water. The major problem areas are scale deposition
and corrosion in the boiler system and solid particle erosion and crack-
ing of turbine components.
A new trend in specifying proper boiler water condition is the emphasis
on minimizing caustic alkalinity. At low operating pressure, alkalinity
will produce carryover problems at concentrations which do not promote
corrosion in the boiler system. As pressure increases, corrosion becomes
very highly dependent upon alkalinity and very strict limitations must
be made. In conjunction with this, investigations are being made into
current boiler operation standards in order to establish the state-of-
the-art and recommend operating standards which should be altered.
The ASME Research Committee on Water in Thermal Power Systems is cur-
rently determining the important areas of research required in order to
prevent or minimize turbine damage. Selection of appropriate investiga-
tions is a difficult effort because turbine problems are generated by a
wide variety of factors. It is possible that investigations will center
upon the dynamic behavior of contaminants saturated in the steam as they
pass through the turbine.
Battelle Memorial Institute in Columbus, Ohio, is investigating boiler
feed water chemistry with regard to control of corrosion and scale deposi-
tion. They are considering various volatile and nonvolatile agents and
will make recommendations on allowable concentrations.
The Electric Power Research Institute is currently sponsoring studies
which are applicable to conventional boiler system feed water treatment
and control. Combustion Engineering is under contract to investigate
423
-------
volatile chemistry treatment in nuclear steam generation systems. The
results should be applicable to conventional fossil fuel boilers in that
corrosion of steam generator tubing will be simulated in a number of ways.
The study will simulate condenser leakage and the affects of changeover
from phosphate treatment to volatile chemistry (hydrazine and morpholine)
treatment. Combustion Engineering is also looking into new methods of
boiler water tube acid cleaning and improvements in cleaning with in-
hibited hydrochloric acid. The investigations include analysis of affects
on boiler materials by testing of failure samples.
Babcock and Wilcox is active in updating a manual on methods of high pur-
ity boiler water analysis. High purity refers to detection of contami-
nants present in concentrations of parts per billion.
Much of the work being done regarding boiler feed water treatment and
specifications is proprietary information. Only a minor number of pro-
jects were specifically identified and are not considered to be repre-
sentative of the major thrust of research. However, some projects related
to corrosion and power plant waste water disposal are listed in Table 148.
424
-------
Title:
Contract No.
Table 148. ON-GOING AND PLANNED ACTIVITIES:
BOILER WATER TREATMENT AND OPERATION
Structural Design Concepts for Increased
Reliability and Safety in Power Plant
Condensing Systems
RP 372
Supporting Organization: EPRI
Performing Organization: . University of Pennsylvania
Principal Investigator: Unknown
Project Description:
The objective of this 2-year program is to
reevaluate traditional condenser structural
design methods by: (1) establishing rational
design criteria for tube support plates;
(2) establishing design rules relating to
deformation of condenser flat-plate sections
stayed by discrete pipes; and (3) performing
theoretical analyses and scale-model tests to
determine the stress distributions in built-up
pressure vessels such as condenser meter
boxes.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Preparation of Data Record on High Tempera-
ture Oxidation and Corrosion of Metals and
Alloys in Electrical Generating systems
RP 538
EPRI
University of Liverpool, England
Battelle Columbus Laboratories
Unknown
This is an 18-month project. Experience
relating to the high temperature oxidation
and corrosion of metals and alloys in circum-
stances relevant to fossil-fuel-fired systems
is very extensive and is dispersed over a
wide range of scientific and technical
literature, governmental, and other reports,
and unpublished experience within companies
and utilities. Collection of this into one
record would greatly aid the designers and
operators of fossil-fuel-fired systems in
avoiding potentially corrosive situations.
425
-------
Table 148 (continued). ON-GOING AND PLANNED ACTIVITIES:
BOILER WATER TREATMENT AND OPERATION
Title: Overall Power Plant Water Recycle/Reuse
Studies - Pacific Northwest Environmental
Research Laboratory
Contract No. :
Supporting Organization: U.S. EPA
Performing Organization: Radian Corporation
Principal Investigator: Unknown
Project Description: This is a contract with Radian Corporation to
determine over-all power plant water manage-
ment systems to minimize water use. Recycle
and treatment/reuse process simulations,
using actual power plant field data as input,
and preliminary system design and economic
studies will be made on four different power
plants representing four different areas of
the United States. This effort, which is
expected to be completed by mid-1976, will be
coordinated with the TVA Fly Ash Characteriza-
tion and Power Plant Effluent Studies. Pilot
plant testing based on results of this study
is expected to commence in early 1977.
426
-------
FUELS AND FUEL STORAGE AND HANDLING
The anticipated growth in the use of coal has spurred greater interest
in fuel conversion and coal properties including chemical content, vola-
tility, ash fusibility, agglomerating tendencies, heat content, coal
size and grindability. All of the above chemical and physical properties
of coal influence furnace and firing equipment design and maintenance
and have an important bearing on emissions and the use and performance
of control equipment.
Coal handling practices will vary greatly depending upon the size of the
combustion units, the type of combustion unit, land and storage area
availability, etc. ' EPRI, the National Coal Association, and all users
of fuels have an interest in fuel storage and handling practices. How-
ever, there is no typical plant and information on emissions from coal
storage and handling is practically nonexistent in the literature. The
only known studies now underway or planned which deal with coal storage and
handling emissions are the Monsanto Research Corporation's stationary source
assessment studies which have dealt with air emissions and a planned TVA study
dealing with coal pile drainage slated for completion in 1976.
One area that has not been covered in any detail in this report concerns
the reduction of sulfur prior to combustion by physical cleaning methods.
EPA has been conducting research for a number of years, with the Bureau
of Mines to improve coal washing processes. EPA has also funded a charac-
terization of the washability of Northern Appalachian coal. This approach
has been found to reduce the average pyritic sulfur content from 2.05 per-
cent to 0.75 percent at a coal recovery yield of 90 percent. Regardless
of yield the average organic sulfur content of the coals studied was 1.2
percent. A recent summary of coal washability studies is presented in an
EPA report by L. Hoffman, et al., entitled "An Interpretive Compilation
of EPA Studies Related to Coal Quality and Cleanability." A list of pro-
grams relating to fuels and fuel handling is given in Table 149.
427
-------
Table 149. ON-GOING AND PLANNED ACTIVITIES:
FUELS AND FUEL HANDLING
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Characteristics of Coal Slurries
RP 314
EPRI
Stanford University
Unknown
The objective of this 3-year project is to
develop improved design criteria for the flow
of and heat transfer from coal slurry mixtures,
Viscometric coefficients and heat transfer
characteristics of slurries will also be
measured.
Organic Sulfur Constituents in Coal
RP 267
Title:
Contract No.:
Supporting Organization: EPRI
Performing Organization: University of Florida
Principal Investigator: Unknown
Project Description:
This 3-year program will isolate the organic
sulfur in coal by chemical means and identify
the nature of the isolated organic sulfur
compounds.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Reduction of Inorganic Sulfur in Dry
Pulverized Coal Using High Intensity Mag-
netic Separation.
RP 540
EPRI
Indiana University Foundation
Unknown
The objective of this 1-year project is to
determine the relationship between magnetic
separation process variables and the extent
of pyritic sulfur reduction so that a meaning-
ful economic evaluation can be prepared.
Many highly pyritic Appalachian coals will
not meet environmental restrictions on
428
-------
Table 149 (continued).
ON-GOING AND PLANNED ACTIVITIES:
FUELS AND FUEL HANDLING
allowable sulfur content. The sulfur content
of such coals may be reduced to acceptable
levels by utilization of high intensity mag-
netic separation to remove weak magnetic
pyritic sulfur compounds from a coal-air
mixture.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Technology Assessment of Preparation of Coal
for Combustion and Conversion
RP 466
EPRI
Unknown
Unknown
The objective of this 1-year project is to
provide a comprehensive, authoritative, and
responsible description of coal preparation
technologies. Coal preparation refers to
those techniques and processes used to im-
prove the quality of coal prior to its use
(removal of sulfur-hearing minerals, se-
paration of rocks, etc.) Also included are
those methods used to control the heating
value of coals through blending and stock-
pile maintenance.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Review of Coal Cost and Production Studies
RP 335
EPRI
Pennsylvania State University
Unknown
This 1-year project will review recent and
ongoing studies to ascertain the state of
knowledge of coal supply. Projections of
cost and output, and the methods by which the
projections are made, will be critically
analyzed.
429
-------
Table 149 (continued).
ON-GOING AND PLANNED ACTIVITIES:
FUELS AND FUEL HANDLING
Title:
Contract No.:
Review of Natural Gas Supply Studies
RP 436
Supporting Organization: EPRI
Performing Organization: Mathematica, Inc.
Principal Investigator:
Project Description:
Unknown
A critical review and assessment and a com-
parative analysis of 12 gas supply studies,
including the Federal Energy Administration
and the National Petroleum Council studies,
will be performed in this 4-month project.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Assessment of Capability of the Existing
Transportation Network for the Movement of
Increased Amounts of Coal
RP 437
EPRI
Mathematica, Inc.
Unknown
The purpose of this 6-month study is to de-
velop a system of measures of aggregative
interregional transportation capacity and to
identify any of the links where transpor-
tation bottlenecks might occur.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Fuel Utilization in Residential Heating
RP 137
EPRI
Ohio State University
Unknown
Investigation of a procedure for calculating
accurately the energy requirements of single
and multiple residential housing units. It is
intended that the procedure be applicable to
both electric and fossil fuel heating systems
in order to determine precisely the difference
in the amounts of fuel raw energy required to
heat houses of similar structure.
430
-------
Table 149 (continued). ON-GOING AND PLANNED ACTIVITIES:
FUELS AND FUEL HANDLING
Title:
Contract No.
Development of Models to Aid in Forecasting
Residential Energy Usage
RP 931
Supporting Organization: EPRI
Performing Organization: Data Resources, Inc.
Principal Investigator: Unknown
Project Description:
The purposes of this 1-year study are to de-
velop improved data bases and forecasting
methodology for energy use in the. residential
sector and to develop a data file on resi-
dential usage of electricity, natural gas,
and fuel oil, by state, for 1950 to 1973.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Forecasting the Industrial Demand for Energy
RP 433
EPRI
Econometrica International
Unknown
This 1-year project will have three phases:
(1) survey of existing work on industrial
energy demand, development of analytic
approaches, and review of data sources;
(2) analysis and empirical research into two
industries; and (3) application of knowledge
gained in (2) to the full list of industries.
Title: Assessment of Energy Modeling (2 parts)
Contract No.: RP 333
Supporting Organization: EPRI
Performing Organization: Charles River Associates, Inc.
Principal Investigator: Unknown
431
-------
Table 149 (continued). ON-GOING AND PLANNED ACTIVITIES:
FUELS AND FUEL HANDLING
Project Description: Part I: An assessment of the state-of-the-
art in electric power demand fore-
casting techniques, with special
emphasis on forecasting reliability.
Part II: An assessment of energy systems
models that integrate supply, demand,
environmental, and other consider-
ations, with emphasis on electric
power problems.
432
-------
FLUE GAS DESULFURIZATION
Present research into methods of SO removal from combustion stack gases
X
is extremely diversified. Potential removal processes range from fuel
pretreatment for sulfur reduction to collection of SO as it exits the
A
stack. The EPA is sponsoring a great number of projects on flue gas
cleaning waste disposal. They and other projects are listed in Table 150,
433
-------
Table 150. ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS DESULFURIZATION
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator;
Project Description:
Prototype Study of Limestone Scrubbing for
S02 - Dust Removal Systems
U.S. EPA
Bechtel Corporation
I.A. Raben
The objectives of this contract are: to com-
plete the detailed design of a highly ver-
satile, prototype limestone wet scrubbing
facility; to procure major equipment; to de-
sign and conduct a 2-year test program to
evaluate limestone wet scrubbing processes;
and to analyze, evaluate, and report the test
results.
A comprehensive process and mechanical design
report will be issued. The test program is
now being conducted at TVA's Shawnee Steam
Plant, near Paducah, Kentucky.
Title:
Contract No.;
Principal Investigator:
Project Description:
Development of Active Carbon SO Sorption
and Sulfur Recovery Process
Supporting Organization: U.S. EPA
Performing Organization: Westvaco
F. J. Ball
The purpose of this effort is to determine
technical feasibility of the power plant flue
gas desulfurizing and elemental sulfur reco-
very process using activated carbon as SOX
sorbent. The process essentially consists of
sulfur oxides sorption, sulfuric acid decom-
position and active carbon regeneration
stages. The reactive gas, hydrogen sulfide,
needed for sulfuric acid decomposition, is
generated internally in the active carbon
regeneration stage. Elemental sulfur is the
byproduct of this process. Pilot plant inves-
tigations, now in progress, are aimed to de-
termine sets of principal operating parameters
434
-------
Table 150 (continued). ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS DESULFURIZATION
for all process stages which then will be
integrated and run continuously for some
time in a cyclic manner.
Title:
Contract No.:
Wet Scrubber Study
Supporting Organization: U.S. EPA
Performing Organization: West Virginia University
Principal Investigator: Dr. D. Y. Wen
Project Description:
The objective of this study is: 1) To
clearly define the reaction mechanism of
S02 absorption by various solutions, such
as CaO-, CaC03-, CaOH-, Na2COo- solutions.
2) Elucidate the phenomena taking place in
various types of wet scrubbers such as
venturi, packed tower, spray tower, and tur-
bulent bed contractor, both from the
mechanical and absorption-kinetic points of
view. 3) Find optimal operating conditions
and provide the design and scale-up criteria
of wet scrubber process which will result in
the most efficient and economic absorption
performance. To achieve objectives, ma-
thematical models describing the phenomena
in these scrubber processes will be devised.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Development of the Stone & Webster Process
for S02 Removal and Recovery
U.S. EPA
Wisconsin Electric Power Company
C. W. Fay
The EPA and Wisconsin Electric Power Company
program is as follows: Phase I - Design,
Installation and Operation of an integrated
pilot plant; development of prototype scale
electrolytic cell system; preliminary design
of 75 Mw prototype system and development of
detailed test programs and operating schedules,
435
-------
Table 150 (continued).
ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS DESULFURIZATION
Based on evaluation of results from Phase I
and continued favorable assessment of tech-
nical and economic feasibility, the program
will continue as follows: Phase II - De-
tailed design, procurement and installation
of a 75 MW prototype system. Phase III -
Start-up and operation of the 75 MW proto-
type system.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Shell Flue Gas Desulfurization Process
Pilot Plant
Tampa Electric Company
'e
Tampa Electric Company
J. Pohlenz, D. J. Rankin
Purpose is to test the system on a coal-
fired boiler in an effort to determine
technical feasibility and operating param-
eters of the modular reactor and its
ability to remove SOX from flue gas. Suc-
cessful operation could lead to further
development and/or application on a larger
or full sized utility boiler.
Title:
Contract No.:
Sulfur Dioxide Removal from Flue Gases
Supporting Organization: Universal Oil Products Company
Performing Organization: Universal Oil Products Company
Principal Investigator: Dr. A. K. Sparks
Project Description:
The object of this work is the removal of
sulfur dioxide from flue gases - principally
from power generating stations that burn coal
or residual oil. Two processes are currently
under development - one uses a liquid absorp-
tion system, the other utilizes a regenerable
solid adsorbent at high temperatures. Both
processes yield elemental sulfur as the
product.
436
-------
Table 150 (continued). ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS DESULFURIZATION
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Evaluation of Advanced Regenerable Flue Gas
Desulfurization Processes
RP535
EPRI
Radian Corporation
Unknown
The primary objective of this 6-month project
is to provide the utility industry with a
comparative state-of-the-art evaluation of
developmental regenerable flue-gas desulfur-
ization processes.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Pilot Test and Evaluation of Three Prototype
Flue Gas Desulfurization Processes.
RP536 '
EPRI
Southern Services, Inc.
Unknown
The Southern Company has installed 20 MWe
pilot plants of three second-generation
flue-gas desulfurization processes at the
Scholtz Steam Plant of Gulf Power Co. The
processes being evaluated during this 18-
morith period are: (1) the A-, D. Little/Com-
bustion Equipment Associates Double Alkali
Process (Sodium/Calcium), (2) the Foster-
Wheeler/Bergbau-Forschung Dry Coal Char Ad-
sorption Process, and (3) the Chivoda
Thorobred 101 Dilute Acid Adsorption Process.
These prototype pilot plants have been de-
signed to permit operation in a utility con-
text over a wide variety of operating con-
ditions, fuel types, and gas-flow rates.
437
-------
Table 150 (continued). ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS DESULFURIZATION
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Development of Improved Lime/Limestone
Scrubbing Technology
RP535
EPRI
TVA
Unknown
This 18-month project is directed to ex-
panding an existing development and process
evaluation program at the TVA Colbert Lime/
Limestone scrubbing pilot plant to include
four additional high priority tasks required
in achieving a commercial design base for
lime/limestone scrubbing on high-sulfur coal.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
S02 Removal from Stack Gases
Foster Wheeler Corporation
Dairyland Power Cooperative
Unknown
Injection of powdered dolomite into the hot
flue area of the boiler system.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Wet Scrubber Pilot Plant Test
Northern States Power Company
Northern States Power Company
J. A. Noer
A temporary installation for testing and
analysis of a 12,000 CFM wet scrubber on unit
No. 1 at Black Dog Generating Plant, will du-
plicate in reduced scale, the Combustion En-
gineering wet scrubber now being designed for
installation at the Sherburne County Generating
Plant. The findings of this pilot installation
will be used to verify the CE Design and assure
its ultimate full scale operation by investi-
gating S02 and particulate removal rates,
scaling, water chemistry, ash hold-up pond
chemistry, materials corrosion, etc.
438
-------
Table 150 (continued).
ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS DESULFURIZATION
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Flue Gas Cleaning Waste Characterization
and Disposal Evaluation
U.S. EPA.
Aerospace Corporation
Unknown
'A broad-based study is being performed
(1) to identify environmental problems
associated with FGC waste disposal,
(2) to assess current FGC waste disposal
methods (both technically and economically),
and (3) to make recommendations regarding
alternate disposal approaches. The effort
includes chemical and physical character-
ization of untreated and treated (fixed,
oxidized, stabilized) FGC wastes, tech-
nical support of the FGC waste disposal
demonstration at Shawnee, and coordinating
all FGD waste related R&D activities
(EPA, TVA, private industry) including
publishing an annual integrated report.
Title:
Contract No.:
Project Description:
Shawnee Field Evaluation of Flue Gas Cleaning
Waste Disposal Methods
Supporting Organization: U.S. EPA
Performing Organization:
Interagency Agreement with TVA and the
Aerospace Corporation
The current program evaluates the Chemfix,
Dravo, and IUCS processes for chemical
fixation of scrubber wastes in three separate
disposal ponds. Untreated lime and lime-
stone wastes are placed in two additional ponds,
Leachate, run-off and groundwater samples
as well as core samples of the wastes and
soil are being collected and analyzed to
evaluate environmental effects. Both Aero-
space Corporation and TVA are performing
selected analyses; Aerospace is responsible
for data evaluation and reporting. Future
plans call for evaluation of other disposal
approaches, including gypsum disposal.
439
-------
Table 150 (continued).
ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS DESULFURIZATION
Title:
Contract No.
Louisville Gas and Electric Lime Scrubbing
Waste Disposal Laboratory and Field Evaluation
Supporting Organization: U.S. EPA
Performing Organization: Louisville Gas and Electric
Principal Investigator:
Project Description:
Unknown
This is part of a contract with Louisville
Gas and Electric (LG&E) for lime and carbide
lime scrubbing tests and waste disposal
studies. Both physical stabilization (e.g.,
by adding fly ash) and chemical fixation will
be evaluated in laboratory studies, subse-
quently followed by field evaluation of the
lab results. The field evaluation will con-
sist of "swimming pool" tests in which all
leachate will be collected and disposal site
tests (similar to Shawnee) in which soil-
leachate interactions can be evaluated.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Laboratory and Field Evaluation of 1st and
2nd Generation Flue Gas Cleaning Waste
Treatment Processes
U.S. EPA
Interagency Agreement with U.S. Army Corps
of Engineers
Unknown
This program will evaluate fixation processes
for several industrial wastes, including FGC
wastes. Initial efforts in this project were
similar to Aerospace laboratory studies of
Chemfix, Dravo, and IUCS processes except that
additional commercial processes are being
evaluated. Independent studies of fixation,
including some of the Corps' own ideas, are
planned for the near future. In addition,
field evaluation of current disposal practices
and small-scale field tests of fixation are
planned.
440
-------
Table 150 (continued). ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS DESULFURIZATION
Title:
Contract No.:
Project Description:
Evaluation of Alternate Flue Gas Cleaning
Waste Disposal Sites
Supporting Organization: U.S. EPA
Performing Organization: Unknown
Principal Investigator: Unknown
This project will technically and economically
assess the potential for using abandoned mines,
operating mines, and the ocean as FGC disposal
sites. Small-scale field studies will be
initiated for those alternatives showing promise,
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Flue Gas Cleaning Waste Leachate/Soil Atten-
uation Studies
U.S. EPA
Interagency Agreement with the U.S. Army
Material Command
Unknown
Experiments are being performed to determine
the extent to which heavy metals and other
chemicals from industrial wastes and FGC
Wastes can migrate through (or, conversely,
be attenuated by) soil in land disposal sites.
Currently, 13 industrial wastes and 3 untreat-
ed FGC wastes are included in the program.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Flue Gas Cleaning Waste Leachate/Liner
Compatibility Studies
U.S. EPA
Interagency Agreement with the U.S. Army
Corps of Engineers
Unknown
This project will consist of physical testing
of approximately 18 liner materials which
have been exposed to 2 different FGC wastes
441
-------
Table 150 (continued). ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS DESULFURIZATION
for periods of 12 and 24 months. An economic
study of material and construction/placement
costs will also be performed.
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Development of Flue Gas Cleaning Waste
Disposal Standards
U.S. EPA
Unknown
Unknown
The project will consist of the establishment
of criteria which can ultimately be used to
determine the best alternatives for a given
plant situation, the tentative selection (for
study purposes) of water quality standards
which could be applied to FGC waste disposal
standards or guidelines, the study of the
economic and other effects of applying the
standards selected, and drafting a prelim-
inary set of guidelines which can be used as
a basis for ultimately formulating final
guidelines and determining research and de-
velopment needed to support their formulation.
This effort is expected to take a minimum of
1 year.
Title:
Contract No. :
Kellogg Flue Gas Cleaning Waste Conversion
Pilot Studies
Supporting Organization: U.S. EPA
Performing Organization: M. W. Kellogg
Principal Investigator:
Project Description:
Unknown
Performance of pilot studies of two process
steps which are part of the Kellogg "Kel-S"
process for converting sludge into CaC03 and
elemental S. The process steps to be studied
are (1) the continuous drying/reduction kiln
conversion of FGC waste to CaS (using coal
as the reductant) and (2) the dissolution of
CaS and liberation of H2S. This process
appears to represent a viable alternative to
FGC waste disposal.
442
-------
Table 150 (continued). ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS DESULFURIZATION
Title:
Contract No.;
Project Description:
Processing Lime/Limestone Wet Scrubbing Wastes
for Disposal or Utilization
Supporting Organization: U.S. EPA
Performing Organization: Unknown
Principal Investigator: Unknown
This project consists of two tasks: (1) a
study of fertilizer production using lime/
limestone scrubbing wastes as a filler ma-
terial and (2) a study to characterize lime/
limestone scrubbing wastes physically and
chemically as a function of the operating con-
ditions under which they are produced.
Title:
Contract No.:
Principal Investigator:
\
Project Description:
Conceptual Design/Cost Study of Alternative
Methods for Lime/Limestone Scrubbing Waste
Disposal
Supporting Organization: U.S. EPA
Performing Organization: TVA
Unknown
This project is one of several tasks com-
prising the economic studies of major FGD
processes being conducted by TVA. In this
study several FGD waste disposal methods and
FGD system design and operating premises will
be selected for a detailed economic evaluation
of FGD waste disposal. Currently available
information, such as engineering cost estimates
from the Aerospace contract and fixation ven-
dor estimates from the Shawnee field evalu-
ation will be used in the initial efforts,
with updating as additional information be-
comes available. Alternatives will very
likely include variations in mechanical de-
watering equipment, variations in treatment
(e.g., oxidation to gypsum, chemical fixation),
and variations in ultimate disposal (e.g.,
ponding, landfill).
443
-------
Table 150 (continued).
ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS DESULFURIZATION
Title:
Contract No. :
Performing Organization:
Principal Investigator:
Project Description:
Gypsum By-product Marketing Studies
Supporting Organization: U.S. EPA
TVA
Unknown
This project is one of several tasks comprising
the flue gas desulfurization (FGD) byproduct
marketing studies being conducted by TVA. A
preliminary study conducted by TVA during early
1974 indicated the possibility that production
and sale of abatement gypsum offered a sub-
stantial economic advantage over FGD waste dis-
posal. These new studies include a thorough
evaluation of gypsum producing processes (e.g.,
Chyoda, carbon absorption, CaS03 oxidation)
and a detailed U.S. marketing study of. abate-
ment gypsum for wallboard. Future plans in-
clude studies of abatement gypsum for use in
Portland cement manufacture.
