-------
TABLE 3-4. Continued
Recommended Occupational TLV
Substance
ORGAN I CS
methanol
ethanol
propanol
ethyl ene
glycol-
vapor
parti cul ate
dimethyl
ether
diethyl
ether
ethyl ene
oxide
formic
acid
acetic
acid1
propionic
acid
formates :
ethyl
formate
methyl
formate
acetates:
ethyl
acetate
methyl
acetate
n-propyl
acetate
isopropyl
acetate
n -butyl
acetate
sec-
butyl
acetate
tert-
butyl
acetate
NIOSH
8-hr TWA
ppm ,
(mg/mj)
200
(262)
b
b
b
b
b
b
b
b
b
b
b
b
b
b
b
b
b
b
b
ACGIH
8-hr TWA
ppm ,
(mg/m }
200
(260)
1,000
(1,900)
200
(500)
100
(260)
(10)
b
400
(1,200)
50
(90)
5
(9)
10
(25)
b
100
(300)
TOO
(250)
400
(1,400)
200
(610)
200
(840)
250
(950)
150
(710)
200
(950)
200
(950)
ACGIH
!5-m1n STEL
ppm ,
(mg/m )
250
(310)
1,000
(1,900)
250
(625)
125
(325)
(20)
b
500
(1,500)
75
(135)
5
(9)
15
(37)
b
150
(450)
150
(375)
400
(1,400)
250
(760)
250
(1,050)
310
(1,185)
200
(950)
250
(1,190)
250
(1,190)
Estimated
Cone.
ppm,
(mq/m )
0.33
(0.43)
1.67
(3.14)
0.34
(0.83)
0.16
(0.43)
(0.02)
-
0.65
(1.98) v
0.08
(0.15)
0.008
(0.01)
0.02
(0.04)
(0.07)
0.16
(0.49)
0.16
(0-41)
0.64
(2.31)
0.33
(1.01)
0.33
(1.39)
0.38
(1.57)
0.25
(1.17)
0.33
(1.57)
0.33
(1.57)
Justification for Estimate
x • 1.65 x 10'3 (262).
x - 1.65 x 10'3 (1900).
x • 1.65 x 10'3 (500).
x = 1.65 x 10~3 (260).
x = 1.65 x 10"3 (10).
Non-toxic within estimated range of
emissions.
x = 1.65 x 10"3 (1200).
x = 1.65 x 10"3 (90).
x = 1.65 x 10~3 (9).
x = 1.65 x 10"3 (25).
Oral LD50, rat: 1510 ma/kn
x « 4.77 x 10'5 (1510).
x = 1.65 x 10"3 (300).
x * 1.65 x 10"3 (250).
x = 1.65 x 10'"3 (1400).
x = 1.65 x 10'3 (610).
x - 1.65 x 10'3 (840).
x = 1.65 x 10~3 (950).
x = 1.65 x 10'3 (710).
x • 1.65 x 10"3 (950).
x = 1.65 x 10'3 (950).
References
3-6
3-6
3-6
3-6
3-6
-
3-6
3-6
3-6
3-6
3-6, 3-9
3-6
3-6
3-6
3-6
3-6
3-6
3-6
3-6
3-6
3-31
-------
TABLE 3-4. Continued
Recommended Occupational TLV
Substance
ORGAN ICS
Isobutyl
acetate
propionates:
methyl
propionate
ethyl
propionate
acetic
anhydride
maleic
anhydride
succinic
anhydride
peroxyacetic
acid
benzene
toluene
ethyl
benzene
cumene
styrene
cresol
vinyl-
toluene
p-t-butyl
toluene
NIOSH ACGIH
8-hr TWA 8-hr TWA
ppm , ppm ,
(mq/m ) (mq/m )
b
b
b
b
b
b
b
1
(3.2)
(See
ref. 3-11)
100
(375)
8-hr
TWA
200
(750)
10-
min.