Title:
Contract No.
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Stack Gas Pollution Control Coordination Center
RP209
EPRI
Battelle Memorial Institute
Battelle recently established an information
bank on the status of stack gas cleanup methods
being tested on a large scale at power stations.
In the current project, Battelle will focus on
specific technical problems emerging from
the Coordination Center data base and from
EPRI/Industry Workshops, and will also define
a SOX control research, development, and test-
ing program that would be most responsive to
industry needs. The utility industry is cur-
rently operating, constructing, or planning
over 90 separate stack gas desulfurization
installations.
444
-------
Table 150 (continued). ON-GOING AND PLANNED ACTIVITIES:
FLUE GAS DESULFURIZATION
Title: Removal of Pollutants from Flue Gases
Contract No. :
Supporting Organization:
Performing Organization: U.S. Department of the Interior
Principal Investigator: . A. J. Forney, W. P. Haynes, J. P. Strakey,
G. Cinquegrane, and B. M. Harney
Project Description: Research into various processes for the removal
of SO and NO .
x x
445
-------
PARTICULATE CONTROL DEVICES
Research and development directed to particulate control for stationary
combustion sources has been focused primarily on electrostatic precipita-
tors. Particulate emissions from stationary combustion are primarily a
result of coal combustion. The majority of coal is burned by the utility
sector where electrostatic precipitators have been applied to three-
quarters of the coal-burning capacity. In recent years EPA has supported
many projects directed towards evaluating and improving the performance
of electrostatic precipitators. Areas such as resistivity problems,
changing flow patterns, rapping losses and efficiency (both mass and fine
particulate) have been investigated by EPA and EPA contractors. Much of
the work has been performed by Southern Research Institute including de-
velopment of a mathematical model to predict performance. More recently,
EPRI has supported a number of projects directed towards electrostatic
precipitator performance and problems in the utility industry.
Installation of lime/limestone S0~ scrubbers in the coming years may lead
to more extensive use of wet scrubbers for partial or complete fly ash
removal. Venturi scrubbers will be used in some cases to remove par-
ticulates before the stack gases enter the S0_ scrubber. Some fly ash will
be collected in S02 scrubbers. EPA is currently investigating the effi-
ciency and economics of wet scrubbers for fly ash collection.
In the last 2 years two utilities have installed fabric filters. GCA/
Technology Division has tested fabric filters applied to utility boilers
in both Colorado and Pennsylvania under an EPA contract. EPRI is spon-
soring further tests of the Colorado installation to be performed by
Meteorology Research Institute.
A list of new or continuing projects is presented in Table 151.
446
-------
Table 151. ON-GOING AND PLANNED ACTIVITIES:
PARTICULATE CONTROL DEVICES
Title:
Contract No.
lonizer/Precipitator Fine Particulate Dust
Collection System
RP386
Supporting Organization: EPRI
Performing Organization: Air Pollution Systems, Inc.
Principal Investigator: Unknown
Project Description:
This 1-year project is directed at accomplish-
ing a more effective collection of low-
conductivity fly ash from fossil-fuel-fired
boilers and fine particulate matter by imposing
a higher degree of ionization on the particles.
Scheduled to be completed by December 1975.
Title:
Contract No.
Performance Evaluation of Electrostatic
Precipitators
RP413
Supporting Organization: EPRI
Performing Organization: Southern Research Institute
Principal Investigator:
Project Description:
Unknown
Computer model studies will enable new pre-
cipitator installations to be analyzed. The
mechanisms of electrode failure will be studied,
because these failures are a major source of
plant outages. The study vill also consider
ash from oil-fired boilers. Scheduled to be
completed by June 1977.
Title: '
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Simultaneous Removal of Mercury and S02 From
Combustion and Smelter Flue Gases
U.S. EPA
South Dakota School of Mines
M. C. Fuerstenav
An evaluation of the feasibility of a process
for simultaneously removing both Mercury and
S02'
447
-------
Table 151 (continued). ON-GOING AND PLANNED ACTIVITIES:
PARTICULATE CONTROL DEVICES
Title:
Contract No.
Supporting Organization:
Assessment and Development of Control Technology
Technology Applicable to Removal of Mercury from
S02 Bearing Waste Gases
68-02-1097
U.S. EPA
Performing Organization: .Midwest Research Institute
Principal Investigator: Dr. I. Smith
Project Description: Literature and bench-scale study of processes
for Mercury removal.
Title:
Contract No.
Performing Organization:
Principal Investigator:
Project Description:
Gas-Flow Modeling for Electrostatic Precipitators
RP531
Supporting Organization: EPRI
Flow Research
Unknown
The objectives of this 3-month project are to:
(1) perform a proof-of-concept study for a new
fluid dynamic collector, applicable to electro-
static precipitators, that would utilize fluid
dynamic forces to retain collected particles
and minimize rapping snd re-entrainment losses;
(2) evaluate the use of scale models and ana-
lytic models for the determination of proper
gas-flow distribution in electrostatic pre-
cipitators; and (3) provide case studies of
gas-flow modeling over the range of Reynolds
numbers expected. Scheduled to be completed by
May 1976.
448
-------
Table 151 (continued). ON-GOING AND PLANNED ACTIVITIES:
PARTICULATE CONTROL DEVICES
Title:
Contract No.
Electrostatic Precipitator Plate Rapping and
Reliability
RP532
Supporting Organization: EPRI
Performing Organization: Princeton University
Principal Investigator: 'Unknown
Project Description:
The rapping of collector plates and the depo-
sition of the collected ash into hoppers is a
key issue in the reduction of size and cost as
well as in the improved reliability and ef-
ficiency of the electrostatic precipitator for
the collection of fine particules. This 1-year
project will be a fundamental analysis of the
structural mechanics of collector plate impac-
tion and vibration. Scheduled to be completed
by December 1977.
Title:
Contract No.
Effects of Smoke- and Corrosion-Suppressant
Additives on Particulate and Gaseous Emissions
from a Utility Gas Turbine
RP462
Supporting Organization: EPRI
Performing Organization: KVB Engineering, Inc.
Principal Investigator:
Project Description:
Unknown
EPRI will perform a research program on a full-
scale gas turbine to characterize several
metallic-based fuel additives. It is intent
of this effort to extract representative ex-
haust samples from a utility gas turbine for
analysis of particulate grain loading, partic-
ulate size distribution and composition, opac-
ity, chemical state of the additive-based trace
metals, analysis for polycyclic organic matter,
and gaseous emission levels with and without
fuel additives. Scheduled to be completed by
December 1975.
449
-------
Table 151 (continued).
ON-GOING AND PLANNED ACTIVITIES:
PARTICULATE CONTROL DEVICES
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Development of Standard Laboratory Resistivity
Apparatus and Procedure for Fine Particulate
Characterizations
RP 464
EPRI
Denver Research Institute
Unknown
This 6-month project seeks a relative evaluation
of the various methods used to measure the lab-
oratory conductivity of fly ash and, if possible,
a determination of the best method to adopt as
an EPRI standard for future work. Especially
with less than about 1 percent sulfur, the ash
conductivity becomes a vital parameter in the
determination of the precipitator design.
Scheduled to be completed by September 1975.
Title:
Contract No.
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Technology Evaluation of Particulate and S0«
Scrubbing by Alkali Powder Reactor Methods
RP491
EPRI
Bechtel Corporation
Unknown
The objectives of this 14-month project are:
(1) to evaluate the technology for dry removal
of particulates and sulfur dioxide by a con-
tactor of alkali powder; (2) to assess the
availability, mining, and transportation of
necessary raw materials; (3) to identify those
power stations that might benefit from the
technology; and (4) to conduct liaison between
organizations having special experience with
the technology. Two variations of the process
are available: dry powdered alkali on a fab-
ric filter and dry granular alkali in a fixed-
or moving-bed reactor. Completed April 1975
but additional work is anticipated.
450
-------
Table 151 (continued). ON-GOING AND PLANNED ACTIVITIES:
PARTICULATE CONTROL DEVICES
Title:
Contract No.:
Supporting Organization:
Performing Organization
Principal Investigator:
Project Description:
Experimental Investigation of an Electrostatic
Precipitator with an Acoustic Preconditioner
and Using Resonant Effects
RP539
EPRI
State University at Buffalo, New York
Unknown
The objective of this 1-year research project
is to provide data sufficient to permit an
economic evaluation and design of a resonant
acoustic field as a preconditioner for the
efficient removal of submicron particles in
an electrostatic precipitator. Two experi-
ments will be conducted. In the first, the
optimum frequency and intensity for the ef-
fective coagulation of particles will be de-
termined. In the second, the power savings
in power consumption using resonant acoustic
effects will be determined.
Title:
Contract No.
Development of Agglomerator and New Collector
for Electrostatic Precipitation
RP533
Supporting Organization: EPRI
Performing Organization: Stanford University
Principal Investigator:
Project Description:
Unknown
This 1-year project involves basic studies
into means for the substantial reduction in
the size and cost of electrostatic precipitators
for the collection of fine particulates from
flue gases. Specifically, the project will
develop two key items: an agglomerator and a
nev? collector. The agglomerator will collect
fine particles by interaction with coarse par-
ticles. The new collector will employ advanced
electrical and boundary layer gas-flow tech-
niques and will be immunized against the effects
of high resistivity western fly ash. Scheduled
to be completed by June 1976.
451
-------
Table 151 (continued). ON-GOING AND PLANNED ACTIVITIES:
PARTICULATE CONTROL DEVICES
Title: Determination of the Fractional Efficiency,
Opacity Characteristics and Engineering and
Economic Aspects of a Fabric Filter Operating
on a Uility Boiler
RP534
Contract No.
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
EPRI
Meteorological Research, Inc.
Unknown
The purpose of this 10-month project is to
perform a complete engineering and economic
analysis of the fabric filter at the Nucla
Station of Colorado Ute. This will include
determination of fabric filter fractional ef-
ficiency, opacity characteristics, and an en-
gineering analysis of the economics, relia-
bility, and maintenance of the opacity regula-
tions as a useful framework for comparing
fabric filter installations to other fly ash
collection devices. Scheduled to be completed
by March 1976.
Title:
Contract No.
Performing Organization:
Principal Investigator:
Project Description:
Use of High Expansion Liquid Foams in Submicron
Particle Emission Control
RP362
Supporting Organization: EPRI
Washington State University
Unknown
The objective of this 2-year program is to de-
termine the feasibility of using high- expansion
liquid foams to remove submicron particles from
stack gases. Existing equipment will be modi-
fied and experiments conducted to determine the
relationship between operating variables and
collection efficiencies. The system will be
modeled mathematically.
452
-------
Title:
Table 151 (continued). ON-GOING AND PLANNED ACTIVITIES:
PARTICULATE CONTROL DEVICES
R&D Program for the Control of Fine Particu-
late Emissions from Stationary Sources
Contract No.
Supporting Organization: U.S. EPA
Performing Organization: Midwest Research Institute
Principal Investigator: • L. Shannon
Project Description:
Evaluate existing equipment and new approaches
to control fine particulates.
Title:
Contract No.
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Wet Precipitator Technology and Joint Collection
of SOX and Particulates
68-02-1313
U.S. EPA
Southern Research Institute
Dr. J. P. Gooch
A review and evaluation of wet precipitator
technology, particularly with regard to the
joint removal of SO and Particulates.
X
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Fractional Efficiency of a Utility Boiler
Baghouse
68-02-1438
U.S. EPA (J. Turner)
GCA
R. Bradway
A field testing program to determine the per-
formance of coal-fired utility boiler baghouses
at Nucla, Colorado and Sunbury, Pennsylvania.
Field Testing was completed in April 1975.
453
-------
Table 151 (continued). ON-GOING AND PLANNED ACTIVITIES:
PARTICIPATE CONTROL DEVICES
• • III _ * INI • I ' fc -[- — -- ' ~ •' " .- . - ^ m ^^^
Title: Evaluation of the Controllability of Power
Plants to Meet Emission and Air Quality Stan-
dards and the Convertibility of Gas and Oil-
fired Plants to Coal
Contract No.: 68-02-1477
Supporting Organization: U.S. EPA
Performing Organization: Pedco Environmental Specialists, Inc.
Principal Investigator: Unknown
Project Description:
Title:
Contract No.:
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Evaluation of Venturi Scrubber Systems for
Control of Particulate Emissions from a Coal-
fired Utility Boiler
68-02-1802
U.S. EPA
Meteorology Research, Inc.
Title:
Contract No.
Particle Migration Velocities in Electrostatic
Precipitators
RP363
Supporting Organization: EPRI
Performing Organization: Washington State University
Principal Investigator:
Project Description:
Unknown
The objective of this 2-year project is to
provide information required for better elec-
trostatic precipitator design and to reduce
the degree of empiricism. Washington State
University is the contractor.
454
-------
Table 151 (continued). ON-GOING AND PLANNED ACTIVITIES:
PARTICULATE CONTROL DEVICES
Title:
Contract No.
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Rapping Re-entrainment Losses from Electro-
static Precipltators
68-02-1875
U.S. EPA
Southern Research Institute
Title:
Contract No.
Supporting Organization:
Performing Organization:
Principal Investigator:
Project Description:
Fine Particle Charging System Development
68-02-1490
U.S. EPA
Southern Research Institute
455
-------
APPENDIX A
FORM 67
STEAM-ELECTRIC'PLANT AIR AND WATER QUALITY CONTROL DATA
FOR THE YEAR ENDED DECEMBER 31, 1972
456
-------
m Fora 67
*•» (5-JO rOR*
V} "' «uostr BUREAU
No. 5«-TO08J
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
FOR THE YEAR ENDED DECEMBER 31, 1972
RILL LEGAL NAME OF RESPONDENT
ADDRESS (Civ. Nu«btr, Strtit, City, SUU tnd Zip Codt)
PLANT COOEt
(USE THROUGHOUT THE REPORT)
PUNT KAHE
PUNT LOCATION, INCLUDING COUNTY, STATE, NEAREST POST OFFICE, AkO ZIP CODE
REPORT TO THE
FEDERAL POWER COMMISSION
Hote: This statement should be completed and filed in the
FEDERAL POWER CCMMISSIOH
555 Battery Street Room 1»15
San Francisco California
on or before May 1, 1973
Name, title, and address of officer or other person to-whom
should bQ addressed any communication concerning this report
TELEPHONE NUMBER (ti»t Aril Cod*)
NAME AKO TITLE
ADDRESS
457
-------
TABLE OF, COHTPfTS
PAR'LI - AIR QUALITY CONTROL DATA.
SCHEDULE A - Fuel Quality 2
Section 1 - Plant Fuel Consumption Data 2
Section 2 - Plant Fuel Source Data '3
SCHEDULE B - Operational Data
Section 1 - Fuel Consumption at Boiler No. ___ .5
Section 2 - Boiler Operation During Year, Boiler Mo.,, 5_
Section 3 - Flue Gas Cleaning Equipment 6.
SCHEDULE C - Disposal of Products Collected From Combustion Cycle
at Plant . 7
SCHEDULE D - Air Quality Control, Plant Operation and Maintenance
Expenses ?
SCHEDULE E - Equipment (Design Parameters)
Section 1 - Boiler Data . . 9
S«ctlon 2 - Flue Gaa Cleaning Equipment 16
Section 3 - Stack Data H
FOOTNOTES - Air Quality Control Data . 12
PART I.I - WATER QUALITY CONTROL DATA
SCHEDULE A - Operational Data
Section 1 - Average Cooling Water Use of Plant - CFS .14
Section 2 - Maxinum Water Temperatures and Average Stream
Flows During Months of Winter and Summer Systen
Peak Power Loads .14
Section 3 - Amount of Chemicals Used During the Year 14
SCHEDULE B - Operation and Maintenance Expenses, $1,000
Section 1 - Cooling Water Operation at Plant 1.4
Section 2 - Boiler Water Makeup and Boiler Slowdown treatment 14
SCHEDULE C - Water Use Authority and Liniting Criteria 16
SCHEDULE D - Cooling Facilities
Section 1 - General Decign Data 16
Section 2 - Once Through Cooling 17
Section 3 - Cooling Ponds 17
Section 4 - Cooling Towers 17
SCHEDULE E - Cooling Watar Supply
Section 1 - Once Through Cooling 18
Section 2 - Cooling Ponds 18
Section 3 - Cooling Towers 18
SCHEDULE F - Water Treatmeut
Section 1 - Settling Ponds for Boiler Water Slowdown 19
Section 2 - Settling Ponds for Bottom Ash '19
Section 3 - Provisions for Plant Sewage Disposal .19
FOOTNOTES - Water Quality Control Data 20
458
-------
GENERAL INSTRUCTIONS
(1) An original and five-conformcd copies of this report form properly filled out and
attested shall be filed with the Federal Power Commission on or before the first
day of the fifth month following the close of the calendar or fiscal year for each
plant operated by an electric utility with a steam-electric generating capacity of
25 megawatts or greater during the year covered, provided the plant'is part of an
electric utility system with a total capacity of !50 megawatts or more. This report
form must also be filed for all plants with a steam-electric generating capacity
of 25 megawatts or greater if the plants are located in a National Air Quality
Control Region announced by the National Air Pollution Control Administration
(Appendix A lists the National Air Quality Control Regions) even if they are part
of a system with a total capacity of less than 150 megawatts.
(2) Six copies of the completed form, including the original if the report is typewritten,
shall be returned to the Regional Office of the Federal Power Commission indicated
on the cover. If more than one sheet is required for any pages label them Sheet 1;
Sheet 2; etc. respectively. Retain a copy of the form for your files.
(3) All entries shall be legible and the form shall be suitable for reproduction.
(4) Information shall be furnished for the calendar year. Information on equipment
and facilities shall be reported as of the end of the calendar year.
(5) Part I, Schedules A, B, C, andD, and Part n, Schedules A and B should be reported
in full each year. Part I, Schedule E, and Part II, Schedules C, D, E, and F,
should be completed for 1969 and every fifth year thereafter (1974, 1979, etc.); in
the intervening years (1970, 1971, 1972, 1973," 1975, etc.) the data should be reported
when equipment was: (a) placed in operation during the year; (b) altered during the
year (i. e. installed, remodeled, removed or otherwise changed); or (c) not pre-
viously reported.
t
(6) Actual data are requested; however, estimated or calculated data may be reported,
provided all such data are noted. Estimates should be identified by the letters "Est"
following the entry, calculated data should be identified by the letters of "Cal."
Estimates and calculations should be based on actual operating conditions during the
year. If other conditions are assumed for any estimates or calculations, they should
be specified in a footnote.
(7) Inconsistencies within this form and with other FPC forms should be explained.
(8) No deviation from these instructions should be undertaken without the approval of
the Regional Office of the Federal Power Commission.
(9) Insert the word "none" where it is a true and complete answer to any inquiry. Insert
the words "not applicable" in those sections or parts of sections which do not apply.
(10) All accounting words and phrases are to be interpreted in accordance with the
Uniform System of Accounts for Public Utilities and Licensees prescribed by the
Federal Power Commission. To the extent possible, costs and expenses should be
reported in accordance with the above-mentioned Uniform System of Accounts.
rre for. 47
«.. (6-70)
459
-------
GENERAL INSTRUCTIONS fContMl
(11) Additional statements inserted for the purpose of further explanation of sections or
items should be made on durable paper conforming to this form in size and width
or margin except for the optional plant one-line diagram which may be of a con-
venient size as chosen by the respondent. Inserts should be securely bound in the
report. Inserts should bear the titles of the sections and report form page numbers
to which they pertain.
(12) All communications concerning this-form and all requests for extra copies of in-
dividual pages should be addressed to the indicated Regional Office of the
Commission. Additional copies of the complete form may be obtained from the
Federal Power Commission, Washington, D. C. 20426 at 50 cents per copy.
DEFINITIONS
a, "Respondent", wherever used in this report, means the electric utility, regardless
of type of ownership, in whose behalf the report is made.
b. The "capacity" of a generating unit is defined as the maximum generator nameplate
rating at maximum hydrogen pressure.
C. Boilers having a "common breeching", as used herein, means two or more boilers
whose flue gas outlet ducts are connected to the same ductwork and stack.
d. The terminology and criteria for performance of the flue gas cleaning equipment
shall be as stated in the standards and publications of the Industrial Gas Cleaning
Institute, and the American Society of Mechanical Engineers.
e. The terminology and criteria for performance of cooling towers shall be in ac-
cordance with the standards and publications of the Cooling Tower Institute.
f. The terminology and criteria for performance of condensers shall be as stated in
the standards and publications of the American Society of Mechanical Engineers.
ABBREVIATIONS
Abbreviations as used herein conform to U. S. National Bureau of Standards
Special Publication 304.
KCC Tar* ft
*•* (6-70)
460
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STEAM-ELECTRIC-PLANT AIR AND WATER QUALITY CONTROL DATA
PART I - AIR QUALITY CONTROL DATA
Schedules A, B, C, and D
Instructions
1. Report annually.
2. Assign the same boiler designation to a specific boiler throughout the entire
Part I of the form.
3. All footnotes should be shown on page 12.
4, If more than one sheet is required for any pages label them, for example, as
page 5, sheet 1; page 5, sheet 2; etc,, respectively.
m for* ft
*•» (6-70)
461
-------
•p-
o>
CO
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART I - AIR QUALITY CONTROL DATA
CCKPHlY NAMC "
COMPANY - PLANT COOE
CLANT CAPACITY - MJ
PLANT NAMC
STATE
COUNTY
REPORT FOR YEAR ENDED
OECCMBfR Jl. U
rout OFFICL AMI «'ii' ccoi
Schedule A - Fuel Quality
SECTION 1 - Plant Fuel Consumption Data
R«(,-ert percent sul fur, ashf and motMure i
o
t-j
01
02
OJ
04
• e
cr-
c?
ce
09
10
11
12
.,
VONTH
JAt;.
FF8.
VAR.
AIR.
>'i1
-•;-.E
.'ol r
• 1,-j,
crp.
rcr.
NOV.
OIC.
rrn<
of coal or oil with distinctly
gilAIIJY llll'OHirO UN ' j 5 fll) ... "A-. b.,rr,e.l" 6.-).,
igures as weighted averages for the month to the nearest 0.1 percent (based on weight of fuel cunuuneo). Hrport f^cl
&j if quality is only available on "as received" basis, it may be so reported. If fuel represents a blend ef Jva or
different qualities* this should be described in a footnote.
COAL
CONSUMPTION
1000 Tons
(b)
DTU
per Pound
AVG. I
SULFUR
(d)
AVG. t
ASH
"
AVG. I
MOISTURE
(f)
•
0 1 L
CONSUMPTION
1000 Bbl>
(9) '
BTU
per Gal.
(h)
r
AVG. (
SULFUR
(i)
-
GAS
CONSUMPTION
1000 Vcf.
(j)
BTU
per cu. ft.
00
C"EC< fit
FCOTNOTI'
(1)
-------
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART I - AIR QUALITY CONTROL DATA
COMPANY NAME '
PIAHI SANE
COMPANY - PLANT CODE
REPORT fOH YEAR
DECEMBER 31,
ENDED
19
Schedule A - Fuel Quality (Cont'd)
Section 2 - Plant Fuel Source Data
o
Z
w
z
_J
1»
1<
16
17
II
19
20
21
22
(.)
SOURCE 1
SOUPCE 2
SOURCE }
EOURCE 4
SOURCE 5
SOURCE 6
SOURCE 7
SOURCE 6
AIL otiitR
COH
SOURCE
(BUREAU OF MINES
COAL DISTRICTS)*
(b)
QUANT 1 TY
1000 Tom
U)
OIL
SOURCE
SUPPLIER **
(0)
REFINERY OR
POUT OF ENTRY •••
(«)
.
-
QUANTITY
1000 Bt>l»
(0
CHECK FOP
FOOTNOTE
M""
• Lilt ol Bureau of Mine* Coil Olitrlcti is attached. If tvtllable, glvt na«t and location of «int» (in footnota on piga 12) aupplying aubatanlial portion*
of the coal uird at th* plant and the quantitie* tupplied bjr each nine.
•t If reiUutl oil i> delivered to a coeipany-wlde lank far* for dlitrlbgtlon to »ore than one plant, explain In footnota.
••• Indicate refinery by "(«)" before refinery na«e| Port «f entry by "(P)"| Other by «{fl)". Eaplaln "Other* in footnote.
•••• All footnote* ahoold bo ihown o* paje 12.
-------
STEAM-ELECTRIC PLANT AER AND WATER QUALITY CONTROL DATA
PART I - AIR QUALITY CONTROL DATA
Schedule B --Operational Data
Instructions
(1) "Efficiency of flue gas cleaning equipment (tested or estimated) is to be re-
ported as the percent by weight of solids, or the percent by volume'of gases
removed from the flue gas when the flue gas cleaning equipment and associated
boiler(s) operate at design capacity, and at the capacity factor for the year.
(2) Efficiency of flue gas cleaning equipment shall be reported to the nearest tenth
of a percent.
(3) If a unit of flue gas cleaning equipment is multi-purpose indicate the units tested
and estimated current efficiency in removing each emittant.
(4) If more than one unit of flue gas cleaning equipment serves a boiler, show the
data for each unit and indicate the combined efficiency and net emission rate in
a footnote. Report the operations of such combination of units in lines 25 - 31
and indicate in a footnote the types of units that are combined.
(5) For two or more boilers connected with a common breeching:
(a) Use a separate sheet number 5 for reporting individual boiler fuel consumption
and operation during the year.
(b) If a group of boilers is served by a common fuel feeder so that fuel consump-
tion at the individual boilers is not obtainable, indicate in the appropriate
space all boilers so served.
rrc For. 61
R«. ((-70)
464
-------
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART I - AIR QUALITY CONTROL DATA
PL*
COMPANY - PLANT CODE
REPORT FOR YEAH ENOtO
DECEMBER 31, IS .
SCHEDULE B - OPERATIONAL DATA
A separate sheet (including Sections 1 and 2) should be prepared for each plant boiler.
01
Section 1 - Fuel Consumption at Boiler No.
si
02
0}
04
OJ
06
°?
08
09
10
11
12
IT,
u
15
MONTH
(O
JANUARY
FEBRUARY
k-ARCH
APRIL
MAY
AINE
JULY
AUGUST
SEPTEMBER
OCTOBER
KOVEK9ER
DECEMBER
TOTAL YEAR
COAL (j.000 Tons)
(b)
OIL (1000 Bbls)
(c)
CAS
(1000 Ncf)
(d)
.
CHECK FOR FOOTNOTE* •
Section 2 - Boiler Operation During Year, Boiler No.
Enter as appropriate the following codes 1 thru 7 in columns (b), (c)y (d), and (e),
hours of systen peak need not be shown.
Boiler Operation Code Boiler Operation^
C
L
5
U
o
X
UJ
z
U
17
18
ontinuous nociinal fi
css than full but ot
er ?5f lotd • • * 2
No*load hot atandby
No-load cold standb
Other (explain in f
lines 16, 1? and 18) Actual
Code .
. . 5
ootnote* pg> 12) • • 7
. - VEEKCArS WEEKENDS -* •
During Period
* Of SyStCR
(a)
Average for
consecut i v# four
hours of highest
output
(Code only)
ft)
WINTER FCAX wfFK
SUWI-'ER PEAK '.EEK
LOWEST PO.'EH
Average for Average for
consecutive four consecutive four
hours of lowest hours of highest
output output
(Code only) (Code only)
(c) (d)
Average for
consecutive four
hours of lowest CHECK FOB
^tput FOOTNOTE -
(Code onl.) "
(e) (0
TOTAL HCUF3 OF BOILER CPft">!IOII P"Hlf:G YtAKi . ' — —
aniirp riPAflTY fArrro i»ll«uF n.iRI.'.C YFAR. f( hCEf.T : ' 1
• If fuel consumption is for s group o< boilei-- served b, a co«»on lu.i """'"'"
s* indicate in footnote, .in. i«
Llat all boiler numbers
One-line diagran. .
•• All footnotes should be shown en pag* If*
••• Midnight Friday t« »idniu.H Sunday.
'•<«»
FPC For. 67
«.. 'e-70l
465
-------
STEAM-ELECTRIC PLANT ADR AND WATER QUALITY CONTROL DATA
PART I - AIR QUALITY CONTROL DATA
COMPANY I.*»E
PLANT NAME
COMPANY - PL AM CODE
REPCKT FCa YEAH C:.0£0
DECEMBER 51, 19
SCHEDULE B - OPERATIONAL DATA (Cont'd)
Section 3 - Flue Gas Cleaning Equipment .
w
:e •
— o
-I 2
21
22
23
24
25
26
27
28
2S
30
$1
32
33
34
35
56
(0
BOILER MIW9ER
MECH1MCAL SEPARATORS*
TESTED EFFICIENCY
DATE OF TEST (YEAR/VOSTH/OAY)
ESTIMATED EFFICIENCY AT ANNUAL
OPERATING FACTOR (if no test
during year)
ELECTROSTATIC OR COMBINATION
MECHANICAL-
ELECTRICAL PRECIPITATORS:
TYPE (Code "E" for Electrostal ie,
or WC" for Combination)
TOTAL HOURS FOR THE YEAR DURING
WHICH ALL ELECTRICAL BUS SEC-
TIONS ARE ENERGIZED AND WHILE
BOILER IS OPERATING •
TESTED EFFICIENCY
DATE OF TEST (YEAR/MOUTH/DAY)
STATE NUMBER OF HOURS DURING YEAR
WHEN PRECIPITATOR IS NOT FULLY
OPERATIONAL WHILE BOILER IS
OPERATINC
ESTIMATED EFFICIENCY DURING
PERIODS WHEN BOILER IS OPERATING
BUT WHEN PRECIPITATOR IS NOT
FULLY OPERATIONAL
ESTIMATED EFFICIENCY AT ANNUAL
OPERATINC FACTOR ( If no Ust
during year) *
DESULFJRIZATION SYSTEK: •••
HOURS OF SERVICE DURICS YEAR • t.
TESTED EFFICIEHCY
DATE OF TEST (YEAR/MCI.TH/CAY) __.
ESTIMATED EFFICIENCY AT ANNUAL
OPERATING FACTOR (if no tist
during year)*
OTHER FLUE SAS CLEANING
TYPE (£«pl«in in footnote)
HOURS IN SERVICE DURI'.S »EAR«
BOILER NO.
M
— — •
BOILER t.:.
(O
BOILER NO.
M
•
•H^MMUMm—l-l-IIBBWIBIIIBMVl^M-M
BOILER NO.
(«)
•
HECK FOR
COTMJTE
(O"
•••.[••••^•••l
• E>pl*in in footnote unusual operating conditions
** All footnotes should be shown o<* page 12«
*** Vhen oper»tional
FPC For* 67
Re* (6-70)
466
-------
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART I-AIR QUALITY CONTROL DATA
REPORT FOR YEAR ENDED
DECEMBER
19
SCHEDULE C - Disposal of Products Collected from Combustion Cycle at Plant
Ul •
3L O
— Z
•L_
01
',!
AMOUNT OF ADDITIVES l;5EO (1000 tons')"
*
o
s=
t
— .
_j
02
UJ
••• •
SULFUR CIOXICE
OTHER SULFUR PRODUCT;..
OTHER PRODUCTS ••
LIVEStCKE
. (b)
DOLOMITE
(c)
OTHER ••
':!)
CHICK fCa
FCCTr.O'C
f,\ •••
QUANTITIES (1000 tons)'
TOTAL
COLLECTED
«...
M
SOLO
(c)
PUD
DISPOSAL
(*}
LAI.O
FILL
(e>
WATER
DISPOSAL
(0
OTHER
DISPOSAL
(o)
CHEW 'FOR
FCOTKCTE
(h) •"
** Specify in footnote • . . . ipprontoitte the sum of columns. "c" through "9".
*** All footnotes should be shown on p*ge 12. «•••• [rter purity of acidr < by weight.
SCHEDULE D - Air Quality Control, Plant Operation and Maintenance Expenses
Uf
2o
_JZ
09
10
11
12
13
14
IS
16
)7
\1
J,9
20
CHARGED TOi
(0
FLYASH COLLECTION At;D DISPOSAL
BOTTOM ASH COLL£CTiCK AND DISPOSAL
SULFUR A;.D SULFUR PRCCJCI COLLECTION AND DISPOSAL
COLLECTION AND DISPOSAL OF OTHER PRODUCTS
FRCK FLUE CAS (SPECIFY IN FOOTNOTE)
OTHER AIR QUALITY CONTROL EXPENSES (SPECIFY IN FOOTNOTE)
TOTAL AIR QUALITY CONTROL EXPENSE (TOTAL OF LIKES 09 THROUGH 13 )
REVfWFS FROV AIR CUHITY CONTROL OPERATIONS*
SALES OF FLYASH (IF SOLD AS FLYASH)
SALES OF DOTTOl' i^H (IF SOLD AS HOI TOW ASH)
SALES OF FLYAEH AI,D BOTIOM Aill (IF SOLO IMHiMIKCLEO)
SALES OF SULFUR AND SULFUR PRODUCTS
OTHER REVENUES FRCX AIR QUALITY COMROL OPERAIIONS (SPECIFY III
FOOTNOTE)
TOTAL BY-PRODUCT SALES REVENUE fROK AIR QUALIIY tONlROl
OPf RAT 'IONS (TOTAL OF LINCS 15 IHROUCH 19) iir-i .,.
AMUKT
(»1000)
(b)
$
CHECiC FOR
FOOTtiO'E I/
fc5~"
I/ All footnolet ihoulll be shown on pi 9. 12.
ff-C for* (7
Re. («-?0)
467
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STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART I - AIR QUALITY CONTROL DATA
INSTRUCTIONS - Schedule E - Equipment (Design Parameters)
L Report every five years, or as specified in item (5) of General Instructions, page ii.
2. Report separate data for each boiler and stack: Indicate which equipment and stack(s)
are connected to which boiler by showing data for connected equipment in the same
column.
3. Fuel consumption should be reported as follows: Coal in tons per hour, Oil in barrels
per hour, Gas in thousand cubic feet per hour.
4. Total air flow during full load is to be reported in standard cubic feet per minute and
also in terms of the percent of theoretical stoichiometric at 6CPF and atmospheric
pressure.
5. If more than one unit of one category of flue gas cleaning equipment serves a boiler,
show the data for each unit and indicate the combined efficiency and the net emission
rate.
6. If a unit of flue gas cleaning equipment is multipurpose, indicate the efficiency and
the mass emission rate for each emittant.
7. Design efficiency of flue gas cleaning equipment is to be stated as the percent by
weight of emittant removed from the flue effluent when a plant and flue gas cleaning
equipment and the associated boiler(s) operate at design capacity.
8. The design mass emission rate should be expressed in pounds of particulate matter
or pounds of SO£ (sulfur dioxide) per hour at the outlet from the flue gas cleaning
equipment. It should be expressed in pounds of particulate or in pounds.of specified
other material collected under design conditions of both the plant and the flue gas
cleaning equipment and the associated boiler(s), using current fuels.
9. The flue, gas rate should be expressed in terms of actual cubic feet per minute at
the top of the stack.
10. The exit gas temperature should be expressed in degrees Fahrenheit at the top
of the stack.
11. The exit gas velocity should be expressed in feet per second at the top of the stack.
12. Cost should be reported as the original costs recorded on the utility's books of
accounts and unitizcd as prescribed in the FPC List of Units of Property effective
January 1, 1961. It is realized certain items called for in this report are not specifi-
cally unitized in the referenced list of property units, In this case the most accurate
figure available is desired. In the case of stacks without foundation, include the
stack cost plus those added costs which are essential to the stack operation and
support.
13. All footnotes should be shown on page 12.
FPC for. (T
M« (6-70)
468
-------
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART I - AIR QUALITY CONTROL DATA
PLANT NAME
COMPANY - PLANT CODE
REPORT fta YEAR ENDED
DECEMBER 31, 19.
SCHEDULE E - Equipment (Design Parameters)
PL£A3£ CIRCLE T^: APPROPRIATE '.UVHCRl
(1) Regular Plant Report
(2) Placed in Ope
(3) Altered during
*tion duri«g year
(4) Not previously reported
(5) Amended report
Section 1 - Boiler Data
__.. (a)
BOILER NO.
(b)
BOILER -10.
(O
BOILER WO.
(d)
BOILER NO.
(e)
CHECK FOB
01
BOILER KUV3ES(S)
02 SERVED BY STACK NUMBER
03 RELATED TO GENERATOR NUMBER
0« BOILER MANUFACTURER (Code is shown below)
05 TEAR BOILER PLACED IN SERVICE
ASSCCIATEO TURBO-GENERATING CAPACITY
06 (Megawatts)
MAXIMUM CONTINUOUS STEAM CAPACITY
07 (Thousand pounds/hour)
DESIGN FUEL CONSUMPTIONl IQCjt BATING
08 COAL (Tons/hour)
05 RESIDUAL OIL (Barrels/hour)
JQ GAS (Thousand cubic feet/hour) ,...,.
PERCENT BOILER EFF4CIENCY
11 AT 100J LOAD
12 AT 75* LOAD
lj AT 50} LOAD
A IB FLOW AT 100? LOAD
TOTAL AIR, 'STANDARD CUBIC FEET/MINUTE
14 (incl. Excess Air)
15 PERCENT^ EXCESS AIR USED
WET OR DRY BOTTOM - (Code as "Wet" or
16 "Dry")(For Coal only)
FLYASH REHUECTION -'(Code
17 "Yes" or "No") ^
TYPE OF FIRING (Code as
18 shown below)*"
• BOILER KAriUFACTURERSi
BSW - The Babcock S vi'lcox Cc.
CE - Combustion Engineering, Inc.
ERIG - Erjie City Iron Workt
FW - Foster Wheeler Corp.
RILY - Riley Stoker Corp.
VOOT - Henry Vogt Machine Co., Inc.
OTHE <• Othtr (Specify in footnou)
*• All footnote* should be »ho»n on ptje 12.
••• TYPE Cf FIRING (where applicable, use
•or* than one code):
PCFR ~ Pulverized Coali Front Firing
PCOP - Pulverized Coal: Opposed Firing
PCTA - Pulverized Coali Tangential Firing
CYCL - Cyclone
SPRE - Spreader Stoker
OSTO - Cther Stoker
FLUI - Fluidized 3«d
RfRO - Residual Oil: Front Firing
ROPP - Residual Oili Opposed Firing
RTAN - Residual Oili Tangential Firing
OFRO - Sas: Front Firing
COPP - Casi Opposed Firing
GTAN - Cast Tangential Firing
OTHE - Other (Specify in footnote)
fPC fora (7.
«.. (6-70)
469
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STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART I - AIR QUALITY CONTROL DATA
COMPANY NAVE
LAM
COMPANY - PLANT coot
REPORT FOR TEAR ENDED
DECEMBER 31, 19
SCHEDULE E - Equipment (Design Parameters) - Continued
Section 2 - Flue Gas Cleaning Equipment Data
BOILER NO.
(tO
BOILER NO.
(c)
BOILER NO.
(d)
BOILER NO.
CHECK FCR
FOOTIJOTf
... y
BOILER NUMBERS (Enter sane Boiler Numbers 41
indicated on page S, line 01)
flA'E CtS CLSAMM
19 TYPE (Code as shown below)* ....................
20 DESIGN EFFICIENCY (Percent) ................. ...
21 MASS EKISSIOU RATE (Founds per hour)** .........
22 YEAR PLACED III SERVICE .........................
23 INSTALLED COST (Thousands of dollars)"* ........
2* MANUFACTURER (Code as shown below)"" ....... '.. ,
ELECTROSTATIC AND CO'ai'.JTIfl.
MECHANIC4L-ELECTRI Cil PPECIHTtTORS
25 TYPE (Code as "E" or "C") .....................
26 DESIGN EFFICIENCY (Percent) .............. .• .....
2? HASS EKISSICIi RATE (Pounds per hour)" .........
28 YEAR PLACED IN SERVICE .........................
29 INSTALLED COST (Thousands of dollars)**' ........
50 MANUFACTURER (Code as shown below)**** .........
0£SULFURI?ATlON SYSTEM
31 TYPE (indicate b/ footnote) .....................
32 DESIGN EFFICIENCY (Percent) ....................
33 HASS EMISSION RATE (Pounds per hour)** ..........
34 YEAR PLACED IN SERVICE .........................
35 INSTALLED COST (Thousands of dollars)*" .......
36 MANUFACTURER (Specify in footnote) .............
OTHER FLUE OS CLEANING EQUIPMENT
37 TYPE (indicate by footnote) .....................
38 DESIGN EFFICIENCY (Percent) ....................
39 MASS EMISSION RATE (Pounds per hour)** .........
40 YEAR PLACED IN SERVICE ......................... .
41 INSTALLED COST (Thousands 0* dollars)"* ........
42 M:;i!FACTUR£R (Specify in footnote)
I/All footnotes should be shown on page i2»
* Mechanical Collectors - Type (if nore tlun one typ« is used in • scries, indicate til' explicable codes »nd
explain in footnote)*
CTCl * Sirti^ht-througn-flow cyclone*
IVPE - Impeller ccHector
VENT -, .et collectorl Venturi
wtIC - '.el Collector: Other (Specify in footnote)
BACH - Bajhouie (Fabric Collector)
GRAV - Gravitational or baffled chanper
SCTA * Sin9le cyclone-Conventional reverse flow,
tangential inlet
SCAX - Single cyclone-Conventionsl reverse flow,
axial inlet
KCTA - Multiple cyclones-Conventional reverse
flow) tangential inlet*
KCAI - Vulliple Cyclones-Conventional reverse
flow; a>itl inlet
•• Pounds per hour « Grains/Actual Cu.Fl./ I /Actual Cu.Fl.Vol./Hr./
01 HE - Other (Specif/ in footnote)
•** S*t Instruction 1?, pa;)* $•
• ••• Flut Cas riftmi.ii fi|ui|irri>t f*nufictur*rs (r.«* ptigr 11 for CoU*»)
FPC forei 67
Re. (6-70)
470
-------
STEAM-ELECTRIC PLANT ALK AND WATER QUALITY CQ/UlROL DATA
PART I - AER QUALITY CONTROL DATA
COMPANY NAME
PLANT HAKE
COKPANT - PLANT CODE
REPORT fCR
ENDED
DECEMBER 31,
SCHEDULE E - Equipment (Design Parameters) - Continued
Section 3 - Stack Data
Ul
Ij 2
«5
44
<5
46
47
48
49
50
51
52
53
5*
55
56
5?
f.1
STACK NUMBERS
INSTALLED COST (Thousands of dollars) ( 1 nitruct ion
12, fig, 8)
STACK HEIGHT (Feet above Ground Elevation)
INSIDE DIAMETER OF FLUE AT TOP (inches)
FluE CAS RATE (CUBIC FEET/MI(;UTE)
AT 100J LOAD
AT 751 LOAD
AT 50* LOAD
em G« TfPERjTuftE (DECREES FSP.ENHEIT)
AT 100J LOAD ,
AT 75? LOAD .
AT 50* LOAD
EXIT CAS VELOCITY (FEET/SECOKO)
AT 100? LOAD
AT 75* LOAD
AT 50* LOAD
DISTANCE TO NEXT STACK, CENTER TO CENTER
(FEET)-'
ORIENTATION OF LINE OF STACKS - DEGREES CLOCK-
WISE FROM. TRUE NORTH*'
STACK
NUMBED
(b)
STACK
Nuvers
M
STACK ,
NUVBER
(dl
STACK
NUMBER
(e)
CHECK FC1
fOCTKCTE-
(f)
All footnotes should be shown on ptge 12.
Show position of sticks by stack number to correspond with the identificition in lin« 4J. Enter tru* north on
the diigri*.
Sttcks Orientition DiagrtBI
FLUE GAS CLEAN!»S EQUIP. MANUFACTURERS (See pg. 10]
AAFC - American Air Filter Co., Inc.
AMST • American Standard, Inc.
BELC - Belco Pollution Control Corp.
BUEL - Buell Engineering Co., Inc.
DUCO - The Ducon Co., Inc.
FIKL - Fischer-Klosternan, Inc.
FULL - Fuller Co., Draco Product*
KIRK - Kirk & Blum Manufacturing Co.
KOPP - Koppers Co., Inc.
PPCI - Prtcipitair Pollution Control, Inc.
PAOA - Precipitation Associates of America, Inc.
PLVR - Pulverizing M.rf.nery Division
COTT - Researc' CoC.rell, Inc.
SVRS - S*ver«<:r tlectronaton Corp.
gOP »'7i- Air Correction Division
TORI - The Torit Corp.
WEST - Western Precipitation Division
WHEE - Vheelabrator Corp.
ZURN - Zurn Industries, Inc.
OTHE - Oth«r (Speoif» in footnoU)
FPC fort (7
««. (4-70)
471
-------
4>
•vl
N>
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART I - AIR QUALITY CONTROL DATA
COMPANY NAVE
PLANT NAME
COMPANY - PLANI C00£ JHEPORI FOR YCAR CNOEO
FOOTNOTES
f(
rise
JOTNOK i
SHECT
'ORi
LINE
FOOT
COLUMN
NOTE
TEXT
•
-------
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART II - WATER QUALITY CONTROL DATA
(Applicable to Nuclear and Fossa Fueled Steam-Electric Plants)
Schedules A and B
Instructions
1. Report annually.
2. All footnotes should be shown on page 20.
3. General instructions on pages i and ii also apply to this part of the form.
Schedule A - Operational Data
Instructions
1. In Section 1, the cooling water withdrawals should include amounts taken from lakes,
reservoirs, streams, wells, estuaries and the ocean. When a utility-owned cooling
pond is used, show only the makeup quantities taken from the supplying water bodies.
The discharges should include the amounts of water returned to the water bodies.
2. In Section 2, the maximum temperature "at diversion" refers to the water temper-
ature in the water body prior to any effect by the plant or diverting facilities. The
maximum temperature "at outfall" refers to the water temperature of the cooling
water immediately before it joins the water body. It includes the effects of all
devices used to reduce the temperature.
Schedule B - Operation and Maintenance Expenses
Instructions
1. The operation and maintenance expenses in Section 1 should include such expenses
for pumps, ponds, cooling towers, fans, cooling water intakes and outlets, piping,
and other costs associated with cooling water operation. The operation and main-
tenance expenses for condenser operation should not be included. Costs should be
in accordance with the FPC Uniform System of Accounts prescribed for Public
Utilities and Licensees.
2. The cost of chemical additives should be excluded from the operation and main-
tenance expenses and shown separately as indicated.
FPC form (}
*t» (6-70)
473
-------
STEAM-ELECTRIC PLANT AER AND WATER QUALITY CONTROL DATA
PART II - WATER QUALITY CONTROL DATA
(Applicable to Nuclear and Fossil Fueled Steam-Electric Plants)
FUR YEAR tSOEB
DECEMBER Jl, 19.
PL AM M
COMPANY - PLANT CODE
CAF-ACIIY - My
iUIE
COUNTY
POST OFFICE AND 2IP CCOE
SCHEDULE A -OPERATIONAL DATA
Section 1 - Average Annual. Cooling Water Use of Plant - CFS
u>
X *
— o
_* z
01
02
03
M
AVERSE PATE CF WITHCR«««L FROM WATES BODY O'JRING YEAR
AV-S:;: ^AT£ CF OlSCHASiE TO WATER BODY CURIW YEAR
AVEBAC; R*TE CF CMSU*rTi;\ CUR INS YEAR
M
CHECK FOR
FOOTNOTE •
V,
Section 2 - Maximum Water Temperatures and Average Stream Flows
Durintr Months of Winter and Summer System Peak Power Loads
WINTER PEAK LCAO MONTH **
o
z
w
3E
—1
01
MAJIMUH TEMPERATURE
°e
AT
OIVERSICN
(a)
AT
OUTFALL
Tb)
MONTHLY AVERAGE
FLOW IN RECEIVING
HATER BODY, CFS
(e)
SUKWER PEAK LOAD WONTH ••
MAXIMUM TEMPERATURE
f
AT
DIVERSION
(d)
AT
OUTFALL
f.l
MONTHLY AVERAGE
FLOW IN RECEIVING
WATER BCOY, CFS
(f)
CHECX FCR
FCOTMIE •
(?)
Section 3 - Amount of Chemicals used During the Year
UJ
Z .
3S
05
06
(a)
COCLINS ^ATCR
BOILER WATER
MAKEUP
PHOSPHATE
LBS.
(b)
CAUSTIC
SODA LSS.
(c)
HYDRAZINE
GALS.
M
LIME
LBS.
(«)
ALUM.
LBS.
(f)
CHLORINE
IBS.
M
OTHER
M
CHECK FCR
FOOTNOTE •
0)
SCHEDULE B - OPERATION AND MAINTENANCE EXPENSES, SI, OQO
Section 1 - Cooling Water Operation at Plant
*>
z •
— 0
J 2
0?
08
(.)
ANNUAL OPERATION AND MAINTENANCE EXPENSES
ANNUAL COST OF CHEMICAL ADDITIVES
(b)
CHECK FOB
FOOTNOTE •
(t)
Section 2 - Boiler Water Makeup and Boiler Slowdown Treatment
u
X •
— CJ
W-i
09
10
(.)
ANKUAL OPERATION AND MAINTENANCE EXPENSES
ANNUAL COST OF CHEMICAL ADDITIVES
M
•
CHECK FCR
FCCTT;:TE •
(c)
All footnotes should be shown on ptgr 20*
** Speci fy month.
FPC For* 6?
«t» (6-70)
474
-------
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART H - WATER QUALITY CONTROL DATA
Instructions
Schedules C, D, E. and F
1. Report every five (5) years, or as specified in item (5) of General Instructions, page L
2. If more than one sheet is required for any pages label them, for example as paee 16
sheet 1; page 16, sheet 2; respectively. '
3. Assign the same unit designation to a specific unit throughout the entire Part II of
the form.