ceil-
ing
b
b
b
b
b
b
150
(700)
b
b
5
(20)
0.25
(1)
b"
b
10
(32)
100
(375)
100
(435)
50
(245)
100
(420)
(22)
100
(480)
10
(60)
ACGIH
15-mln STEL
ppm ,
(mq/m )
187
(875)
b
b
5
(20)
0.25
(1)
b
b
25
(80)
150
(560)
125
(545)
75
(365)
125
(525)
5
(22)
150
(720)
20
(120)
Estimated
Cone.
ppm,
(mq/m )
0.24
(1.16)
0.03
(0.12)
0.04
(0.17)
0.01
(0.03)
0.0004
(0.002)
_
(0.124)
(0.073)
_
(lng/n,3)
0.16
(0.62)
0.16
(0.72)
0.08
(0.4)
0.16
(0.69)
0.01
(0.04)
0.16
(0.79)
0.02
(0.1)
Justification for Estimate
x = 1.65 x 10'3 (700).
Oral LDLo, rabbit: 2550 mg/kg;
x • 4.77 x lO-5 (2550).
Oral LD50, rat: 3500 mq/ka
x • 4.77 x 10-5 (3500).
x = 1.65 x 10"3 (20).
x = 1.65 x in"3 (1).
Subcutaneous TDLo, rat;K2600 mq/ka/65
weeks; x « 4.77 x 10"s (2600).
Oral LD50, rat: 1540 mq/ka-
X • 4.77 x 10"5 (1540).
Suspected carcinoaen.
x = 1.65 x 10"3 (375).
x = 1.65 x 10~3 (435).
x = 1.65 x 10"3 (245).
x = 1.65 x 10"3 (420).
x = 1.65 x 10"3 (22).
x = 1.65 x TO"3 (480).
x • 1.65 x 10"3 (60).
References
3-6
3-6, 3-9
3-6, 3-9
3-6
3-6
3-6, 3-9
3-6, 3-9
3-6,
3-10, 3-11
3-6
3-6
3-6
3-6
3-6
3-6
3-6
3-32
-------
TABLE 3-4. Continued
Recommended Occupational TLV
NIOSH
8-hr TWA
ppm 3
Substance (mq/m )
ORGANICS
nltro-
anillne
naphtha-
lene
blphenyl
PCB's
(as chloro-
diphenyl)
42% chlorine
54% chlorine
anthracene
phenanthrene
fluoran-
thene
pyrene
benzo(a)-
pyrene
benzo(e)-
pyrene
perylene
anthanth-
rene
benzo(ghi)-
perylene
coronene
b
b
b
b
b
b
b
b
b
b
b
b
b
b
b
ACGIH
8-hr TWA
PPm 3
(mg/m )
1
(6)
10
(50)
0.2
(1)
-
(1)
.
(0.5)
b
b
b
b
b
b
b
b
b
b
ACGIH
15-nln STEL
ppm 3
(mq/m )
2
(12)
15
(75)
0.2
0)
-
(1)
-
(0.5)
b
b
b
b
b
b
b
b
b
b
Estimated
Cone.
ppm,
(mn/m )
0.002
(0.01)
(lng/m3)
0.0003
(0.002)
-
(lng/m3)
•
(lng/m3)
_
(lng/m3)
_
(0.03)
_
(0.09)
_
(lng/n3)
.
(lng/n3)
_
(lng/m3)
.
(lng/m3)
^
-
_
Justification for Fstim.te
x - 1.65 x 10"3 (6).
Suspected carcinogen.
x •= 1.65 x 10'3 (1).
Suspected carcinoaen.
Suspected carcinoaen.
Suspected carcinooen.
Oral LD50, mice: 700 mci/kn
x ' 4.77 x lO-5 (700).
Oral LD50, rat: 2000 mo/kq
x =• 4.77 x 10'5 (2000)
Suspected carcinoaen.
Suspected carcinogen.
Suspected carcinogen.
By analogy with naphthalene.
Insufficient toxicologic information
to estimate an exposure.
Insufficient toxicologic Information
to estimate an exposure.
Insufficient toxicologic Information
References
3-6
3-6, 3-10
3-6
3-6, 3-10
3-6, 3-10
3-6, 3-10
3-6, 3-9
3-6, 3-9
3-6, 3-10
3-6, 3-10
3-6, 3-10
3-33
-------
TABLE 3-4. Continued
NAAOS
(Ref. 3-12)
Cone.
ppm.