4. All footnotes should be shown on page 20.
Schedule C - Water Use Authority and Limiting Criteria
1. Footnote and explain if equipment for monitoring cooling water temperatures is
located at other than points of diversion and outfall.
2. If requested distances do not properly define mixing zone, footnote and describe
in necessary detail.
Schedule D - Cooling Facilities
1. In Section 1, footnote and explain any seasonal use of cooling facilities.
2. Show by footnote in Section 3 if spray ponds are used.
3. The costs called for in Sections 2, 3, and 4 should be reported as the original' costs
' reported on the utility's books of accounts and unitized as prescribed in the FPC
List of Units of Property effective January 1, 1961. In case certain items'are not
specifically unitized in the referenced list of property units, the most accurate
figure available is desired. The costs should include amounts for such items as
pumps, piping, canals, ducts, intake and discharge structures, dams and dikes,
reservoirs, cooling towers, and appurtenant equipment. The costs of condensers
should not be included.
4. In Section 4, show the water cooling range-as the number of degrees (F) the water
is designed to be cooled in the cooling equipment.
Schedule E - Cooling Water Supply
1. The dependable flow requested is the seven-day average low flow discharge expected
to occur not more frequently than once in 10 years.
2 In Section 2, include such other uses of cooling ponds as fishing, boating, camping,
" hiking, residential development, and industrial development.
rn ror« <7
»« (C-70)
475
-------
STEAM-ELECTRIC PLANT Am AND WATER QUALITY CONTROL DATA
PART II - WATER QUALITY CONTROL DATA
COUPMl* NAME
PLANT NAME
COMPANY - PLANT CODE
REPORI FCR TEAR ENDED
DECEMBER Jl,
SCHEDULE C - WATER USE AUTHORITY AND LIMITING CRITERIA
tu
z <
— c
01
02
0}
0*
UJ
z .
— o
05
06
OB
• („>
ISSUING AU'HORITIES OF LICENSES OR -t'wiISl CCL'HIY, STATE, FEDERAL,
OR OTHER. LIST AND DESCRIBE AU'HCRITIES IN FOOTNOTE.
FREQUENCY OF TEMPERATURE MONITORING "OF COOLING WATER EFFLUEMr
CONTINUOUSLY (C), HOURLY (H), DAILY (0), OR OTHER (0).
FOOTNOTE AND EXPLAIN IF OTHER.
DISTANCE »ix IKS zr';r EMENDS c~j:i~ £•.-". FT.
DISTANCE MIXING ZONE EXTENDS F?> :-t=E, FT.
' '•}
MAXIMUM ALLOWABLE TEWERAtURE RISE'CF COOLING WATER (°F)
AT OUTFALL TO RECEIVING WATER BCDY
AT LIMITS OF DEFINED Ml X!.',: ZCNE
HAXIMUH ALLOWABLE TEMPERATURE CF CCSuUS WATER (°f)
JT C'JTFALL TO RECEIVI'.'G WATER BDC"
AT LIMITS OF DEFINED MIXINi ;C!.E
(b)
SUMMER
(b)
WINTER
(c)
CHEC'. FCH
FOOTWE •
(c)
CHECK FOR
FOOTMTE •
SCHEDULE D - COOLING FACILITIES
SECTION 1 - GENERAL DESIGN DATA
iu
— c
_J 3!
09
10
11
12
1}
14
(«)
6ENERAT1NG UNIT IDENTIFICATION NUMBER
RATED GENERATING CAPACITY, MW
TYPE COOLit.G: ONCE-THROUGH, FRESH (OTF)l
ONCE-THROUGH, SALINE (OTS): COOLING POND
(CP)l WET COOLING TO.'ER (wCT)l DRY
COOLING TOWER (OCT)i COMBINATION (C8).
FOOTNOTE AND EXPLAIN COKBINAT IONS.
YEAR COOLING FACILITIES INSTALLED
DESIGNED TEVPEflATUBE RISE ACROSS THE
CONDENSER, Of
DESIGNED RATE OF FLOW THROUGH THE CONOEKSfR,
CFS
(b)
(c)
(1)
(«) '
FOOTNOTE •
(f)
• ALL FOOTNOTES SHOULD BE SHOWN CK PACE 20.
fPC for. 67
*«. (6-70)
476
-------
PART II - WATER QUALITY CONTROL DATA
,
PL*. I ;>M£
COMPANY - PLANT CODE
RFHORT fW T£«« EliOCO
0-CiuBER 51. 19
SCHEDULE D - COOLING FACILITIES - Continued
z.
t_J
x
_J
n
16
11
13
1.3
20
2i
<:£
23
21
25
SECTION 2 - ONCE THROUGH COOLING
(«) '
cmr-.eo RATE CF WITHORAWL AT FULL iP^o, crs
i:,-AKE LGCATICf.S: i/
a, HECTIC'; FROM cEi.ua OF PLAI;T, CESREES
C:C'A:;CE F=j'> CENTER CF PLANT, FT.
;;5TA:.CE FRC'-' S'iCaE, F~ .
iVtSiCj^ DISTANCE B£LO» «t'ER Su°FAC-:, FT.
CLTFiLL LCCA'ICfiSl \]
CIPECTICf. FROM Crr.TER CF PLAMT, CtGRcES
CISTA:.CC FRC1-' CCr.TER Cr PLA'tT, FT.
DISTANCE FRO1.1 SICHE, FT.
AVESAGE OISTA-.Cc BELC« /ATER SURFACE, f .
./ ARE DIFFUSERS USED? FOOTNOTE A;,0 DESCRIBE
1 F "YES."
INSTALLED COSTS, $1,000 ••
(b)
(c)
"
(a]
(*)
CHECK COS.
tOOTNOtJE^"
(0
ar
z
z
-J
25
2?
?S
SECTION 3 - COOLING PONDS
(»)
TCTS!_ SU?-"ACE ASEA, ACRES
"CTAt VCL'.VE, Av.fiE-fE£T
'•;ST;LLE; :CS'S, $1,000 **
M
(c)
(d)
(e)
-
CHECK FOR
FOOTNOTE •
(0
o
z
z
.J
29
1C
n
» 2
71
3*
SECTION 4 - COOLING TOWERS
(.)
T>PE CR1F7-VECKAMCAL (•'), NATURAL ,:.)
LE':CTH, IF AFPllCA3i.Er FEET
«ioT4 cs DIAMETER AT BASE, FEE"
HEIGHT, FEET
.A*ER rcCLII.C RANGE, °F
IHS1ALLEO COSTS, $1,000 **_.
fb)
(c)
(d)
(.)
CHECK FOB
FOOTNOTE '
(f)
U ALTHJUiH KOT REQUIRED, A SKETCH SHO.'.'.S THE LAYOUT CF THE COOLIHC SYSTEM IS DESIRABLE.
• ALL FOOT:.OTES SHCJLO BE SHOWN c:. PAGE 20.
«• S» instruction }, SchtiluU 0, ptgt 15.
477
-------
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART II - WATER QUALITY CONTROL DATA
COHPANY NAME
PLANT SAME
COMPANY - PLASt CODE
REPORI FOR
ENDED
DECEMBER 31, 19_
SCHEDULE E - COOLING WATER SUPPLY
SECTION 1 - ONCE THROUGH COOLING
0
z
w
z
_*
01
02
05
SOURCE(S)
OF
WATER
(0
?-OAY, 10 TEAR
DEPENDABLE FLOW
CFS .
00
AVERAGE
FLOW
CFS
(c)
GENERATING UNITS
SERVED
NO
(t)
NO
(«)
NO
(»)
NO
(S)
f
CHECK FOR
FOOTNOTE •
00
FOOTNOTE A.'.O EXPLAIN ANY DISCHARGE IliTO A DIFFERENT BODY OF WATER, AND .HEN DISCHARGE IS OTHER THAN
DOw;.STREAM FROM WATER INTAKE LOCATION.
SECTION 2 - COOLING PONDS
0
z
UJ
z
^
04
05
06
07
08
SOURCE(S)
OF
WATER
(0
7-DAY, 10 YEAR
DEPENDABLE FtOW
CFS
(b)
AVERAGE
FLOW
CFS
(c)
GENERATING UNITS
SERVED
KO
(•!)
KO
(O
NO
(*)
NO
(«)
PERIOD OF YEAR Pt>,0 IS USED FOR COOL IKS
OTHER USES OF PCI.O
CHECK FOR
FOOTNOTE •
M
SECTION 3 - COOLING TOWERS
O
2
Ul
z
— J
09
10
11
12
J1
TOWER
NO.
(a)
.SOURCE(S) OF
MAKEUP WATER
(b)
PERIOD OF YEAR
USED FOR COOLING
(c)
LOCATION OF
SLOWDOWN
DISCHARGE
(
-------
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART 0 - WATER QUALITY CONTROL DATA
COMPAN
PLANt
COKPA;,
a
x
*
01
02
NAVE
1 - PLAUI CODE
REPORT fO« IlUt tf.UEO
DECEMBER 31, 19 _^
SCHEDULE F - WATER TREATMENT
ECTION 1 - SETTLING PONDS FOR BOILER WATER SLOWDOWN
(a)
FIRST PCNO
SECC'.O P0\0
EVACUA'ICN PRCCES'JRE AND
FREQUENCY OF CLEANING
i'ETHOO
(b)
jiwES PER YEAR)
EST IMTED
PH
(0
SUSPENDED
SOLIDS !>**
OICCMARCE
VOLl'^E CU.
FT. PER YR.
' (0
t,»ye OF
WATER BODY
RECEIVINO-
THE DISCHARGE
1
CHEM f:»
FOCTNC'E •
M
SECTION 2 - SETTLING PONDS FOR BOTTOM ASH
i
UJ
X.
H
03
04
d
2
UJ
yt
3
0=;
06
;o
FIRST FOr.D
SECOI.O PCKO
EVA^UAfluf, FRvt-twUM^
AND fRE?UESCY CF CLEAMKS
KETHOO (TIKES F£» YEAR)
M (e)
•
(a)
FIRST POKD
SECCr.D POSO
EST I^AT £0
H
p
(<)
S'JSPEt.OEO
SOLIDS PF8
(«)
SOURCE CF SLUICIM;
AND CLEiMIiS rfATER
(b)
DISCHARGE
VOLUME -CU.
FT. PER YR.
(f)
NAME OF
WATER BODY
RECEIVING
THE DISCHARGE
(9)
AKOUNT Of ASH TREATED
TONS PER YEAR
(e)
CHiCH FOR
FOOTKCTE •
M
CHECK FOR
FOOTKCTE •
(0)
SECTION 3 - PROVISIONS FOR PLANT SEWAGE DISPOSAL
UJ
z .
_ o
07
g
UJ
X
OR
O"
10
CODE
(a) M
CODE FOR PUBLIC SEWER (PS), SEPTIC TANK (ST J SURFACE «ATER
BODY (SW), OR CTHER (OT). FOOTNOTE IF OTHER AND EXPLAIN.
EFFLUENT TREATMENT OESIGNi
CO
BEFORE TREATMENT
AFTER TREATMENT
•-AIER SCOY RECEIVIN5 THE OISCHARSE
BOD
PPM
(b)
H
l>
(c)
PHOSPHATES
PMM
(O
OTHER
(«)
CHECK FOR
FOOTNOTE •
(c)
CHECK fOR
FOOTNOTE •
(0
• *Lt FOOTNOTES SHOULD 8E SHOWN ON PAGE 20,
FCC For* S?
•t. (t-?0)
479
-------
APPENDIX B
FUEL CONSUMPTION BY MAJOR USE CATEGORIES AND LOCATION
This appendix provides information concerning the consumption of various
fuels used by the electric utility, industrial, commercial/institutional
and residential use categories. Data are presented for fuel use by state
and region.
The purpose of these tables is to provide input data on a statewide basis
to the priority model. The ratio of state to national fuel consumption
can be used to estimate emissions by state from national emissions pre-
sented in the summary tables.
480
-------
Table 152. ELECTRIC UTILITY FUEL CONSUMPTION BY STATE
oo
U.S. total
Key England
Connecticut
Maine
Massachusetts
New Hampshire
Rhode Island
Vermont
Kiddle Atlantic
Now Jersey
New York
Pennsylvania
East North Central
Illinois
Indiana
Michigan
Ohio
Wisconsin
Vest North Central
Iowa
Kansas
Minnesota*
Missouri
Nebraska
North Dakota
South Dakota
South Atlantic
Delaware
District of Columbia
Florida
Georgia
External combustion
Bituminous
103 tons/yr
372,598
1,107
29
0
13
1,031
0
34
45,236
2,349
5,716
37,171
131,589
32,255
26,700
19,614
43,018
9,972
27,816
2,845
1,031
6,898
15,353
1,329
0
355
75,230
928
260
6,553
10,710
Anthracite
103 tona/yr
1,460
0
0
0
0
0
0
0
1,460
0
0
1,460
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
o •
Lignite
103 tons/yr
12,500
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
6,400
0
0
0
0
0
6,400
o •
0
0
0
0
0
Residual oil
103 gol/yr
19,584,050
3,231,415
1,138,103
189,800
1,733,534
77,823
92,000
155
5,430,934
1,552,979
3,199,897
678,058
732,741
252,296
21,950
362,078
59,229
37,188
120,047
9,723
42 , 534
37,769
19,059
4,571
77
6,314
5,630,587
229,131
210,654
2,663,335
135,155
Distillate oil
103 gal/yr
1,117,817
5,232
4,826
0
0
0
406
0
0
0
0
0
140,871
48,561
16,310
51,815
11,568
12,617
75,567
14,667
12,524
27,398
11,048
8, -8 14
440
676
45,833
3,202
0
0
7,690
Gas
106 ft/yr
3,124,690
9,940
C
0
6,600
0
1,900
1,440
25.80Q-
7,700
12,700
5,400
103,400
26,700
9,100
33,000
13,200
21,400
330,700
53,800
153,200
31,200
41,700
42,700
0
3,100
. 186,820
640
0
132,000 '
37,400
Internal combustion
oil
103 gal/yr
2,229,210
102,325
35,470
6,250
43,728
5,341
1,532
9,999
1,051,217
406,392
472,393
172,432
357,442
182,820
7,735
61,772'
75,539
29,576
92,623
11,482
12.470
45,893
12,255
9,416
179
933
450,345
8,841
11,100
138,346
122,024
Gas
106 ft/yr
265,214
797
0
626
0
171
0
0
35,021
• 7,279
25,371
2,371
63,095
15,993
4,731
22,779
7,358
12,234
33,345
6,832
5,896
9,009
5,692
4,832
380
504
48,800
248
0
21,221
5,324
-------
Table 152 (continued). ELECTRIC UTILITY FUEL CONSUMPTION BY STATE'
oo
10
South Atlantic
Maryland
North Carolina
South Carolina
Virginia
West Virginia
East South Central
Alabama
Kentucky
Mississippi
Tennessee
Heat South Central
Arkansas
Loulelana
Oklahoma
Texas
Mountain
Arizona
Colorado
Idaho
Montana
Nevada
New Mexico .
Utah
Wyoming
Pacific
California
Oregon
Washing ton
Alaska
Hawaii
External combustion
Bituminous
103 tons/yr
3,865
19,636
5,446
4,933
22,899
62,387
18,513
22,037
1,181
20,656
2,696
0
0
2
2,694
23,017
463
4,321
0
585
3,812
7,415
971
5,450
3,076
0
0
3,076
444
0
Anthracite
103 lons/yr
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lignite
103 tons/yr
0
0
0
0
0
0
0
0
0
0
5,700
0
0
0
5,700
400
0
0
0
400
0
0
0
0
0
0
0
0
0
0
Residual oil
103 gal/yr
978,505
212,939
159,830
1,018,365
22,623
84,253
0
4,687
79.566
0
682,706
318,769
143,096
7,476
213,365
77,319
232
25,024
0
2,750
18,788
15,069
12,667
2.789
3,263,658
3,261,024
542
2,092
232
330,158
Distillate oil
103 Eal/yr
0
14,643
17,524
2,774
0
169,851
0
909
168.942
0
410,146
13,850
172,380
3,399
220,517
230,868
195,770
1,890
0
5,808
5,656
21,320
424
0 •
39,449
22,491
0
16,958
0
0
Gas
106 ft/yr
3,500
390
12,200
320
370
44,690
4,900
4,990
34,800
0
1,960,800
38,800
334,000
283,000
1,305,000
185,540
25,600
63,300
8
0
28,200
64,600
3,100
730
277,000
27 7 ,.000
0
0
0
0
Internal combustion
Oil
103 gal/yr
66,356
27,096
31,351
44,451
780
55,094
37,694
246
3,130
14,024
10,795
751
3,775
3,406
2,863
38,820
29,012
5,740
52
750
943
911
195
1,217
36,282
14,134
20,422
1,726
24,002
10,260
Gas
106 ft/yr
9,938
314
9,126.
2,637
0
8,999
0
422
7,645
931
22,702
427
3,725
7,365
11,183
22,287
14,317
2.276
0
1,595
2,122
1,352
161
463
14,285
12,645
1,641
0
15,883
0
-------
Table 153. INDUSTRIAL FUEL CONSUMPTION BY STATE
U.S. total
New England
Connecticut
Maine
Massachusetts
New Hampshire
Rhode Island
Vermont
Middle Atlantic
New Jersey
New York
Pcnnsy Ivanla
East North Central
Illinois
Indiana
Michigan
Ohio
Wisconsin
West North Central
Iowa
Kansas
Minnesota
Missouri
Nebraska
North Dakota
South Dakota
Bituminous
103 tons/yr
62.928
1A1
49
8
61
8
8
7
8068
78
2318
5672
27429
4261
5253
5954
9346
2615
5323
1459
414
970
1424
414
321
321
Anthracite
103 tona/yr
364
6.0
1
2
3
342
121
1.
220
8.778
0
0
0
7.000
1.778
1.222
0
0
1.222
0
0
0
0
Lignite
103 tons/yr
2,866
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
800
0
0
0
0
0
800
0
RcsMu.il oil
103 r.nl/yr
8,443,281
1,090,110
305,718
317,310
336,672
60,942
52,458
17,010
1,847,832
638,400
427,476
781,956
1,336,440
506,478
467,124
136,962
184,968
40,908
356,076
5,250
62,622
205,044
51,492
4,074
24,738
2,856
Distillate oil"
103 gal/yr
3,024,840
119,196
41,538
15,960
46,998
5,166
6,132
3,402
369,936
113,736
111,216
144,984
580,860
100,842
107,940
108,654
240,324
23,100
173,166
36,073 '
17,598
36,498
54,432
13,774
3,864
5,922
C.-,sa
106 £t3/yr
8,875,600
64,800
19,000
4,500
27,500
4,500
4,800
4,500
562,400
82,700
127,800
351,900
1,669,900
431,500
239,300
338,900
438,800
171,400
629,900
134,100
175,500
119,300
120,600
72,300
2,000
6,100
Bagasse
103 tons/yr
4,319
0
0
0
0
0
0
0
9
9
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Wood
103 tons/yr
28,645
1.376
0
1,298
3
24
0
51
154
0
0
154
472
1
48
0
9
414
106
0
0
87
15
0
0
4
00
OJ
'External and Internal combustion combined.
-------
Table 153 (continued). INDUSTRIAL FUEL CONSUMPTION BY STATE
South Atlantic
Delaware
District of Columbia
Florida
Geornia
Maryland
North Carolina
South Carolina
Virginia
West Virginia
East South Central
Alabama
Kentucky
Missifsippi
Tennessee
West South Central
Arkansas
Louisiana
Oklahoma
Texas
Mountain
Arizona
Colorado
Idaho
Montana
Nevada
Ncv Mexico
Utah
Wyoming
gaclflc
California
Oregon
Washington
Alaska
Bituminous
103 tons/yr
12,311
925
259
388
388
925
1,440
1,106
2,516
4,364
6,278
2,311
1,868
0
2,099
252
40
30
32
150
2,418
137
536
295
295
137
18
754
246
245
13
232
463
0
Anthracite
10 tona/yr
5.000
3.000
0
0
0
0
1.111
0.889
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1.333
0
0
1.333
0
0
Lignite
103 tons/yr
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2,000
0
0
0
2,000
66
0
0
66
0
0
0
0
0
0
0
0
0
0
0
Residual oil
103 gal/yr
1,941,954
154,132
2,940
359,352
305,172
305,298
292,068
165,144
341,623
16,170
196,812
92,988
31,878
58,968
12,978
473,088
79,254
99,582
53,508
240,744
290,157
106,302
19,57?
1,365
37,800
18,774
•34,482
47,418
24,444
839,412
502,362
115,458
221,592
22,764
48,636
Distillate oil
103 gal/yr
477,834
10,584
1,134
65,436
67,284
69,384
103,152
50,442
80,684
29,734
205,086
60,060
42,924
30,492
71,610
363,678
28,644
102,312
55,440
177,282
313,698
10,122
38,724
30,996
56,910
1,680
21,924
113,862
39,480
398,454
246,582
72,618
79,254
11,970
10,962
Gas
106 ft3/yr
733,000
10,200
61,700
97,000
175,100
61,700
98,100
87,700
54,900
85,600
537,100
161,200
77,500
137,800
160,600
3,462,000
180,200
1,103,100
141,900
2,036,800
374,400
65,900
87,700
-
38,700
10,600
61,200
58,400
51,900
342,100
660,000
60,100
122,000
15,200
230
Bagasse
10 tons/yr
740
0
0
740
0
0
0
0
0
0
0
0
0
0
0
470
2
468
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
3,100
Wood
103 tor.s/yr
8,288
0
0
2,034
2,236
0
2,ol5
677
626
0
2,821
872
68
1.264
597
4,058
2,111
1,624
0
323
1,800
0
2
1,166
632
0
0
0
0
9,466
1,359
4,336
3,771
104
0
-------
Table 154. COMMERCIAL/INSTITUTIONAL FUEL CONSUMPTION BY STATE
00
U.S. total
Mew England
Connecticut
Maine
Massachusetts
New Hampshire
Rhode Island
Vermont
Middle Atlantic
New Jersey
New York
Pennsylvania
East North Central
Illinois
Ind inna
Michigan
Ohio
Wiscons in
West North Central
Iowa
Kansas
Minnesota
Missouri
Nebraska
North Dakota
South Dakota
Bituminous
1Q3 tons/yr
4,519
47
14
0.75
30
0.75
0.75
0.75
737
59
21
657
2,046
245
284
349
789
379
343
35
8
198
56
5
20
21
Anthracite
10-* tons/yr
2,118
2.9
0
0
0.6
0
0
2.3
2,088
111
229
1,748
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Residual oil
103 a
-------
Table 154 (continued). COMMERCIAL/INSTITUTIONAL FUEL CONSUMPTION BY STATE
oo
-
South Atlantic
Delaware
District, of Columbia
Florida
Georgia
Maryland
North Carolina
South Carolina
Virginia
West Virginia
East South Central
Alabama
Kentucky
Mississippi
Tennessee
West South Central
Arkansas
Lnuiu iana
Oklahoma
Texas
Mounta In
Arizona
Colorado
Idaho
Montana
Nevada
New Mexico
Utah
Wyoming
Pacific
California
Oregon
Washington
Alaska
Hawaii
Bituminous
10-* tons/yr
581
6
4
13
14
26
238
160
120
0
585
40
0
31
514
0
0
0
0
0
180
0.62
112
37
30
0.29
0
0
0
0
0
0
0
0
0
Anthracite
103 tons/yr
21
11
0
0
0
10
0
0
0
o •
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
c
0
0
0
0
0
0
Restdunl oil
103 Ral/yr
872,046
44,772
213,234
106,890
104,664
221,676
83,874
8,400
71,442
17,094
60,984
40,866
8,862
2,772
8,484
73,122
19,614
630
4,410
48,468
84,336
0
25,662
6,930
8,736
3,402
2,814
23,436
13,356
399,966
133,098
138,852
128,016
546
3,528
Distillate oil
103 gal/yr
867,636
51,282
35,023
125,496
84,420
138,432
204,246
38,976
181,440
8,316
484,428
128,604
83,938
109,158
162, /08
807,744
80,724
99,540
86,352
541,128
347, SOS
34,230
70,938
27,426
17,472
8,904
66,360'
80,388
41,790
414,162
408,114
6,048
0
0
0
Gas
10° ft3/yr
170,300
2,400
3,200
26,800
35,800
26,500
18,500
13,100
26,600
17,400
119,100
28,300
34,700 '
21,400
34,700
221,800
31,000
41,500
32,900
116,400
139,600
22,300
51.000
7,400
13,900
9,500
18,800
6,300
10,000
190,400
157,800
10,000
221,000
8,400
0
Wood
1C3 tons/yr
0
0
0
0
0
0
0
0
0
0
6.4
0
2.5
3.9
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
63.4
0
63.4
0
0
0
-------
Table 155. RESIDENTIAL FUEL CONSUMPTION BY STATE
oo
U.S. total
New England
Connecticut
Matne
Massachusetts
New Hampshire
Rhode Island
Vermont
Middle Atlantic
New Jersey
New York
Pennsylvania
East North Central
Illinois
Indiana
Michigan
Ohio
Wisconsin
West North Central
Iowa
Kansas
Minnesota
Missouri
Nebraska
North Dakota
South Dakota
Bituminous
103 tons/yr
5,189
13.18
9
0.5
2.71
0.32
0.45
0.20
0
0
0
0
1413.4
689.3
165.6
212.1
267.2
79,2
208
9.2
8.1
49.2
135.4
6.1
0
0
Anlhracl te
103 tons/yr
2,904
55.6
6.3
8.3
26.9
3.5
1.3
9.3
2211.7
41.4
435.3
1735.0
340.6
64.0
40.9
100.0
127.9
7.8
10.6
0
0
10.6
0
0
0
0
I.tRnite
ID3 tons/yr
100
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
100
0
0
0
0
0
100
0
Distillate oil
103 g.-il/yr
16,244,690
2,993,390
713,790
375,280
1,300,120
240,490
213,140
150,570
6,012,720
1,048,880
3,676,150
1,287,690
2,878,260
541,660
445,780
698,230
480,730
711,860
1,288,170
278,830
10,220
623,680
118,800
54,110
143,460
109,070
Gas
105 fc3/yr
5,371,472
131,111
32,872
3,723
87.371
2,360
3,294
1,491
793,322
139,673
353,845
299,804
Wood
103 tons/yr
4.875
155
9
80
13
25
0.3
25
127
8
67
52
1,602,710 279
476,975
178,511
360,730
455,844
130,650
622,483
112,965
112,068
125,168
184,513
60,455
10,886
16,428
28
57
61
45
88
502
16
25
98
327
12
3
21
-------
Table 155 (continued) . RESIDENTIAL FUEL CONSUMPTION BY STATE
•p-
oo
00
South Atlantic
Delaware
District of Columbia
Florida
Georgia
Marylund
North Carolina
South Carolina
Virginia
West Virginia
lEast South Central
AlaV-ma
Kentucky
Mississippi
Tennessee
West South Central
Arkansas
Louisiana
Oklahoma
Texas
Mountain
Arizona
Colorado
Idaho
Montana
Nevada
Ktw Mexico
Utah
Wyaong
Pacific
California
Oregon
Washington
Alaska
Hawaii
Bituminous
103 tons/yr
851.7
0
20.5
24.7
20.0
0
143.3
69.9
330.3
243.0
1450.5
11.6
314.0
7.7
1117.2
883.1
90.6
170.0
120.0
502.5
337.6
.074
56.5
72.
72.
.016
0
187.
22.
32.
0
20.
12.
0
0
Anthracite
103 tons/yr
103.2
5.4
0
0
0
25.4
0
0
8.8
63.6
132.3
0
132.8
0
0
17.6
1.8
3.4
2.4
10.0
11.1
0
0
0
0
0
4.7
0
6.4
20.4
0
0
' 20.4
0
0
Lignite
103 tons/yr
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Distillate oil
103 gal/yr
2,018,480
90,160
69,530
115,510
37,860
438,030
566,310
186,410
472,990
41,630
131,690
9,860
1,620
73,920
46,290
10,120
2,450
1,470
1,270
4,930
208,300
2,350
11,640
99,770
43,310
27,42(5
3,140
16,000
4,670
703,560
18,110
225,730
459,720
0
0
Cas
106 Ct3/yr
407,427
8,828
0
29,863
99,703
91,038
36,309
28,443
56,442
56,796
268,281
72,205 •
93,863
49,158
53,055
555,609
2,450
104,016
92,363
289,943
290,867
38,579
109,222
12,193
27,773
10,325
24,491
51,588
16,696
694,331
631,354
24,471
38.506
5,331
0
Wood
103 tons/yr
-1,380
6
1
39
350
49
350
247
300
38
994
270
198
200
326
469
287
40
81
88
337.7
66.8
14.7
58.3
56.4
12.9
109.6
10.
9.
604.
168.0
263.1
173.0
0
0
-------
APPENDIX C
TRACE ELEMENT CONTENT OF ASH COLLECTED BY USE
CATEGORY (TONS/YEAR) AND OF FUELS
The trace element content of ash collected in the utility, industrial,
commercial/institutional and residential sectors is presented in Tables
156 through 159. These tables, in conjunction with the state fuel con-
sumption figures in Appendix B, can be used to estimate the trace element
content of the solid waste contribution of specific combustion systems.
Table 160 presents the trace element content (ppm) of the various -fuels.
These values have been used as the basis for the emission estimates pre-
sented in the text and for the derivation of Table 156 through 159-
489
-------
Table 156. ELECTRIC GENERATION: ASH TRACE ELEMENTSC
Sb
As
Ba
Be
Bi
B
Br
Cd
Cl
Cr
Co
Cu
F
Fe
Pb
Mn
Hg
Mo
Ni
Se
Te
Tl
Sn
Ti
U
V
Zn
Zr
Bituminous
138
12,000
11,500
670
279
14,800
0
99
0
4,000
1,300
3,500
0
1,200,000
2,200
13,000
5
1,000
4,100
310
83
28
265
163,000
4,200
7,700
6,100
15,300
Anthracite
0.11
10.9
72
3.3
0.11
1.1
0
1.0
0
131
118
83
0
8,900
8.4
15.3
0.4
11
55
0.1
0.11
0.11
1.1
650
0.4
13
36
63
Lignite
3,100
2.1
15
380
0
0
38
50
77
0
51
520
14.5
26
27
75
•
140
900
Tons bottom ash and collected fly ash, 1974.
490
-------
Table 157. INDUSTRIAL: ASH TRACE ELEMENTS2
Sb
As
Ba
Be
Bi
B
Br
Cd
Cl
Cr
Co
Cu
F
Fe
Pb
Mn
Hg
Mo
Ni
Se
Te
Tl
Sn
Ti
U
V
Zn
Zr
Situminous
28
1,200
1,600
100
42
2', 200
0
17
0
600
150
530
0
130,000
390
150
1.4
160
600
90
13
4.2
41
25,000
640
1,200
930
1,900
Anthracite
0.025
3.6
18
0.94
0.025
0.28
0
0.028
0
37
28
23
0
2,100
2.7
4.3
0.001
3.6
15
0.022
0.028
0.028
0.28
190
0.076
4.0
10
15
Lignite
710
0.51
4.4
96
0
0
9.6
9.8
19
0
15
9.0
3.6
6.4
6.9
20
30
190
aTons, 1973, bottom ash and collected
fly ash.
491
-------
Table 158. COMMERCIAL: ASH TRACE ELEMENTS'
Sb
As
Ba
Be
Bi
B
Br
Cd
Cl
Cr
Co
Cu
F
Fe
Pb
Mn
Hg
Mo
Ni
Se
Te
Tl
Sn
Ti
U
V
Zn
Zr
Bituminous
1.9
100
130
8.5
2.6
140
0
1.5
0
62
13
45
0
12,400
32
60
0.069
13
52
3.8
i.o
0.35
3.4
2,140
54
99
77
161
Anthracite
0.21
20
120
6.0
0.21
2.1
0
0.21
0
240
160
150
.0
14,000
18
28
0.058
20
100
0.13
0.21
0.21
2.1
1,200
0.54
26
e
63
96
Tons 1973, bottom ash.
492
-------
Table 159. RESIDENTIAL: ASH TRACE ELEMENTS3
Sb
As
Ba
Be
Bi
B
Br
Cd
Cl
Cr
Co
Cu
F
Fe
Pb
Mn
Hg
Mo
Ni
Se
Te
Tl
Sn
Ti
U
V
Zn
Zr
Bituminous
2.5
166
190
12
5
273
0
2
0
74
19.6
65
0
18,000
46
18
0.007
19
74
4
1.6
0.5
5
3,000
77
143
112
Anthracite
0.3
30
172
9
0.3
3
0
0.3
0
359
270
224
0
20,000
27
42
0
30
148
0.2
0.3
0.3
3
1,790
0.8
39
98
240 1 I43
Lignite
Distillate
2.4
0
30
0.02
0.2
5
0
0
0
0.5
0.44
0.82
0
0.6
0.4
0
0.15
0.3
0.3
0.9
1.2
8
1
0
0
1.6
0
0.36
30
_l -.._j....i....
aTons bottom ash.
493
-------
Table 160. TRACE ELEMENTS IN FUEL, ppm
VO
Sb
As
Ba
Be
Bt
B
Br
Cd
Cl
Cr
Co
Cu
F
Fe
Pb
Mn
Hg
Mo
Ni
Se
Te
Tl
Sn
Tl
U
V
Zn
Zr
Bituminous
0.5
28.0
36.0
2.0
1.0
53.0
15.0
0.4
1500.0
14.0
4.0
13.0
81.0
3500.0
9.0
46.0
0.2
4.0
14.0
3.0
0.3
0.1
1.0
589.0
15.0
28.0
22.0
47.0
Anthracite
0.10
10.00
58.00
3.00
0.10
1.00
1.00
0.10
1500.00
120.00
90.00
75.00
110.00
6800.00
9.00
182.00
0.30
10.00
50.00
0.20
0.10
0.10
1.00
600.00
0.30
13.00
33.00
48.00
Lignite
*
303.0
0.2
1.6
41.0
0.1
2000.0
4.1
4.0
8.0
6.0
31.0
2.0
3.0
5.0
9.0
12.0
80.0
Residual
0.04
0.30
0.67
0.09
0.11
0.17
2.02
16.23
1.78
2.24
10.00
7.25
0.04
2.08
0.02
2.30
50.07
0.14
5.41
1.40
57.14
0.19
Distillate
0.04
0.01
.
0.03
0.13
0.49
-------
APPENDIX D
AIR AND WATER QUALITY STANDARDS
AIR POLLUTANTS
Standards
Certain contaminants have been classified by law as pollutants and for
which maximum allowed ambient levels have been established by the U.S.
Environmental Protection Agency. Table 161 contains a list of these
ambient air standards.
Ambient air quality standards are to be achieved by regulatory activities
as specified in state implementation plans (SIP's) and approved by the
U.S. Environmental Protection Agency. The SIP's contain emission stan-
dards for various types of emission sources and pollutants. In addition,
the Federal government has promulgated new source performance standards
for important classes of emission sources such as coal burning boilers,
petroleum refineries and incinerators. The NSPS promulgated for stationary
fossil fuel boilers by the EPA are exemplified in Table 162. State emis-
sion standards for several western states, some of which are stricter
than the Federal standards, are presented in Table 163.
WATER POLLUTANTS
Standards
The EPA has published proposed criteria for water quality for various
3
types of aquatic environments. These criteria, which are listed in
495
-------
Table 161. AMBIENT AIR STANDARDS'
vo
Species
SOX (as S02)
Farticulate
Carbon monoxide
Oxidant (as Oj)
HOX (as N02)
Nonmethane
Hydrocarbons
(as CH4)
Averaging
period*
AAM
24
8
3
ACM
24
8
8
1
8
1
AAM
24
8
1
8
3™
Air quality standards
Primary
80(0.03)
365(0.14), Ix
75
260, Ix
10.000(9), Ix
40,000(35), Ix
160(0.08), Ix
100(0. 05) L
160(0.24), Ix
Secondary
60(0.02)
260(0.09), Ix
1,300(0.49), Ix
60h
150, Ix
10.000(9), Ix
40,000(35), Ix
160(0.08), Ix
100(0. OS)1
160(0.24), Ix
Episode levels0
Alert
800(0.30)
375
17,000(15)
200(0,1)
282(0.15)
1,130(0.6)
Warning
1,000(0.33)
750
34,000(30)
800(0.4)
565(0.3)
2,260(1.2)
Emergency
2,100(0.79)
1,000
46,000(40)
1,200(0.6)
750(0.4)
3.000(1.6)
Industrial
healthd>e
TLV
13,000(4.9)
-(15)
55,000(47)
200(0. I)3
9,000(4.7)
-(16)
'format for each entry is as follows: STANDARD vig/m @ 760 mmllg & 20°C (Equivalent Value, ppra). The maximum allowable
cxceedance rate, if any, follows. This refers to the maximum number of times per year that the standard may be
exceeded. For example, Ix means the standard may be exceeded only once per year.
^''National Primary and Secondary Ambient Air Quality Standards," Federal Register 36, No. 84, pp 8186-8201.
'"Requirements for Preparation, Adoption and Submittal of Implementation Plans," Federal Register, 35, No. 158,
pp 15486-15502.
^"Occupational Safety and Health Standards, National Concensus Standards and Established Federal Standards," Federal
Register, 35, No. 105, pp 10466-10714.
'"Occupational Safety and Health Standards - Miscellaneous Amendments," Federal Register, 36, No. 157, pp 15101-15107.
fThe averaging period is given in hours unless otherwise specified. AAM means Annual Arithmetic Mean Value and ACM
•eans Annual Geometric Mean Value.
-------
Table 162. PROMULGATED NEW SOURCE PERFORMANCE STANDARDS -
POWER PLANTS
Source category and pollutant
Fossil-fuel-fired steam generating
with >63 x 106 keal/hr (250 x 10*
Btu/hr) of heat input
Coal-burning plants
Particulates
Sulfur dioxide
Nitrogen oxides (as NO )
Oil-burning plants
Particulates
Sulfur dioxide
Nitrogen oxides (as N02>
Gas-burning plants
Particulates
Nitrogen oxides (as Nt^)
New source
performance standard
(maximum 2-hr average)
0.18 g/10 cal heat
input (0.10 lb/106 Btu)
2.2 g/106 cal heat
input (1.2 lb/106 Btu)
1.26 g/106 cal heat
input' (0.70 lb/106 Btu)
0.18 g/10b cal heat
input (0.10 lb/10b Btu)
1.4 g/106 cal heat
input (0.80 lb/106 Btu)
0.54 g/106 cal heat
input (0.30 lb/106 Btu)
0.18 g/10 cal heat
input (0.10 lb/106 Btu)
0.36 g/106 cal heat
input (0.20 lb/106 Btu)
aAt this time there is no NSPS for N0x emissions from lignite-
fired steam generators.
497
-------
Table 163. EMISSION STANDARDS FOR NEW COAL-
FIRED POWER PLANT IN THE WESTERN
UNITED STATES2.a
State
S02
lb/106 Btu
Particulate
lb/106 Btu
NOX
Xb/106 Btu
Federal standards
1.2
0.10
0.70f
State standards
New Mexico
Nevada
Arizona
Montana
Missouri
Arkansas
Oklahoma
Oregon
South Dakota
Colorado
Minnesota
Washington
Nebraska
Idaho
Kansas
North Dakota
Texas
lova
Wyoming
California
Utah
0.34
0.40
0.80
1.00
1.17
1.20
1.20
1.20
1.20
1.28d
1.75
2.33
2.50
2.78
3.00
3.00
3.00
6.00b
_ e
0.15b
0.13
0.13
0.14
0.10b
0.10
0.12
0.20
0.10
0.10
0.40
0.20.
0.15b
0.14
0.14b
0.27b
0.30
0.60
0.10b
0.45
_ c
0.70
_ c
_ c
0.70
0.70
_ c
0.70
0.70
_ c
_ c
0.67
_ c
0.90
_ c
_ c
_ c
0.70
No statewide standards, local standards vary
i i
No standards
Standards given are those in effect in May 1975. Where plant
size affects the emission standard, values are based on 500 MW.
All standards have been converted to units of lb/10^ Btu. Con-
versions from gr/dscf, where performed, were based on combustion
of coal having a noisture-free analysis of 65 pet carbon and
10,800 Btu/lb, burned with 30 pet excess air. County standards
are not included in this table.
The units presented in the regulation are "Ib/hr/MM Btu."
Indicates there are no statewide standards.
Effective January 1, 1980, S02 is restricted to 0.35 Ib/MM Btu.
The current Wyoming 503 emission standard applied to sulfuric
acid plants. There is no current standard for power plants.
The Federal Standard for KCx does not apply to lignite.
498
-------
Table 164, includes not only chemical pollutants but also bilogical
contaminants, heat (temperature limits) and other pollutant forms.
Effluent standards for many source classes have been proposed and are
promulgated by the U.S. EPA. Proposed effluent standards for steam
electric power generating point sources have been published (see Sec-
tion E of this Appendix).
Organic Pollutants
Organic pollutants are particularly troublesome because'of their high
activity with other water stream contaminants. A prime example of this
type of interaction is the large concentration of "possibly carcinogenic
chlorohydrocarbons recently found in the New Orleans drinking water
supply. This situation was brought about by the chlorination of pro-
cessed industrial water containing significant concentrations of hydro-
carbons. Thus, the presumably beneficial effect of chlorine addition
to the drinking water supply may have been negated by its subsequent
reaction with the low level contaminant.
Various organisms are able to methylate mercury by oxidizing the elemental
metal to its divalent state from which it reacts with naturally occurring
hydrocarbons to form methyl mercury. Similar reactions also occur with
elements such as cadmium and selenium.
SOLID WASTE POLLUTANTS
Of the three pollutant media, air, water and solid, the emissions and
effects of emissions in the solid state are least understood. In fact,
the delineation between solid effluents and solid contaminants remains
a gray area. One is often faced with the vexing question - Does solid
waste used as landfill constitute pollution and, if so, at what stage?
In general, a solid waste pile can be considered neutral (other than
as perhaps an eyesore) with respect to the ambient environment until the
499
-------
Table 164. TABULAR SUMMARY OF WATER QUALITY CRITERIA"
Constituent
pH
Alkalinity
Acidity
BOD
Al
HH,
Sb
A*
Ra
».
Bi
'
»r
Agriculture
(Irrigation)
4.3-9.0
—
—
No limit
5.0 mg/1
20.0 mg/1
(20 yr«)
—
—
0.10 mg/1
2.0 mg/1
(20 yrs)
*
0.1 mg/1
0.5 mg/1
(20 yrs)
—
0.75 mg/1 Sen.
1.0 mg/1 Seml-
Tol.
2.0 mg/1 Tol.
—
Agriculture
(livestock)
—
--
—
5.0 ng/1
—
—
0.2 ng/1
—
No limit
—
S.O mg/1
—
Freshwater
(aquatic life)
6.0-9.0
751 natural level
Addition of acids
unacceptable
—
1/20 (0.05)
0.61? Bg/1
—
--
-~
— —
—
•
~
Freshwoter
(wildlife)
6.0-9.0
30-130 mg/1
—
—
— •
~
—
"—
~ *•
—
~~
Freshwater
(public supply)
5.0-9.0
No limit3
No Unit
—
0.5 ng/1
—
0.1 og/1
1.0 og/1
"•"
~
1.0 Bg/1
"~
Marine water
(aquatic life)
6.5-8.5
—
—
—
1/100 (0.01)
96-hr LC5Q
1.5 mg/1
1/19 LD50
0.4 ng/1
1/50 (0.02)b
96-hr LC50
0.2 og/1
1/100 (0.01)
96-hr LC50
0.05 mg/1
1/20 (0.05)
LD50
1.0 tng/1
1/100 (0.01)
96-hr LC50
1.5 mg/1
No limit
1/10 (0.1)
96-hr LC50
0.1 vg/1 (free)
100 ng/1 (Ionic)
Recreational waters
Acceptable -
6.5-8.3
Must be -
5.0 - 9.0
—
—
—
~
—
"*
•••
—
w
o
o
-------
Table 164 (continued). TABULAR SUMMARY OF WATER QUALITY CRITERIA'
Constituent
HC03
Cd
Cl
(free)
C12
(Chloride)
Cr
CO
Cu
(CM)
r
V
r«
pb
u
Agriculture
(irrigation)
No limit
0.01 mg/1
0.05 mg/1
(20 yrs)
No limit
Ho limit
0.1 mg/1
1.0 mg/1
(20 yrs)
0.05 mg/1
S.O
-------
Table 164 (continued). TABULAR SUMMARY OF WATER QUALITY CRITERIA:
Constituent
Ha
Hg
Inorganic
Bg
Organic
Ko
«l
(N03)
(H02>
r
s*
Ka
*4
Agriculture
(irrigation)
0.20 ng/1
10.0 og/1
(20 yr.)
0.01 ng/1
0.05 ng/1
0.2 mg/1
2.0 mg/1
(20 yrs)
No limit
—
0.02 ng/1
No limit
—
Agriculture
(livestock)
Ho limit
1.0 Mg/1
«MK>
No Halt
«••
100 mg/1
Combined
(NOj) & (N02)
10 ng/1
0.05 Dg/1
—
— •
Freshwater
(aquatic life)
——
0.2 ug/1
Tot. cone.
0.05 ug/1
Avg. cone.
0.5 ug/g
Body burden
Cone. Total Hg
0.2 ug/1
Tot. cone.
0.05 ug/l
Avg. cone.
0.5 ug/g
Body burden
Cone. Totl. Kg
—
1/50
96-hr LC_0
""*
—
—
—
•••
Freshwater
(wildlife)
—
O.S vg/g
In fish
—
"
"
—
—
—
"
Freshwater
(public supply)
0.05 ng/1
0.002 ng/1
Total
—
™"
10 mg/1
1 »g/l
No limit
0.01 ng/1
No Unit
0.05 Dg/1
Marine water
(aquatic life)
1/50 (0.20)
96-hr LC50
0.01 Dg/1
1/100 (0.01)
•
1/20 (0.05)
96-hr LCJO
1/50 (0.02)
96-hr LC,.-
0.1 Bg/lio
~
—
1/100 (0.01)
96-hr LC,»
0.1 ug/1 °
1/100 (0.01)
96-hr LC5Q
0.01 mg/1
—
1/20 (0.50)
96-hr LC50
5.0 ug/1
Recreational water*
—
—
~
"
—
25 ug/1
Lakes & res.
50 ug/1
At conflueaca
100 ug/1
Streams
—
—
O
ro
-------
Table 164 (continued). TABULAR SUMMARY OF WATER QUALITY CRITERIA"
Constituent
Tl
U
V
Zn
Viruses
Micro-
Organlsma
Fecal
Conforms
Dissolved
Solids (tot)
Hardness
Suspended &
Settleable
Solids
Temperature
Agriculture
(irrigation)
— —
—
—
•—
~
--
1000/100 ml
2000-5000 mg/1
(Tolerant)
500-1000 mg/1
(Sensitive)
—
No Unit
No Unit
Agriculture
(livestock)
— —
-—
0.1 iag/1
25 mg/1
—
5000 coli- .
forms/ 100 ml"
20.000/100 al"
1000/100 ml"
4000/100 mlb
"
—
~
*•
Freshwater
(aquatic life)
™
— •
—
3/1000 (0.003)
96-hr LCSO
—
™
Bloassay*
(See T.D.S.)
80 ng/1
•
Freshwater
(wildlife)
—
—
—
~-
—
2000/100 nl
2000/100 nl
"
—
—
(Minimized)
maintain nat-
ural pattern
Freshwater
(public supply)
~
™
—
S ng/1
No limit
10,000/100 ml
2000/100 nl
No limit
No limit
— —
Not to detract
from potability
Marine vater
(aquatic life)
1/20 (0.05)
96-hr LC50
0.1 ng/1
1/100 (0.01)
96-hr. LC5Q
0.5 ng/1
1/20 (0.05)
96-hr LC50
1/100- (0.01)
96-hr LCSQ
O.l.mg/1 "
—
— •
"
—
-—
2.0 (3.6F)9-5
1.0 (1.8F)6-8
Recreational waters
—
—
—
—
—
—
2000/100 ml avg.
4000/100 al max.
log mean 2n
200/100 ol
<10Z samples in
30 days to exceed
400/100 ml
"
—
— •
66 P
Ul
o
-------
Table 164 (continued). TABULAR SUMMARY OF WATER QUALITY CRITERIA
;3
Constituent
Toxic
Algae
Botulism
Pesticides
Da la poo
TCA
2.4-D
Insecti-
cide*
Turbidity
Carbon
Adsorbable
Foaming
Agents
NTA
Phenols
Color
Agriculture
(Irrigation)
~
"""
0.2 ug/1
0.2 v&ll
0.1 pg/1
Ho Unit
—
—
M
—
—
Agriculture
(livestock)
Heavy growth of
blue-green not
accepatble
—
See Public
Water Send*.
. ..
—
**
—
._
—
:
—
~
Freshuater
(aquatic life)
— —
—
1/100 (0.01)
96-hr t,C50
Those for which
no toxlclty date
available
—
~
..
—
<10Z change In
C.P.
—
1
—
Comp. pt. not
changed by >10X
Freshwater
(wildlife)
No limit
Minimizes fac-
tors which pro-
mote disease
—
—
~
DDT 1 ag/kg
wet weight
—
—
—
™
Freshuater
(public supply)
—
—
Silvex 0.03
2,3,5-T 0.002
0,02 VB/1
Organophos-
phates 0.1 ng/1
Ho Unit
0.3 mg/1 CCE
1.5 CAE
0.5 mg/1
(ABS)
No limit
1 Mg/1
75 platinum-
cobalt unit*
Marine water
(aquatic life)
—
— •
1/100 (0.01)
96-hr «50
~
—
—
—
—
—
•"~
Recreatiooal waters
— -
—
~
--
•••
—
Clarity - 4 ft.
Secchi
— •
—
"***
-------
Table 164 (continued). TABULAR SUMMARY OF WATER QUALITY CRITERIA"
Constituent
Radio-
activity
Salinity
D.O.
Sulfate
Sulfide*
Detergent*
Oil*
Phthalste
Ester*
PCB'e
Tainting
Substance*
Odor
Light
Agriculture
(Irrigation)
See Federal
Drinking Water
Standard*
•~
~~
—
—
•Mk
—
"
—
~
—
Agriculture
(livestock)
See Federal
Drinking Water
Standard*
3000 ng
soluble
•alts/1
— ••
—
—
~~
—
"
--
—
—
Freshwater
(aquatic Ufa)
See Federal
Drinking Water
Standard*
--
See Table
Section V
—
0.002 mg/1
1/20 (0.05) (LAS)
96-hr LC50
0.2 mg/1 max.
No vlslblo oil
1/20 (0.05)
96-hr LD5Q
Hexonc extract-
able sediment*
1000 mg/kg
0.3 Mg/1
0.002 Mg/1
(In. water)
0.5 pg/g
(in tissue)
Tables 314
—
—
Freshwater
(wildlife)
~
No rapid
fluctuation
—
—
--
"-
No visibl*
floating oil*
—
Ho Increase
—
—
<10% change
in C.P.
Freshwater
(public oupply)
See Federal
Drinking Water
Standards
—
No limit
saturation
preferred
250 Dg/1
—
—
No Unit
No Unit
~
Free
—
Marine water
(aquatic life)
See Federal
Drinking Water
Standards
~
6.0 ng/1
~
—
~
No film or odor
No tainting of
fish
No onshore oil
deposit
—
~
—
—
—
Recreational water*
—
—
—
—
—
~
—
•w
—
—
—
*"No Holt," where it appear* in this table, refer* to constituent* that were addressed but for which it vaa indicated that insufficient data existed
for prescribing limits.
bLCjQ values are the concentration levels which if exceeded over the tine period specified will prove fatal to 50 percent of fish.
clf cooper or zinc 1* present > 1 Bg/l, then AT - 0.001 LC$o>
Average Of a •Inlenu* of 2 *uple* per Bonth.
'individual •*•?!*.
-------
constituents of the waste pile interact with air, water (ground or
surface) or soil. Since solid wastes are often placed in clay, asphalt,
rubber or plastic liners, these cross media effects often have a long
time lag before environmental degradation begins. Therefore, in assess-
ing solid waste effects, factors such as liner breakage, diffusion rates
through liners, evaporation rates, leaching rates, and runoff composition
must be estimated in order to determine which solid effluents eventually
appear in which media and at what rates. For these reasons there are
no emission or ambient solid waste standards; however, effluents to air
and water which are initially removed as solid waste must be taken into
account in emissions to the former media.
Since solid samples are considerably more difficult to analyze chemically
than air or water samples, solid waste piles are usually characterized
by broad parameters such as pH, BOD, COD, anion content, bilogical param-
eters, etc. Leaching rates from solid waste piles determine the magnitude
and type of solid and water pollution. Since leaching rates range from
almost nothing to 100 feet per year depending upon soil type, runoff,
ground water levels, and liner permeability, pollution problems associ-
ated with solid waste disposal may develop immediately or may have time
lags of several years from plant start-up dates.
Ground and surface water pollution from sanitary landfills occurs through
two different leaching processes. The first process is the dissolving
of solid and liquid pollutants present in a landfill by excess water and
their subsequent transportation out of the fill into surface or ground
water reservoirs. The second process is the solution of (XL produced by
bacterial action on organic compounds, in the ground water adjacent to
the fill, and the consequent solution of minerals, mainly carbonates and
bicarbonates, resulting in excessive alkalinity and hardness of the ground
water.
506
-------
OTHER POLLUTANTS
Thermal Water Pollution '
Introduction - A power plant can release heat into the environment in
several ways. Some of the heat generated during fossil fuel combustion
will escape through stacks. An even greater amount is lost to cooling
water used in condensers. The amount of heat rejected to cooling water
represents about 45 percent of the heating value of fossil fuels used
in the most efficient plants. Overall, more than 80 percent of all
thermal water pollution in the United States comes from electricity gen-
9 10
erating plants. It has been predicted that by the year 2000 the
electric power industry will require four times as much cooling as was
needed in 1965, thereby presenting a potential fourfold increase in
thermal water pollution. In the cooling process heat can be released
directly to a nearby body of water or indirectly via water droplets
evaporated from a cooling tower.
Effects11' of ThermalPollution
The deleterious effects of higher than ambient water temperature are:
(a) Decreased dissolved oxygen content;
(b) Increased reaction rates between primary contaminants
which yield secondary pollutants;
(c) Lethal or harmful effects on fish and other aquatic
organisms;
(d) Harboring of pathogenic disease causing organism;
(e) Decrease in attractiveness of recreational waters;
(f) Adverse effects on adjoining land ecology;
(g) Decreased crop growth and yields due to decreased
effectiveness of irrigation water;
(h) Decreased ability of surface waters to self-purify.
507
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The last effect is a direct result of (a) since dissolved oxygen is
necessary to oxidize organic pollutants. An example of harmful effects
upon aquatic organisms is the rate of shell growth of the clam Meroenaria
mercenaria as a function of temperature which peaks at 20 C and falls
off symmetrically with a half width at 12°C.
Standards - Since surface water temperatures vary widely with geographical
location and climate, no fixed criteria for ambient temperatures can be
set. However, standard regulating thermal discharges have been proposed.
The following conditions are considered to detract from water quality:
• Water temperature higher than 85°F (29.4°C);
• More than 5 F water temperature increase in excess of that
caused by ambient conditions;
• More than 1 F hourly temperature variation over that caused
by ambient conditions;
• Any water temperature change which adversely affects the
biota, taste, odor, or the chemistry of the water:
• Any water temperature variation or change which adversely
affects water treatment plant operation (e.g., speed of
chemical reactions, sedimentation basin hydraulics, filter
wash requirements, etc.);
e Any water temperature change that decreases the acceptance
of the water for cooling and drinking purposes;
• Any irrigation water temperature which significantly in-
fluences soil temperature.
Cooling Tower Plumes - As a result of the National Environmental Policy
Act of 1969, once-through cooling systems have begun to be replaced by
several alternative heat removal techniques. Among these alternatives
are cooling towers which are basically air-water heat exchangers which
allow for the transfer of much of the cooling water heat content to
ambient air. One of the principal environmental disadvantages of cool-
ing towers, particularly the more common wet variety, is the formation of
visible plumes of water droplets.
508
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The more serious visible pollution associated with plume formation are
ground level fog, icing, snow formation and salt deposition. These
effects, as well as the extent of the plume, are functions of ambient
temperature, wind conditions, water droplet composition, cooling tower
emission rate, and relative humidity.
A frequently invoked, yet incorrect, criteria for plume visibility is
the attainment of 100 percent relative humidity. In fact, three pro-
cesses lengthen the visible part of the plume: nonuniform distribution
of water vapor droplets in the plume, finite droplet evaporation time
and droplet vapor pressure lowering due to dissolved condensation nuclei.
Visible pollution resulting from plume formation is generally quite
localized and becomes problematic only in certain situations, such as
low level fogging of a highway or interference with airplane navigation.
Natural fog formation is generally more common and more severe.
Noise
Noise can be defined as unwanted sound or sound without intrinsic value.
In general, the higher the noise level the larger the disturbance and the
more intermittent, the greater the annoyance. Some of the complex effects
13
of noise pollution, considered important by the EPA, are:
• Hearing damage;
• Other health effects such as alteration of the function
of the endocrine, cardiovascular, and nervous system;
• Behavioral effects such as interference with concentra-
tion ability;
• Sleep interference;
• Communication interference;
• Effects on animals;
509
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While there are no federal regulations proposed for ambient noise levels,
14
the EPA has identified noise levels, which, if exceeded, may be dele-
terious to the public health and welfare.
510
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EFFLUENT GUIDELINES AND STANDARDS.FOR STEAM ELECTRIC POWER
vCc, „**.„ ^ ENVIRONMENTAL PROTECTION AGENCY
EFFLUENT GUIDELINES AND STANDARDS FOR STEAM ELECTRIC POWER GENERATING
40 CFR 423; 39 FR 36186, October 8, 1974, Effective November 7 1974- 40 FR
7095, February 19, 1975: 40 FR 23987. June 4, 1975)
TMe 40—Protection of the Environment
CHAPTER I—ENVIRONMENTAL -
PROTECTION AGENCY
IFBL 274-6]
SUBCHAPTER N—EFF1.UENT GUIDELINES AND
STANDARDS
PART 423—STEAM ELECTRIC POWER
GENERATING POINT SOURCE CATEGORY
AUTHORITY: Sees. 301, 304 (b) and (c),
306 (b) and (c), 307(c) and 501(a.) at the
Federal Water Pollution Control Act, as
amended (33 U.S.C. 1215, 1311, 1314 (b) and
(c). 1316 (b) and (c), 1317(c) and 1361(a)),
68 Stat. 816 et seq.: Pub. L. 92-500.
Subpart A—Generating Unit Subcategory
§ 423.10 Applicability; description of
the generating unit subcalegory.
The provisions of this subpart are ap-
plicable to discharges resulting from th3
operation of a generating unit by an es-
tablishment primarily engaged in the
generation of electricity for distribution
and sale which results prims rilv from a
process utilizing fossil-type fuel (coal.
oil, or gas) or nuclear fuel in conjunc-
tion with a thermal cycle employing the
steam-water system as the thermcdy-
namie medium.
§423.11 Specialized definitions.
For the purpose of this subpart:
(a) Except as provided below, the
general definitions, abbrtv;ations and
methods of analysis set forth in 40 CFR
Part 401 shall apply to this subpart.
(b) The term "generating unit" shall
mean any generating unit subject to ll.e
provisions of this part, except those units
definec' below as small, or old.
The term "once through cooling-
water" shall mean water passed through
the main cooling condensers in one or
two passes for the purpose of removing
waste heat from the generating unit.
(1) The term "recirculatcd cooling
water" shall mean water which Is passed
through the main cooling condensers for
the purpose of removing waste heat from
the generating unit, passed through a
coohnr device for the purpose of remov-
ing such heat from the water and then
passed axam, except for blowdown.
through the main cooling condensers.
|40 FR 7095, February 19, 1975|
im> The term "cooline pond" shall
moan any manmnde water impoundment
which does not impede the How of a
navigable stream and which is used to
remove waste heat from heated con-
denser water prior to returning the re-
circulatcd coaling water to the main
condenser.
(n) The term "cooling lake" shall
mean any manmarie water impound-
ment \\hich impedes the flow of a navi-
gable stream and which is ur,ed to re-
move waste heat from heated condenser
water prior to recirculating the water to
the main condenser.
§ 423.12 Effluent limitation* £iii
representing l!u* decree of diluent re-
duction attainaMc by tlie. application
of llie bcM practicable control Iceli-
lioloRj- current!? available.
-------
(b) The following limitations establish
the quantity or quality of pollutants or
pollutant properties, controlled by this
section, which may be discharged by a
point source subject to the provisions of
this subixu I after application of the best
practicable control technology currently
available:
(1) The pH of all discharges, except
once through cooling water, shall be
within the range of 6.0-9.0.
(2) There shall be no discharge of
polychlotinstcd biphcnyl compounds such as
those commonly used for transformer fluid.
[40 FR 7095. February 19, 1975)
(3) The quantity of pollutants dis-
charged from low volume waste sources
shall not exceed the quantity determined
by multiplying the flow of low volume
waste sources times the concentration
listed in the following table:
Averaee of d:\ily
Effluent Maximum for values for ilnriy
characteristic any one day consrcuiivcdays
shall not exceed
TSS lOOms/l 30m»/l.
Oil and Grease 20 nig/1 15 mg/1.
(4) The quantity of pollutants dis-
aharged in ash transport water shall not
exceed the quantity determined by multi-
plying the flow of ash transport water
times the concentration listed in the fol-
lowing table:
(40 FR 7095, February 19, 1975]
Arerace of daily
Effluent Maximum for values for llnriy
characterisUc auy one day consecutive days
suall not exceed
TSS 100n«/l 30 me/I.
Oil aud Grease 20 r.ig/1 15 mg,1.
(5) The quantity of pollutants dis-
charged in metal cleaning wastes shall
not exceed the quantity determined by
multiplying the flow of metal cleaning
wastes times the concentration listed in
the following table:
Effluent
characteristic
e of daily
Maximum for values for linn v
any one day
consecutive days
aliau not exceed
TSS 100 well- 30 me/I.
OH and Grruse '.'Omul 15 me/1.
•,'opper. Tolcl l.Omc/1 1.0 mc/L
Irou, Total — l.Omg.'l, 1.0 me/).
(6) The quantity of pollutants dis-
charged in boiler blowdown shall not ex-
ceed the quantity determined by multi-
plying the flow of boiler blowdown times
the concentration listed in the following
table:
Averace ofdally
Effluent Maximum for values for thirty
characteristic any one day consecutive d;iy3
Bhall not exceed
TSS I00mj/l MmR/l.
Ot! and Orrasc 20 jric/1 15 mfifl.
Copl*T. Total 1.0 nd .— 1.0 rug/1.
Iron, Total l.Ocig.l . 1.0 mg/L
(7) The quantity of pollutants dis-
charged In once through cooling water
shall not exceed the quantity determined
by multiplying the flow of once through
cooling water sources times the concen-
tration listed in the following table:
Effluent Maximum Avcrw
Characteristic Concentration ConceaitraUon
Free available 0.5 mgfl 0.2 mg/t
chlorine.
(8) The quantity of pollutants dis-
charged in cooling tower blowdown shall
not exceed the quantity determined by
multiplying the fiov- of cooling tower
blowdown sources times the concentra-
tion listed in the following table:
Effluent Maximum Avera-n
Characteristic Concentration Concentration
Free available O.img/1 OJmg/L
chlorine.
(9) Neither free available chlorine nor
total residual chlorine may be discharged
from any unit for more than two hours in
any one day and not more than one unit
in any plant may discharge free avail-
able or total residual chlorine at any one
time unless the utility can demonstrate
to the regional administrator or State, if
the State has NPDES permit issuing au-
thority, that the units in a particular
location cannot operate at or below this
level of chlorination.
(10) In the event that waste streams
from various sources are combined for
treatment or discharge, the quantity ot
each pollutant or pollutant property con-
trolled in paragraphs (b) (1) through
(9) of this section attributable to each
controlled waste source shall not exceed
the specified limitation for that waste
source.
[40 FR 7095. February 19, 1975J
§ 423.13 Effluent limitations fruidclines
representing the decree of effluent
reduction attainable by the applica-
tion ot" the best nvailablc technology
economically achievable.
The following limitations establish the
quantity or quality of pollutants or pol-
lutant properties, controlled by this sec-
tion, which may be discharged by a point
source subject to the provisions of this
subpart after application of the best
available technology economically
achievable:
(a) The pH of all discharges, except
once through cooling water, shall be
within the range of 6.0-9.0
-------
Effluent Maximum Average
Clurftclorfetlc Concentration ConctmlruUoa
Frw
O.Smg/1 OJmg/1.
Average of dally
Maximum for values for thirty
anyone day consoculivcdays
shull not exceed
Zinc 1.0 me/I t.omcl.
Chromium 0/2 niL'/l 0.2 mcA.
'Ptimphonls SO in;:/! 5.0 mc/1,
OUie* corrosion Limit to be established on a case
Inhibiting by case ba^is.
materials.
(j) Neither free available chlorine nor
total residual chlorine may be discharged
from any unit for more than two hours in
any one day and not more than one unit
in any plant may discharge free avail-
able or total residual chlorine at any
one time unless the utility can demon-
strate to the regional administrator or
state, if the state has NPDES permit
issuing authority, that the units in a
particular location cannot operate r.t or
below this level of chlorination.
(k) In the 'event that waste streams
from various sources are combined for
treatment or discharge, the quantity of
each pollutant or pollutant property con-
trolled in paragraphs la) through (j) of
this section attributable to each con-
trolled waste source shall not exceed the
specified limitation for that waste source.
(1) There shall be no discharge of heat
from the main condensers except:
(1) Heat may be discharged in blow-
down from recirculated cooling water
systems provided the temperature at
which the blowdown is discharged does
not exceed at any: time the lowest tem-
perature of recirculating cooling water
prior to the addition of the make-up
water.
(2) Heat may be discharged In blow-
down from recirculated cooling water
systems which have Leen designed to dis-
charge blowdown water at a tempera-
ture above the lowest temperature of re-
circulated cooling water prior to the
addition of make-up water providing
such recirculating cooling systems have
been placed in operation or are under
construction prior to the effective date
of this regulation.
(3) Heat may be discharged In blow-
down (overflow) from a cooling pond or
cooling lake where the owner or opera-
tor of a unit otherwise subject to this
limitation can demonstrate that a cool-
Ing pond, or cooling lake In service or
under construction as of the effective
date of this regulation, is used to cool re-
circulated cooling water before it is re-
circulated to the main condensers.
[40 FR 7095, February 19, 1975)
(4) Heat may be discharged where
the owner or operator of a unit otherwise
subject to this limitation can demon-
strate that sufficient land for the con-
struction and operation of mechanical
draft evaporative cooling towers is not
available (after consideration of alter-
nate land use assignments) on the prem-
ises or on adjoining property under the
ownership or control of the owner or
operator as of March 4. 1974. and that
no alternate recirculatlng cooling system
Is practicable.
(5) Heat may be discharged where
the owner or operator of a unit other-
wise subject to this limitation can dem-
onstrate that the total dissolved solids
concentration in blowdown exceeds 30,-
000 ing/1 and land not owned or con-
trolled by the owner or operator as of
March 4. 1974. is located within 150
meters (500 feet) in the prevailing down-
wind direction of every practicable loca-
tion for mechanical drnft cooling towers
and that no alternate recirculating cool-
ing system is practicable.
(6) Heat may be discharged where the
owner or operator of a unit otherwise
subject to this "limitation can demon-
strate to the regional administrator or
State, if the State has NPDES permit
issuing authority, that the plume which
must necessarily emit from a cooling
tower would cause a substantial hazard
to commercial aviation and that no alter-
nate recirculated cooling water system
is practicable. In making such demon-
stration to the regional administrator or
State the owner or operator of such unit
must include a finding by the Federal
Aviation Administration that the visible
plume emitted from a well -opera ted cool-
ing tower would in fact cause a substan-
tial hazard to commerical aviation in the
vicinity of a major commercial airport.
(m) The limiuiion ol parjirjph "1"
of this section shall become effective on
July 1,1981.
>n) In the event that a regional re-
liability council, or when no functioning
regional reliability council exists, a major
utility or consortium of utilities, can
demonstrate to the regional administra-
tor or State, if the State has NPDES
permit issuing authority, that the system
reliability would be seriously impacted
by complying with the effective date set
forth in paragraph (m) above, the re-
gional administrator may accept an al-
ternative proposed schedule of compli-
ance on the port of all the utilities
concerned providing, however, that such
schedule of compliance will require that
units representing not less than 50 per-
cent of the affected generating capacity
shall meet the compliance date, that
units representing not less than an addi-
tional 30 percent of the generating
capacity shall comply not later than
JtU" 1.1932 and the balance of units shall
comply not later than July 1,1983.
§ 423.14 (Reserved]
§ 423.15 Standards of performance for
new sources.
The following standards of perform-
ance establish the quantity or quality of
pollutants or pollutant properties, con-
trolled by this section, which may be
discharged by a new source subject to
the provisions of this subpart:
(a) The pH of all discharges, except
once through cooling water, shall be
within the ranee of 6.0-9.0.
(b) There shall be no discliarge of
polychlormated biphcnyl compounds
such as those commonly used for trans-
former fluid.
(40 FR 7095. February 19,1975]
(c) The quantity of pollutants dis-
charged from low volume waste sources
,shall not exceed the quantity determined
by multiplying the flow of low volume
waste sources times the concentration
listed in the following table:
Effluent
characteristic
Maximum ftr values for thirty
any one day coiwvutive days
TSS ................ lOOmir/l ......... 30 me/t
Oil and Crease ..... 20 jiig/1 ........ ..
(d) The quantity of pollutants dis-
charged in bottom ash transport water
shall not exceed the quantity determined
hy multiplying the How of bottom ash
transport water times the concentration
listed in the following table and dividing
the product by 20:
E (Burnt
characteristic
Maximum for
auy OD« day
Average of tluily
values for thirty
CGitsoculivc day*
EbaJl not exceed
TSS looms;!. SOmit/!.
Oil and Grease 20mgA 15 ing/l.
(e) There shall be no discharge of TS3
or oil and grease in fly ash transport
water.
(f) The quantity of pollutants dis-
charged from metal cleaning wastes shall
not exceed the quantity determined by
multiplying the flow of metal cleaning
wastes times the concentration listed In
the following table:
Average of daily
Effluent Maximum for Tallies for thirty
characteristic any one day cons-xutive dayl
shall not rxcev-tt
.
Oil and C.rease 'JO me/t 15 mg/l.
CopiH-r. Total . 1.0rriE/l 1.0 roft.1.
Iron, Total . l.Omg/1... 1.0 rug/U
(S> The quantity of pollutants dis-
charged in boiler blowdown shall not ex-
ceed the quantity determined by multi-
plying the flow of boiler blowdown times
the concentration listed in the following
table:
Average of daily
Effluent Maximum for values fur thirty
characteristic any one day con>wutive days
shall nut exceed
TSS ............. 100 roe/1 ......... 30in«1.
Oil and Crease ..... 20ms/) .......... 15 mf/l.
Copper. Total ...... l.Omp/1 ......... 1.0 nifiL
Iron, Total ........ l.Omg/l ......... I.Oms/1.
(h) The quantity of pollutant? dis-
charged in once through cooling water
shall not exceed the quantity determined
by multiplying the flow of once through
cooling water times the concentration
listed in the following table:
Effluent
Characteristic
chJorioo,
Maximum
Concentration
05 mg/l . ...
Avenwr*
ConcealtttUos
02mc/t
(i) The quantity of pollutants dis-
charged in cooling tower blowdown
shall not exceed the quantity determined
by multiplying the flow of cooling tower
blowdown sources times the concentra-
tion listed In the following table:
513
-------
Kfflumt
Minimum
Coiict>ntTBUon
Conc*nli*Uon
Free
clilorine.
0.5 mc/1. 0.2 ing/).
f of this section attributable to -each
controlled waste source shall not exceed
the specified limitation for that waste
source.
(1) There shall be no discharge of
heat from the main condensers except:
(1) Heat may be discharged in blow-
down from recirculated cooling water
systems provided the temperature at
which the blowdown is discharged does
not exceed at any time the lowest tem-
perature of recirculated cooling water
prior to the addition of the make-up
water.
(2) Heat may be discharged in blow-
down from cooling ponds provided the
temperature at which the blowdown is
discharged does not exceed at any time
the lowest temperature of recirculated
cooling water prior to the addition of
the make-up water.
§ -123.16 Prctrealmem standards for new
sources.
The pretreatment standards under sec-
tion 307(c> of the Act for a source within
the generating unit subcategory. which is
a user of a publicly owned treatment
works (and which would be a new source
subject to section 306 oi the Act, if it
were to discharge pollutants to the
navigable waters), shall be the standard
set forth in 40 CFR Part 128, except that,
for the purpose of this section, 40 CFR
128.133 shall be amended to read as
follows:
In addition to the prohibitions set forth In
40 CI-R 123131. the preueatment standard
lor incompat'ble pollutants Introduced Inlo a
puohcly ou-nt3 treatment works shall be the
Mandaid ol performance lor new sources
spc;il:ed in 40 CFR 423.15 except lor the foi-
lou'ini: pollutants or pollutant parameters
for which the following pretreaTment stand-
ards are established:
Pollutant or pollutant Pretreatment
parameter: standard
Heat No limitation.
free available chlorine No linmatum.
Total residual chlorine No limitation.
If the publicly owned treatment u-orks
u-hlch receives the pollutants Is committed,
in Its KTDKS permit, to remove ft specllicd
percentage of any incompatible pollutant,
the prttrcntment standard applicable to
users of siicu treatment works shall, except
in the case of standards providing for no
discharge of pollutants, be correspondingly
reduced in stringency for that pollutant.
(40 FR 7095, February 19,1975]
Subpart D—Small Unit Subcategory
§423.20 .Applicability; dcwriplion of
liicsniuli unit su!>culc£ory.
The provisions of this subpart are ap-
plicable to discharges resulting from the
operation of a small unit by an establish-
ment primarily engaged in the genera-
tion of electricity for distribution and
sale which results primarily from a proc-
ess utilizing fossil-type fuel (coal, oil, or
gas) or nuclear fuel in conjunction with
a thermal cycle employing the steam-
water system as the thermodynamic
medium.
§ 423-21 Specialized definitions.
For the purpose of this subpart:
(a) Except as provided below, the
general definitions, abbreviations and
methods of analysis set forth in 40 CPR
Part 401 shall apply to this subpart.
(b) The term "smDll unit" shall mean
any generating unit subject to ths pro-
visions of this p-rt. except a unit de-
nned below as old, of less than 25 mega-
watts rated net generating capacity or
any unit which is part of r.n electric
utilities system with a total net gen-
erating capacity of less than 150 mega-
watts.
(c) The term "old unit" sh?H mean
any generating unit, subject to the pro-
visions of this part, of 500 megawatts or
greater rated net generating capacity
which was first placed in service on or
before January 1, 1970 and any.generat-
ing unit of less than 500 megawatts rated
net generating capacity which was first
placed in service on or before January 1
1974.
The term "blowdown" shall mean
the minimum discharge of reclrculatlng
water for the purpose ol discharging
materials contained In the process, the
further buildup of which would cause
concentrations or amounts exceeding
limits established by best engineering
practice.
(40 FR 7095, February 19,1975)
(e) The term "free available chlorine"
shrill m?nn the value obtained using the
amperometric titration method for free
available chlorine described in "Stand-
ard Methods for the Examination of
Water and Wastewater", page 112 (13th
Edition).
(i) The term "low volume waste
sources" shall mean, taken collectively
as if Ircm one source, wastewater from
all sources except those for which
specific limitations are otherwise estab-
lished in this subpart. Low volume waste
sources would Include but are not limited
to wastcwaters from wet scrubber air
pollution control systems. Ion exchange
wafer treatment systems, water treat-
ment evaporator blowdown, laboratory
and sampling streams, lloor drainage,
cooling tower basin cleaning wastes and
blowdown from rccirculatlng house serv-
ice water systems. Sanitary wastes and
air conditioning wastes are specifically
not included In low volume waste
sources.
[40 FR 7095, February 19,1975]
(g) The term "ash transport -water"
shil! moan water used in the hydraulic
transport of either fly ash or bottom ash.
(h) The term "metal cleaning
wastes" shall mean any cleaning com-
pounds rinse waters, or any other wr.ter-
borne residues derived from cleaning
any metal process equipment including.
but not limited to, boiler tube cleaning,
boiler firsside cleaning and air pre-
heater cleaning.
(ij The term "once through cooling
water" shall mean water passed through
the main cooling condensers in one or
two passes for the purpose of removing
waste; heat from the generating unit.
(j) The term "recirculated cooling
water" shall mean water which is passed
through the main cooling condensers for
the purpose of removing waste heat from
the generating unit, passed through a
cooling device for the purpose of remov-
ing such heat from the water and then
passed again, except for blowdown,
through the main cooling condensers.
|40 FR 7095, February 19,1975]
(k) Th;. term "cooling pond" shall
mean any manmade water impoundment
which does not impede the flow of a
navigable stream and which is used to
remove waste heat from heated con-
denser water prior to reluming the re-
circulated cooling water to the main con-
denser.
§ 423.22 Effluent limitations guidelines
rcpresentini the dc.ircc of diluent
reduction attainable by tlic appHcA*
lion of the best practicable control
technology currently availnblc.
(a> In establishing the limitations set
forth in this section. EPA took into ac-
count all information it »vas able to col-
lect, develop and solicit with respect to
factors (such as ase and size of pliir.t,
utilization of facilities, raw materials.
manufacturing processes, non-water
quality environmentr.l impacts, control
and treatment technology available,
enerpy requirements and costs) which
can affect the industry subcatesorizatlon
and effluent levels established- It is, how-
ever, possible that data which would
affect these linvtations have not been
available and. as a result, these limita-
tions should be adjusted for certain
plants in this industry. An individual dis-
charger or other interested person may
submit evidence to the Regional Admin-
istrator (or to the State, if the State has
the authority to issue NPDES permits)
that factors relitmr.to the equipment or
facilities involved, the process applied, or
other such factors related to such dis-
charger are fundamentally different
514
-------
from the factors considered In the estab-
lishment ol the guidelines. On the basis
of such evidence or oth"r available Infor-
mation. the Hcgion.il Administrator (or
the State) will make a written finding
that such factors are or are not funda-
mentally different for that facility com-
pared to those specified in the Develop-
ment Document. If such fundamentally
different factors are found to exist, the
Rcmonal Administrator or the State
shall establish for thn discharner effluent
limitations in the NPDES permit either
more or less stringent than the limita-
tions established herein, to the extent
dictated by surh fundamentally differ-
ent factors. Such limitations must be ap-
proved by the Administrator of the En-
vironmental Protection Agency. The
Administrator ma approve or disap-
prove such limitations, specify other
limitations, or initiate proceedings to re-
vise these retaliations.
The quantity of pollutants dis-
charged from low volume waste sources
shall not exceed the quantity determined
by multiplying the flov-r of low volume
waste sources times the concentration
listed in the following table:
ATprap? of dtr'.r
Effluent Maximum lor vanics lor ihiny
characteristic any one day consocmivt da>7
shall not •xixV'l
TS? ............ 100mjr/\ ......... 3lnu:.1.
Oil and Cn&x ..... 10 mg,Q ........... U xc;/L
(4) The quantity of pollutants dis-
chareed in ash transport water shall not
exceed the quantity determined by mul-
tiplying the flow of ash transport water
tirr.cs the concentration toted in the
following table: _ _
Average of tlai'.r
EflJrjprt MMiaium for valu.-i for thirty
characteristic any one day confecuuve rt.iys
shall not ucoca
TSS ......... - ..... 100 mr/l. ........ JOmsA
Oil and Grease _____ 20mg,l ........ —
(5) The quantity of pollutants dis-
charged in metal cleaning wastes shall
not exceed the quantity determined by
multiplying the flow of metal cleaning
wastes times the concentration listed In
the following table:
Effluent
ebarftcterLstte
Mextmam fir
^iUu.-j for thirtr
coiK-Tuuve-iUTi;
Entail IUH exceed
TSS ioonw/1 »mt/l.
OH «nd lirea™ y>mtH — li nw/V.
(•orj*T. Tuva! 1.0m*A 1.0 mc.T.
Irou, TouJ 1.0 xus/1 1.8ui|A
<6) The'quantity of pollutants dis-
charged In boiler blowdown shall not ex-
ceed the quantity determined by mul-
tiplying the flow of boiler blowdown
times the concentration listed In the
following table:
7. n.u«nt
ehartwusriatio
., , t -,-of'Jally
Maximum for valum fur tinny
auy one day consecutive Oays
shall not excoe4
......... .
Oil and Ortass ..... lOrriRrt .......... IS mcfl.
Copper, Total ______ l.o mu/1 ______ , 10nur/l
Iron. Total ......... 1.0 mj/i ......... 1.0
(7) The quantity of pollutants dis-
charged in once through cooling water
shall not exceed the quantity determined
by multiplying the flow of once through
cooling water sources times the concen-
tration listed in the following table:
Effluent Maximum Averaee
Characteristic Coucentration Coaccnwatloa
Frea available 0.5 mg/l 0.2 mcA.
cb tonne.
(8) The quantity of pollutants dis-
charged in cooling tower blowdown shall
not exceed the quantity determined by
multiplying the flow of cooling tower
blowdown sources times the concentra-
tion listed in the following table:
Eflluant
Characteristic
MaUmtxm
Concentration
A Tenure
Concentration
Free available
chJortDa.
04 rng/l 0.2m&/t
(9) Neither free available chlorine nor
total residual chlorine may be discharged
from any unit for more than two hours
In any one day and not more than one
unit in any plant may discharge free
available or total residual chlorine at
any one time unless the utility can dem-
onstrate to the regional administrator or
state, if the state has NPDES permit is-
suing authority, that the units in a par-
ticular location cannot operate at or
below this level of chlorination.
(10) In the event that waste sircams
from various sources are combined for
treatment or discharge, the quantity of
each pollutant or pollutant property con-
trolled in paragraphs (b) (1) through
(9) of this section attributable to each
controlled waste source shall not exceed
the specified limitation for that waste
source.
(40 FR7095, February 19,1975)
§ 423.23 Effluent limitations cuidrlinc*
representing the decree of effluent
reduction attainable by the, applica-
tion of the bc.*l available technology
economically achievable.
The following limitations establish the
quantity or quality of pollutants or pol-
lutant properties, controlled by this sec-
tion, which may be discharged by a point
source subject to the provisions of
this subpart after application of the
br.st available technology economically
achievable:
(a) The pH of all discharges, except
once through cooling water, shall be
within the ranee of 6.0-9.0.
(b) There shall be no discharge of
polvchlorlnated biphenyl compounds
such as those commonly used for trans-
former fluid.
(c) The quantity of pollutants dis-
charged from low volume waste sources
shall not exceed the quantity determined
by multiplying the flow of low volumo
waste sources times the concentration
listed In the following table:
_, Avenge of dally
Effluent Maifmum for »alu*-s for Ihlrtf
cbaracicristic any one day eor>$r<-utlv« day*
shall not U£oe tngX.IIIIIIII 15 m^/C
(d) Th? quantity of .pollutants dis-
charged in bottom ash transport water
shall not exceed the quantity determined
by multiplying the flow of bottom ash
transport water times the concentration
listed in the following table and dividing
the product by 12.5..
AT«rageof dtfljr
Effluent M&xJmtim lor values lor thirty
characteristic &ay one day oonstcuUve d&yt
that! cot exceed
T55S lOOntffA. 30tag/L
Oil and Crease..... 2£> mg/1 *. . li ID£/L
(e) The quantity of pollutants dis-
charged in fly ash transport wate* shall
not exceed the quantity determined by
multiplying the flow of fly ash transport
water times the concentration listed In
the following table:
Arerijr«ofdtJ3y
Efflu*^t MarimiiTG for values lor thirty
characteristic &ny one day consecutive dnyt
shall not exceed
TS3 .
OU and Grease _____ 20m£/1 ----------
(f) The quantity of pollutants dis-
charged in metal cleaning wastes shall
not exceed the quantity determined by
multiplying the flow of metal cleaning
wastes times the concentration listed in
the following table:
Aver&ce of dally
Efluent Marimnm for values for thirty
characiehstio any one day consecuUve cay*
shall act exceed
TS3 ................ 1001T5.1
Oil and Grease _____ 20mg/l ...... ____ 15 mj[A.
Copier, Total ______ l.OniK.t _________ l.OinicA.
Iron, Tola! _________ 1.0 mgil ______ ...
(g) The quantity of pollutants dis-
charged in boiler blowdown shall not ex-
ceed the quantity determined by multi-
plying the flow of boiler blowdown times
the concentration listed in the following
table:
Effluent
chan-ct^rtaUc
Mariinum for
any one Uay
Avirrart Ofds/Iy
Tftlurs Jor thirty
consrcutLvf d*yi
tvbail not exceed
TSS 100n-.r,/L SOmjtfl.
Oil and tlrt-aw "."U uig/l.'.... IS mi/I,
Copprr Total l-0i,i,;/l 1-OirjtA.
Iron.lalil l.OJi^.l l.Omi/1.
(h) The quantity of pollutants dis-
charged in once through condenser water
shall not exceed the quantity determined
515
-------
by multiplying the flow of once through
condenser water sources times the con-
centration listed in the following table:
Maiimum
CouccntraLiOQ
Frw available
c&lorlne.
(1) The quantity of pollutants dis~
charged in cooling tower blowdown shall
not exceed the quantity determined by
multiplying the flow of cooling tower blow-
down times the concentration listed in the
following table:
Effluent
Characteristic
Maximum Average *
Concern ration CoiiceulraUon
Jrr*
chlorine.
0.5 mg/l.._.:,„. 0.2 mgA-
Average of duily
Maximum for values for th;i ly
Miy one day consecutive daya
sbail not exceed
Zinc l.Orofr/l 1.0mp,1
Chromium.. 0.2 me/1 o.'-i IUR./L
I'-.'.^'KT^S 5.Qms/l 5.0 mgil.
Other corrosion Linut 10 I* established on a case by
inhibiting case bans.
materials.
{40 FR7095, February 19, 1975]
(j) Neither free available chlorine nor
total residual chlorine may be discharged
from any unit for more than two hours
In any one day and not more than one
unit in any plant may discharge free
available or total residual chlorine at
any one time unless the utility can
demonstrate to the regional administra-
tor or state, if the state has NPDES per-
mit Issuing authority, that the units in a
particular location cannot operate at or
below this level of chlorination.
The quantity of poUutaists dis-
charged in boiler blowdown shall not ex-
ceed the quantity determined by multi-
plying the flow of boiler blowdown times
the concentration listed in the following
table:
Averse* of 'Tatty
EtBuent Maximum for value* lor thirty
characteristic any one day consocuuve days
shall not eiceca
TSS 100mc/L 30 me/1.
Oil and Grease 20 me/1 15 mp;l.
Copper. Total l.OnicA 1.0 nie/U
Iron. Total 1.0mg/l._ 1.0 cupA.
(h) The quantity of pollutants dis-
charged in once through cooling water
shall not exceed the quantity determined
by multiplying the flow of once through
cooling water times the concentration
listed in the following table:
Fifiucnt Maximum Averapf
Characteristic Concentration Concentration
Free available
chlorine.
O.Smg,1
(11 The quantity of pollutants dis-
charged in cocllns tower blowdown shall
not exceed the quantity determined by
multiplying the flow of cooling tower
blowdown sources times the concentra-
tion listed in the following table:
Effluent
CbtmutlertsUc
MrulmtiRi
ConcauLrutton
Conwu (ration
Free available
cbloriu«.
0.5 mg/l _________ 0.2
Average of dally
Maximum for valurs for tliiily
any ooc day consecutive days
•hall not Hce«4
Materials added
ti>r corrosion in-
hibilion loclud.
iiiS «»!«.
chromium,
phosphorus and
No detectable
amount.
No detectable
auiouut.
(j) Neither free available chlorine nor
total residual chlorine may be discharged
from any unit for more than two hours
in any one day and not more than one
unit in any plant may discharge free
available or total residual chlorine at any
one time unless the utility can demon-
strate to tiie regional administrator or
state, if th; state has NPDES permit is-
suing authority, that the units In a par-
ticular location cannot operate at or be-
low this level of chlorination.
(fc) In the event that waste steams
from various sources are combined for
treatment, or discharge, the quantity of
each pollutant or pollutant property con-
trolled in paragraphs (a) through (jj of
this section attributable to each con-
trolled waste source shall not exceed the
specified limitation for that waste
source.
(1) There shall be no discharge of
heat from the main condensers except:
(1) Pleat may be discharged In blow-
down from recirculated cooling water
systems provided the temperature at
which the blowdown is discharged does
not exceed at any time the lowest tem-
perature of recirculated cooling water
prior to the addition of the make-up
water.
(2) Heat may be discharged In blow-
down from cooling ponds provided the
temperature at which the blowdown Is
discharged does not exceed at any time
the lowest temperature of recirculated
cooling water prior to the addition of
the make-up water.
§ 423.26 Prctrcalmcnt ttandarils for new
sources.
The pretreatment standards under
section 307 (c.1 of the Act for a source
within the srnan unit subcategory, which
is a user of a publicly owned treatment
works (and which would be a new source
subject to section 306 of the Act, If it were
to discharge pollutants to the navigable
•waters), shall be the standard set forth
in 40 CFR Part 128. except that, for the
purpose of this section, 40 CFR 128.133
shall be amended *o read as follows:
In addition to the prohibitions set forth la
*0 CFR 128 131. the pretreatment standard
lor Incompatible pollutants Introduced into
a publicly owned treatment works shall b*
the standard of performance lor new sources
specified in 40 CFR 42:1 25 except for tho
following pollutants or pollutant parameter*
(or which the following pretreatment stand-
ards are established:
516
-------
FoUiiranf or pollutant Pretrcatmcnt
parameter
.
Frw available chlorine.. No limitation
Toul residual chlorln. . No (imitation.
If the publicly owned trentment works
which receives the pollutants Is committed
Jn Its NPDES permit, to remove a specified
percentage of any incompatible pollutant.
tfeo .pretreatment sianrtwd applicable to
usar3 of such treatment, works shall', except
In the case or standards providing for' no dis-
charge of pollutants, be correspondingly re-
duced In stringency for that pollutant.
[40 FR 7095, February 19, 1975)
Subpart C — Old Unit Subcategory
§ 423.30 Applicalii!;:y; description of
the old unit subcaiegory.
The provisions of this subpart are ap-
plicable to discharge:; resulting from the
operation of an old 111114. by an establish-
ment primarily engarred in the genera-
tion of electricity for distribution and
sale which results primarily from a process
utilizing fossil-type fuel {coal, oil, »as) or
nuclear fuel in conjunction with a thermal
cycle employing the steam-water system as trie
thcrmodynamic medium.
[40 FR 7095, February 19, 1975|
..
§ 423.31 Specialized definitions.
For the purpose of this subpart:
(a) Except as provided below, the gen-
eral definitions, abbreviations and meth-
ods of. analysis set forth in 40 CFR Part
401 shall apply to this subpart.
(b) The terra "old unit" shall mean
any generating unit, subject to the pro-
visions of this part, of 500 megawatts or
greater rated net generating capacity
which was flrst placed la service on or
before January 1, 1970 and any gener-
ating unit of less than 500 megawatts
rated net generating capacity which was
flrst placed in service on or before Jan-
uary 1, 1974.
(c) The term "blowdown" shall mean
the minimum discharge of rectrculatine
water for th? purpose of discharging ma-
terials contained in tne process, the fur-
ther buildup of which would cause con-
centrations or amounts exceeding limits
established by best engineering practice.
(40 FR 7095, February 19, 1975]
(d) The term "free available chlo-
rine" shali mean the value obtained using
the amperometric titration method for
free available chlorine described in
"Standard Methods for the Examina-
tion of Water and Wastewater", page
112 (13th Edition).
(e) The term 'low volume waste
sources" shall mean, taken collectively as
If from one source, wnstewatcr from all
sources except those for which specific
limitations are otherwise established in
this subpart. Low volume waste sources
would include but are not limited to
wastewaters from wet scmbber air pollu-
tion control systems, ion exchange water
treatment systems, water treatment
evaporator blowdown, laboratory and
sampling streams, lloor dralnaiTC. cooling
tower basin cleaning wastes and blow-
down from rccirculatins house service
water systems. Salutary wastes ana air
conditloninK wastes are specifically not
Included in low volume waste sources.
[40 FR 7095, February 19, 1975)
The term "ash transport water"
shall mean water used in the hydraulic
transport of either fly ash or bottom
tish.
(R) The term "metal cleaning wastes"
shall, mean any cleaning compounds,
rinse waters, or any other waterborne
residues derived from cleaning any
metal process equipment including, but
not limited to. boiler tube cleaning,
boiler fireside cleaning and air preheater
cleaning.
'(h) The term "onco through cooling
water" shall mean water passed through
the -main cooling condensers in one or
two passes for the purpose of removing
waste heat from the generating unit.
|40 I:R 7095, February 19. 19751
(i) The term "recirculated cooling
water" shall mean water which is passed
through the main cooling condensers for
the purpose of removing waste heat from
the generating unit, passed through a
cooling device for the purpose of remov-
ing such, heat from the water and then
passed again, except for blowdown,
through the main cooling condensers.
[40 FR 7095, February 19, 1975|
§ 423.32 Effluent limitations euiJelines
representing the deprce of ctllucnt
reduction attainable by tlte applica-
tion of the best practicable control
technology currently available.
(a) In establishing the limitations
set forth" In this section, EPA took into
account all information it was able to
collect, develop and solicit with respect
to factors (such as age and size of plant,
utilization of facilities, raw materials,
manufacturing processes, non-water
quality environmental impacts, control
and treatment technology available,
energy requirements and costs) which
can affect the industry subcategoriza-
tion and effluent levels established. It
is, however, possible that data which
would affect these limitations have not
been available and. as a result, these
limitations should be adjusted for cer •
tain plants in this iudustry. An individ-
ual discharger or other Interested person
may submit evidence to the Regional Ad-
mmistrator (or to the State, if the State
has the authority to issue NPDES per-
mits) that factors relating to the equip-
ment or facilities involved the process
applied, or other such factors related to
such discharger are fundamentally dif-
ferent from the factors considered in the
establishment of the guidelines. On the
basis of such evidence or other available
information, the Rceional Administrator
(or the State* will make a written find-
ing that such factors are or are not fun-
damentally different for that facility
compared to those specified m the De-
veioomcr.t Document. If such funda-
mentally different factors are found to
exist, the Regional Administrator or the
Stale shall est?bli.-.h for the cHschartrer
cl!K:cnt limitations in the Nl'DCS permit
cither more or less strinnent than the
limitations establirhcd hcrum, to the ex-
tent dictated by such Umdamcntully dif-
ferent factors. Such limitations must be
approved by the Administrator of the
Environmental Protection Apcncy. The
Administrator may approve or dis-
approve such limitations, specify other
limitations, or Initiate proceedings to
revise these regulations.
(b) The following limitations estab-
lish the quantity or quality of pollutants
or poilutant properties, controlled by
this section, which may be discharged,
by n point source subject to the provi-
sions of this subpart after application of
trie best practicable .control technology
currently available:
(1) The pll of all discharges, except
once tlirough cooling water, shall be
within the range of B.0-9.0.
(2) There shall be no discharge of
polychlorinatcd bcplicnyl compounds such as
unosc commonly used for transiotmer fluid.
[40 FR 7095, February 19,1975J
(3) The quantity of pollutants dis-
charged from low volume waste sources
shall not exceed the quantity determined
by multiplying the flow of low volume
waste sources times the concentration
listed in the following table:
Av«rs£e of doily
Effluent Mailmum tor values (or thiny
cbaraclcmu'o any one day consrculive daji
aaall cot exceed
TS3 100 m«/l_
Oil and Grease ?Onie/!.._ 15
(4) The quantity of pollutants dis-
charged in ash transport water shall not
exceed the quantity determined by mul-
tiplying the flow of ash transport water
times the concentration listed in the fol-
lowing table.
Avera£« of d ally
Effluent Maximum for values Tor thirty
characteristic aoyoaeday conv«jtiTe days
sball Dot eucxd
T?3 — 100 rosfl JOms/U
Oil ar.d Grease "20 mg.1
(5) The quantity of pollutants dis-
charged in metal cleaning wastes shall
not exceed the quantity determined by
multiplying the flow of metal cleaning
wastes times the concentration listed in
the following table:
characu-riiUc
Maiimuro for
aoy 1 day
Avenge o
values for 3o
coos^culiredays
TSS
Oil ftii'l <'r<-:i5e
.
Iron, Toul
- JOmcA- ....... . 30 mtli.
-0 ir.c.'l ......... - 15 DDK;!.
lJ>n..'/l ......... 1.0 ro?/L
1-OniB/l ......... LOnn/L
cliaructensiic
,. Averaccofdaily
Maximum for v»lucs lor 30
any 1 day
TSS 100 mcA- 30 me/I.
O:l n:id The quantity of pollutants dis-
charged in boiler blowdown shall not ex-
ceed the quantity determined by multi-
plying the ilow of boiler blowdown timcj
the concentration listed in the following
table:
<7) The quantity of pollutants dls-
charn-d in once throurh cooling water
sh lU not exceed tlu- nu.mtity determine*.
by'multlplvinc the flow ot once through
coolim' water sources times the concen-
tration listed in the following table:
517
-------
Madmum
CoucmilniUoa
.
Concentration
0.5 mefl
(8) The quantity or pollutants dis-
charged In cooling tower blowdown shall
not exceed the quantity determined by
multiplying the How or cooling tower
blowdown sources times the concen-
tration listed in the following table:
Affluent Maximum Avcra£i*
CharactensUc Concentration Couamlrutton
Fre« svoltahla 0.5 mgA 0.2 mg/l.
calortrto.
(9) Neither free available chlorine nor
total residual chlorine may be discharged
from any unit for more than two hours
in any one day and not more than one
unit in any plant may discharge free
available or total residual chlorine at
any one time unless the utility can dem-
onstrate to the reslonal administrator
or state, if the state has NPDES permit
Issuing authority, that the units in a
particular location cannot operate at or
below this level of chlorination.
(10) In the event that waste streams
from various sources arc combined for
treatment or discharge, the quantity of
each pcilutant or pollutant property con-
trolled in paragraphs (b) (1) through
(9) of this section attributable to each
controlled waste source shall not exceed
the specified limitation for ihit \\3\te source.
(40 FR 7095, February 19, 1975]
% 423.33 Effluent limitations jruidolines
rtprcsciitins llie (icprcc of diluent
reduction attainable l*y the applica-
tion of the best available technology
economically achievable.
The following limitation? establish the
quantity or quality of polluta its or pol-
lutant properties, controlled by this sec-
tion, which may be discharge ' by a point
source subject to the provisions of this
subpart after application cf the best
available technology:
available technolosy economically achievable.
[40 FR 7095, February 19. 1975)
(a) The pH of all discharges, except
once through cooling water, shall be
within the range of 6.0-9.0.
(b) There shall be no discharge of
polychlorinated biphcnyi compounds
such as those commonly used for trans-
former fluid.
[40 f R 7095. February 19, 1975)
(c) The quantity of pollutants dis-
charged from low volume waste sources
shall not exceed the quantity determined
by multiplying the flow of low volume
waste sources times the concentration
listed in the following table:
(d) The quantity of pollutants dis-
charged in bottom ash transport water
shall not exceed the quantity determined
by multiplying the flow of bottom ash
transport water tunes the concentration
listed In the following table and dividing
the product by 12.5:
Avenge of dally
Effluent Maximum tor value* lor tlilrly
crmracleristio anyone day const.utlve flays
sliaU not exceed—
CilurjfU'ristio
Minimum Avoroire
Com-enlruuoa Concentration
f daily
Effluent Maximum for values for thnry
cbai selenitic any one day rorts*vutived;\>s
snail HOI exceed
TSS 100 mft/1 30mR/l.
Oil and (Jreasw 00 tried 15 rng/1.
Copper, Total 1.0 iMjra 1.0 i»c,1.
Iron, Total - 1.0 mg/l 1.0 nig;!.
(h> The quantity of pollutants dis-
charged in once throurh cooling water shall
not exceed the quanm> dc'.crmined by multi-
plying the How of once throufji cooling water
sources times the concentration listed m the
following table:
Effluent
Characteristic
Maximum
Concentration
A vr-rrjn1
Concent nmon
Fref a?ni!ab!e O.S mjr/l 0.2D1R/1.
chlorine.
A „.„,.,, 0,nAi,y [40 FR 7095, February 19. 1975]
EfBumt M.niiruro for v»invj inr tinny The qunntity of pollutants dis-
char»c«ri5tlc any one day ™«™X^4?_ charged in coolme tower bloudown shall
_______ not exceed the quantity determined by
multiplying the lluw ol Limiin^ tovicr bluw-
dow n times me concentration listed In
• the following table:
Firit itvnllnblB
chlorine.
0.5 mg/1......... 0.2 mg/L
TS3 100ni!/U 30ms,1.
Oil and Grease 20 mg.'l 15 uig/1.
The quantity of pollutants dis-
charged in fly ash transport water shall
not exceed the quantity determined by
multiplying the flow of ily ash transport
water times the concentration listed in
the following table:
Average of daily
Effluent Maximut for values for 3l>
characteristic any 1 day couycultve days
shall not exceed—
TSS 100 mgA BGriieA
Oil and Grease *'0u)&;l 15 ing/L
(f) The quantity of pollutants dis-
charged in metal cleaning wastes shall
not exceed the quantity determined
by multiplying the flow of metal cleaning
wastes times the concentration listed in
the following table:
Averare of dally
Effluent Maximum for valuer for 30
churacterisUc any 1 day consecutive days
shall not eiceco.—
TSS 100 mgA 30rr.ii/l.
Oil and (jre.iM 20 me.'! 15m>;1.
Copper, Total l.OmK'T... - 1.0mc,X
iron. Total 1.0 nig/ - 1.0 mi/1.
Avoroce of dally
Maximum tor valutifur3U
tuiy 1 day constvulfvc dayf
&h.ill not exceed—
Zinc . 1.0 roir/1 LODic/L
Chromium 0:.! nic/L.. 0.? niR/1.
IllOiphorus 5.0 ni,1:,'!.. 5.0 inp/l.
Ollirr corrosion Liniil lobe established on acoseby
inhibiting casa basbu
r,3 ]nur/l ......... Mnw/l.
oii uid'urease. ..... 20 un/i .......... u tuc/1.
[40 FR 7095, February 19,1975]
(j) Neither free available chlorine nor
total residual chlorine may be discharged
from any unit for more than two hours
in any one day and not more than one
unit in any plant may discharge free
available or total residual chlorine at any
one time unless the utility can dcmon»
strate to the regional administrator or
state, If the state has NPDES permit
issuing authority, that the units in a par-
ticular location cannot operate at or
below this level of chlorination.
Ik) In the event that waste streams
from various sources are combined for
treatment or discharge, the quantity of
each pollutant or pollutant property con-
trolled in paragraphs ia.> through (j) of
this section attributable to each con-
trolled waste source sha':l not exceed the
specified limitation for that waste source.
§423.34 [Reserved]
Subpart D—Area Runoff Subcategory
§ 423.40 Applicability; dr.tt-riplion of
the area runoif subcalegory.
The provisions of this subpart are ap-
plicable to discharges resulting from ma-
terial storage runoff and construction
runoff which are used in or derived from
units subject to the limitations in sub-
parts A, B. or C of this part.
[40 FR 7095, February 19,1975]
§ 423.41 Specialized definitions.
For the purpose of this subpart:
ta) Except as provided below, the gen-
eral definitions, abbreviations and meth-
ods of analysis set forth in 40 CFK
Part 401 shall apply to this subpart.
(b) The term "material storage run-
off" shall mean the rainfall runorf from
or through any coal, ash or other ma-
terial storage pile.
-------
§ 423.42 Fflturnt liminniont guitlrlinc*
represemin" l!1(- ilr^-rrc of rlllitrnl
rciluotmn allaiiuiMc by the applirn.
lion of the l>e>t praclirnlile control
terhnolos) currently available.
In establishing the limitations set
forth in this section, EPA took into ac-
count all information it was able to col-
lect, develop and solicit with respect to
factors (such as age and size of plant,
utilization of facilities, raw materials',
manufacturing processes, non-water
quality environmental impacts, control
and treatment technology available, en-
ergy requirements and costs) which can
affect the industry subcategorizatior.
and effluent levels established. It is, hew-
ever, possible that data which would af-'
feet these limitations have not been
available and, as a result, these limita-
tions should be adjusted for certain
plants In this industry. An individual
discharger or other interested person
may submit evidence to the Regiona1. Ad-
ministrator (or to the State, if the State
has the authority to issue NPDES per-
mits) that factors relating to the equip-
ment or facilities involved, the process
applied, or other such factors related to
such discharger are fundamentally
different from the factors considered in
the establisliment of the guidelines. On
the basis of such evidence or other avail-
able information, the Regional Adminis-
trator (or the State) will make a writ-
ten finding that such factors are or are
not fundamentally different for that fa-
cility compared to those specified in the
Development Document. If such funda-
mentally different factors are found to
exist, the Regional Administrator or the
State shall establish for the discharger
eSluent limitations in the NPDES permit
either more or less stringent than the
limitations established herein, to the ex-
tent dictated by such fundamentally
different factors. Such limitations must
be approved by the Administrator of the
Environmental Protection Agency. The
Administrator may approve of disap-
prove such limitations, specify other lim-
itations, or initiate proceedings to revise
these regulations:
(a) Subject to the provisions of para-
graph of this section, the following
limitations establish the quantity or
quality of pollutants or pollutant prop-
erties, controlled by this section, which
may be discharged by a point source sub-
ject to the provisions of this subpart
after application of the best practicabla
control technology currently available:
Effluent Effluent
characteristic: limitations
TSS * Not to exceed 50 rag/I.
pn -\Vlthln me range 6.0 to 9.0.
(b) Any untreated overflow from fa-
cilities desiencd, constructed and oper-
ated to treat the volume of material stor-
age runoff and construction runolf which
is associated with a 10 year, 24 hour rain-
fall event shall not be subject to the
limitations in subparagraph (a) of this
section.
§ 423.43 Effluent KmituUons guidelines
representing liic ticprce of elfiuent
reduction attainable by the applica-
tion of the best available technology
economically achievable.
(a) Subject to the provisions of para-
graph (b) of this section, the following
limitations establish the quantity or
quality of pollutants or pollutant prop-
erties, controlled by this section, which
may be discharged by a point source sub-
ject to the provisions of this subpart after
application of the best practicable con-
trol technology currently available:
Effluent Effluent
characteristic: limitations
TSS Not to exceed 50 mg/t.
ph Within the range 6.0 to 9.0.
(b) Any untreated overflow from fa-
cilities designed, constructed and oper-
ated to treat the volume of material stor-
age runoff and construction runoff v.-hich
results from a 10 year, 24 hour rainfall
event shall not be subject to the limita-
tions in paragraph (a) of this section.
§ 423.44 [Reserved]
§ 423.45 Stumlun!* of performative for
new sourer*.
(a) Subject to the provisions of para-
graph ib) of this section, the following
standards of performance establish the
quantity or quality of pollutants or pol-
i I'.nr.t properties, which may be dis-
charged by a new source subject to the
provisions of this subpart:
Effluent Effluent
characteristic: limitation}
TSS Not to exceed 50 mg/l.
pn. Within the range 6.0 to 9.0.
(b) Any untreated overflow from' fa-
cilities designed, constructed and oper-
ated to treat the volume of material stor-
age runofl and construction runoff which
results from a 10 year, 2-1 hour rainfall
event, shall not be subject to the ph and
TSG limitations stipulated in paragraph.
(a) of this section.
§ 423.46 Frclrcalment standard* for
new sources.
The pretreatment standards under
section 307(c) of the Act for a source
within the area runoff subcategory,
which is a user of a publicly owned treat-
ment works (and which would be a near
source subject to section 306 of the Act,
if it were to discharge pollutants to the
navigable waters), shall be the standard
set forth in 40 CFR Part 123, except that,
for the purpose of this section, 40 CFR
128.133 shall be amended to read as
follows:
In addition to the promotions set forth In
40 CFU 128.131. the pretreatrnent stj.ndird
for Incompatible pollutaivts introduced !mo
a publicly owned treatment works shall be
the standard of perlermrmce for new sources
specified in 40 CFR 423 45: Prorided, Tha..
if the publicly owned treatment works which
receives t-he pollutants is committed, in us
NPDES permit, to remove a specified per-
centape of any incompatible pcUutant. the
pretreatmcnt standard applicable to users of
such treatment works shall, except in the
case of standards providing for no discharge
• of pollutants. b& correspondingly reduced in
stringency for that pollutant.
519
-------
REFERENCES
1. Edwards, J. B. Combustion: The Formation and Emission of Trace
Species. Ann Arbor, Michigan, Ann Arbor Science Publishers, Inc.,
1974.
2. Sondreal, E. A. and P. H. Tufte. Scrubber Developments in the West.
Presented at the 1975 Lignite Symposium, Grand Forks, North Dakota,
May 14-15, 1975.
3. Proposed Criteria for Water Quality. Volume I. U.S. Environmental
Protection Agency. October 1973.
4. Effluent Guidelines and Standards for Steam Electric Power
Generating. Fed Regist. 135:0541, April 18, 1975.
5- Epstein, S. S. Potential Carcenogenic Hazards Due to New Orleans
Drinking Water. Testimony Before the House Committee on Health
and Welfare, Louisiana House of Representatives. February 21, 1975.
6. Principles for Evaluating Chemicals in the Environmental. National
Academy of Sciences, National Academy of Engineering and Committee on
Toxicology, National Research Council. 1975.
7. Instrumentation for Environmental Monitoring - Water. Lawrence
Berkeley Labs, NSF February 2, 1973. LBL-I, Vol. 2.
8. Proceedings of Symposium on Energy Production and Thermal Effects.
Oak Brook, Illinois, September, 1973. Ann Arbor, Michigan, Ann
Arbor Science Pub., Inc., 1974.
9. Mills, G. A., H. Perry, and H. R. Johnson. Fuels Management in an
Environmental Age. Environ Sci Technol. 5(1):30, 1971.
10. Levin, A. E. , T. J. Birch, R. E. Hillman, and G. E. Raines. Thermal
Discharges: Ecological Effects. Environ Sci Technol. 6(3):224,
1972.
11. Water Quality Criteria. Federal Water Pollution Control Administra-
tion, 168. Report of the National Technical Advisory Committee to
the Secretary of the Interior. Available from the U.S. Government
Printing Office, Washington, D.C. 20402.
12. Meyer, J. H., T. W. Eages, L. C. Kohlenstein, J. A. Kagan, and
W. D. Stanbus. Mechanical Draft Cooling Tower Visible Plume
Behavior: Measurements, Models, Predictions. In: Cooling Tower
Environment - 1974. Technical Information Center, Office of Public
Affairs, ERDA, 1973. p. 307-352.
520
-------
13. Federal Noise Effects Research FY73-FY75. U.S. Environmental Pro-
tection Agency. Report No. EPA-600/1-75-001. March 1975.
14. Information on Levels of Environmental Noise Requisite to Protect
Public Health and Welfare With Adequate Margin of Safety. U.S.
Environmental Protection Agency. Report No. EPA-550/9-74-004.
March, 1974.
521
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APPENDIX E
COMBUSTION CLASSIFICATION SYSTEM
The rows of the .summary tables, as presented in the main body of this
report, define the combustion systems to be evaluated for air, water,
and solid waste pollutants. These systems are identified by function,
combustion type (external or internal), fuel, furnace type, and firing
method. A classification coding system identifying the above factors,
and others such as size, the use of fly ash reinjection, and control
device application, has been developed to aid in the possible computer-
ization of the data base.
The specific classifications used in the summary tables were chosen pri-
marily to identify factors that affect pollutant properties or quantities
or to indicate the state-of-the-art of combustion technology. Table 165
presents an overview of the Combustion System Classification by listing
the function, combustion types and fuels for the electric generation
function and combustion type for the industrial, commercial and residen-
tial functions. Table 166 further expands the classification system to
include all of the factors that can be used to define the system dis-
cussed in Section II of the report for Electric Generation-External
Combustion-Bituminous Coal-Pulverized Dry-Tangential Firing. This table
is also condensed since a full expansion of all classifications under the
above heading by Electric Generation-External Combustion-Bituminous Coal
would require 576 rows to include furnace types, firing patterns, size
and fly ash reinjection (excluding control devices). If full use is to
be made of this classification system, the need for computerization is
obvious. Computerization will require also that a classification coding
522
-------
system be developed for the unit processes and pollutants which comprise
the columns of the summary tables. Approximately 300 columns have been
used in this document to define the pollutants emitted from combustion
sources and their associated operations.
523
-------
Table 165. OVERVIEW OF COMBUSTION CLASSIFICATION SYSTEM
1.0.00.0.0
1.1.00.0.0
1.1.10.0.0
1.1.11.0.0
1.1.12.0.0
1.1.13.0.0
1.1.20.0.0
1.1.21.0.0
1.1.22.0.0
1.1.23.0.0
1.1.24.0.0
1.1.25.0.0
1.1.26.0.0
1.1.30.0.0
1.1.31.0.0
1.1.32.0.0
1.1.33.0.0
1.1.40.0.0
1.1.41.0.0
1.1.42.0.0
1.1.43.0.0
1.2.00.0.0
1.3.00.0.0
1.4.00.0.0
1.4.20.0.0
1.4.22.0.0
1.4.30.0.0
1.4.31.0.0
2.0.00.0.0
2.1.00.0.0
2.2.00.0.0
3.0.00.0.0
3.1.00.0.0
3.2.00.0.0
4.0.00.0.0
4.1.00.0.0
Electric Generation
External Combustion (all fuels)
Coal
Bituminous
Anthracite
Lignite
Petroleum
Residual Oil
Distillate Oil
Crude Oil
Kerosene
Diesel Fuel
Gasoline
Gas
Natural Gas
Process Gas
LPG
Waste
Bagasse
Wood/Back
Other
Internal Combustion (All)
Internal Combustion - Turbines
Internal Combustion - Reciprocating
Petroleum
Distillate Oil
Gas
Natural Gas
Industrial
External Combustion
Internal Combustion
Commercial
External Combustion
Internal Combustion
Residential
External Combustion
524
-------
Table 166. EXAMPLE OF COMBUSTION CLASSIFICATION SYSTEM
FOR ELECTRIC GENERATION, EXTERNAL COMBUSTION
1.0.00.0.0 Electric Generation
1.1.00.0.0 External Combustion
1.1.10.0.0 Coal
1.1.11.0.0 Bituminous
1.1.11.1.0 Pulverized Dry
£> 1.1.11.1.1 Tangential
1.1.11.1.1.1 > 5000 x 106 Btu/hr
1.1.11.1.1.2 1500 - 5000 x 106 Btu/hr
1.1.11.1.1.3 . 500 - 1500 x 106 Btu/hr
1.1.11.1.1.3.1 with fly ash reinjection
1.1.11.1.1.3.1.1 with ESP
1.1.11.1.1.3.1.1.1 with ESP and limestone scrubber
1.1.11.1.1.3.1.1.1.1 with ESP, limestone scrubber and staged firing
1.1.11.1.1.3.1.x.x.l with staged firing: no other control device
-------
APPENDIX F
CONVERSION FACTORS
CAPACITY, ENERGY, FORCE, HEAT
Multiply
By
To obtain
Btu
Btu/min
Btu/min
Btu/min
Btu/min
Btu/min
Horsepower (boiler)
Horsepower (boiler)
Horsepower-hours
Kilowatts
Kilowatts
Kilowatt-hours
Kilowatt-hours
Megawatts
Pound/hr steam
0.2520
3.927 x 10-4
2.928 x 10~4
0.02356
0.01757
10-3
33,479
9.803
0.7457
56.92
1.341
3415
1.341
1360
0.454
Kilogram-calories
Horsepower-hrs
Kilowatt-hrs
Horsepower
Kilowatts
Pound/hr steam
Btu/hr
Kilowatts
Kilowatt-hours
Btu/min
Horsepower
Btu
Horsepower-hrs
Kilogram/hr steam
Kg/hr
Energy equivalences of various fuels:
Bituminous coal - 22.4 x 106 Btu/ton, 1971-1973
21.9 x 106 Btu/ton, 1974
Anthracite coal - 26.0 x 106 Btu/ton
Lignite coal - 16.0 x 106 Btu/ton
Residual oil - 147,000 Btu/gal
Distillate oil - 140,000 Btu/gal
Natural gas - 1,022 Btu/ft3
1 Ib of water evaporated from and at 212 F equals:
0.2844 Kilowatt-hours
0.3814 Horsepower-hours
970.2 Btu
526
-------
FLOW
Multiply
Cubic feet /minute
Cubic feet/second
Cubic feet /second
Cubic meter/sec.
Cubic meter/sec.
Gal Ions /year
Gal Ions /min.
Liters /min.
Liters /min.
Million gals /day
Million gals /day
Million gals /day
Pounds of vater/min.
LENGTH, AREA, VOLUME
Multiply
Acres
Acres
Acres
fitv*> ^**f
Acre-feet
Acre- feet
Acre- feet
Barrels-oil
Barrels-oil
Centimeters
Cubic feet
Cubic feet
Cubic feet
Cubic feet
Cubic feet
Cubic feet
Cubic meters
Cubic meters
Feet
Feet
By
0.1247
0.646317
448.831
22.8
8.32 x 109
10.37 x 10-6
2.228 x 10-3
5.886 x 10'4
4.403 x ID'3
1.54723
0.044
695
2.679 x 10-4
By
43,560
4047
1.562 x 10--*
43,560
325,851
1233.49
0.156
42
0.3937
2.832 x 104
1728
0.02832
0.03704
7.48052
28.32
35.31
264.2
^0 48
«/ \J * *TW
0.3048
To obtain
Gallons/sec.
Million gals /day
Gallons /min
Million gals /day
Gal Ions /year
m^/day
Cubic feet/sec.
Cubic ft/sec,
Gals/sec.
Cubic ft/sec.
Cubic meters. secibd
Gal Ions /min.
Cubic ft/sec.
To obtain
Square feet '
Square meters
Square miles
Cubic feet
Gallons
Cubic meters
Cubic meters
Gallons-oil
Inches
Cubic cms.
Cubic inches
Cubic meters
Cubic yards
Gallons
Liters
Cubic feet
Gallons
Centimeters
Meters
527
-------
Gallons
Gallons
Gallons, Imperial
Gallons water
Liters
Meters
Meters
Square feet
Square feet
Square meters
Square meters
Square miles
0.1337
3.785 x 10'3
1.20095
8.3453
0.2642
3.281
39.37
2.296 x 10"5
0.09290
2.471 x 10~4
10.76
640
Cubic feet
Cubic meters
U.S. gallons
Pounds of water
Gallons
Feet
Inches
Acres
Square meters
Acres
Square feet
Acres
MASS, PRESSURE, TEMPERATURE, CONCENTRATION
Multiply
Pounds
Pounds of water
Pounds of water
Pounds/sq. inch
Pounds/sq. inch
Pounds/sq. inch
Temp. (°C) + 17.78
Temp. (°F) - 32
Tons (metric)
Tons (short)
Tons (short)
Tons (short)
By
To obtain
Atmospheres
Atmospheres
Atmospheres
Grams
Grams /liter
Grams /liter
Grams /liter
Kilograms
Parts /million
Parts /million
29.92
33.90
14.70
15.43
58.417
8.345
0.062427
2.2046
0.0584
8.345
Inches of mercury
Feet of water
Lbs/sq. inch
Grains (troy)
Grains /gal
Pounds /1000 gals.
Pounds /cubic ft
Pounds
Grains /U.S. gal
Lbs /million gal
453.5924
2205
2000
0.89287
0.9975
Grams
0.01602
0.1198
0.06804
2.307
2.036
1.8
0.555
Cubic feet
Gallons
Atmospheres
Feet of water
Inches of mercury
Temp. (°F.)
Temp. (°C.)
Pounds
Pounds
Tons (long)
Tons (metric)
528
-------
ABMA
ASME
BaP
BOD
BSD
Btu
COD
EPA
FGC
FGD
FEA
FPC
IERL
kWh
MR
MW
MWh
NEDS
NPDES
PBB
PCB
PHH
POM
PPOM
SOTDAT
APPENDIX G
MAJOR ACRONYMS USED IN THIS REPORT
American Boiler Manufacturer's Association
American Society of Mechanical Engineers
Benzo(a)pyrene
Biological Oxygen Demand
Benzene Soluble Organics
British Thermal Units
Chemical Oxygen Demand
Environmental Protection Agency
Flue Gas Cleaning
Flue Gas Desulfurization
Federal Energy Administration
Federal Power Commission
Industrial Environmental Research Laboratory
Kilowatt Hours
Municipal Refuse
Megawatts
Megawatt Hours
National Emission Data System
National Pollution Discharge Elimination System
Polybrominated Biphenyls
Polychlorinated Biphenyls
Polyhalogenated Hydrocarbons
Polycyclic Organic Matter
Particulate Polycyclic Organic Matter
Source Test Data System
529
-------
TS Total Solids.
IDS Total Dissolved Solids
TSS Total Suspended Solids
TLV Threshold Limit Value
TVA Tennessee Valley Authority
530
-------
I. REPORT NO.
EPA-600/2-76-046b
TECHNICAL REPORT DATA
incase read lnunn-iuma tin the rcnrsc bcjon- completing
3. RECIPIENT'S ACCESSION NO.
4. TITLE ANOSU3TITLE
Preliminary Emissions Assessment of Conventional
Stationary Combustion Systems; Volume II—Final
Report
5. REPORT DATE
March 1976
6. PERFORMING ORGANIZATION CODE
'•AUTKORU)NormanSurprenant, Robert Hall, Steven Sla-
ter, Thomas Susa, Martin Suss man, Charles Young
8. PERFORMING ORGANIZATION REPORT NO.
GCA-TR-75-26-G(2)
9. PERFORMING ORGANIZATION NAME AND ADDRESS
GCA/Technology Division
GCA Corporation
Bedford, Massachusetts 01730
10. PROGRAM ELEMENT NO.
EHB525; ROAP AAU-002
11. CONTRACT/GRANT NO.
68-02-1316, Task 11
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final: 3/75-12/75
14. SPONSORING AGENCY CODE
EPA-ORD
15. SUPPLEMENTARY NOTES u
Project officer for this report is R. A. Venezia, Ext 2547.
i6.ABSTRACT The report gives results of Q. preliminary emissions assessment of the air,
water, and solid waste pollutants produced by conventional stationary combustion
systems. It gives results in four principal categories: utilities (electric generation),
industrial (steam generation, space heating, and stationary engines), commercial/
institutional (space heating and stationary engines), and residential (space heating).
For each principal combustion system category, it gives: process types and oper-
ating efficiencies, fuel consumption, pollutant sources and characteristics, major
research and development trends, fuel consumption trends, -and technical areas
where emission data are incomplete or unreliable. It also gives the pollutant emis-
sions from applicable unit operations for each of 56 source classifications, using a
uniform combustion source classification system.' It identifies major gaps in avail-
able data regarding the population and capacity of combustion systems, application of
control measures, fuel composition, and other parameters which significantly
influence pollutant characteristics and emission rates.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Pollution
Combustion
Utilities
Industries
Industrial Wastes
Residential Buildings
Steam Electric
Power Generation
Space Heating
Stationary Engines
STATEMENT
b. IDENTIFIERS/OPEN ENDED TERMS
c. COS3.TI Field/Croup
Pollution Control
Stationary Sources
Emissions Assessment
19. SECURITY CLAi
Unclassified
13B
21B
05C
10A
13A
21G
PAGES
555
EPA Form 2220-1 19-73)
531
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