Substance (mg/m )
GASES AND
PARTICULATES
carbonates
ammonium a
carbonate
ammonium a
bicarbonate
potassium a
carbonate
carbonyls
nickel a
carbonyl
iron penta- a
carbonyl
carbon a
(elemental )
carbides
calcium a
carbide
iron a
carbide
silicon a
carbide
tungsten a
carbide
nitric acid a
nitrates a
nitrites a
cyanides
hydrogen a
cyanide
metallic a
cyanides
ammonia a
cyanates a
Recommended Occupational TLV
NIOSH ACGIH AC6IH
8-hr TWA 8-hr TWA 15-mln STEL
pom , ppm , ppm ,
(mg/mj) (mg/m ) (mg/nr)
b
b
b
b
b
b
b
b
b
b
2
(5)
b
b
b
b
50
b
b
b
.b
0.05
(0.35)
0.01
(0.08)
(3^5)
b
(i)
(10)
(5)
2
(5)
b
b
10
(11)
b
25
(18)
b
b
b
b
0.05
(0.35)
0.01
(0.08)
(7)
b
(2)
(20)
(10)
4
(10)
b
b
15
(16)
b
35
(27)
b
Estimated
Cone.
ppm.
(mq/mj)
(0.004)
(0.012)
(0.09)
(1 ng/m3)
0.02 ppb
(0.0001)
(0.006)
(0.002)
(0.02)
(0.008)
0.003
(0.008)
(0.008)
(0.008)
0.016
(0.018)
0.016
0.06
(0.04)
0.016
Justification for Estimate References
intravenous LD 50, mice: 96 nig/kg;
x * 4.77 x 10-5 (96)
Intravenous LD 50, mice: 245 rag/kg;
x - 4.77 x 10-5 (245)
Oral LD 50, rat: 1870 mg/kg;
x = 4.77 x ID"5 (1870)
Suspected carcinogen .
x = 1.65 x 10"3 (0.08)
x - 1.65 x 10"3 (3.5)
By analogy to calcium hydroxide,
calcium carbide is non-toxic with-
in range of estimated emissions.
TLV for soluble iron salts;
x = 1.65 x 10'3 (j)
TLV for nuisance particulates;
x » 1.65 x ID'3 (10)
TLV for insoluble tungsten compounds
x = 1.65 x ID'3 (5)
x = 1.65 x 10"3 (5)
By analogy to nitric acid.
By analogy to nitric acid.
x = 1.65 x 10"3 (11)
By analogy to hydrogen cyanide.
x * 1.65 x 10"3 (25)
By analoav to hvdrnopn cvanidp.
3-6, 3-9
3-6, 3-9
3-6, 3-9
3-6, 3-10
3-6
3-6
3-6
3-6
; 3-6
3-6
3-6
3-6
3-34
-------
NAAQS
.TABLE 3-4. Continued
Rtconnended Occupational TLV
Cone.
ppm.
Substance (mg/iO
GASES AND
PARTICULATES
amines, Imines,
1m1des
methyl ami ne a
ethyl ami ne a
ethyl ene- a
dlamine
dl ethyl- a
ami'ne
cyclohexyl- a
amine
aniline a
m'trlles a
nitro compounds
nltro- a
methane
2-nitro- a
propane
nltro- a
benzene
amides
acetamlde a
formamide a
azo compounds
azobenzene a
azoxy compounds
azoxybenzene a
sulfurlc add a
ammonium a
sulfate
metallic a
sul fates
NIOSH
8-hr TWA
ppm ,
,
(1 ug/mj)
0.033
(0.050)
1 3>
(1 ng/m3)
- 3
(1 ng/m )
(0.002)
(0.003)
.
(0.002)
Justification for Estimate
x • 1.65 x 10"3 (12)
x • 1.65 x 10"3 (18)
x « 1.65 x 10"3 (25)
x • 1.65 x 10"3 (75)
x • 1.65 x 10"3 (40)
x •= 1.65 x 10"3 (19)
By analogy to hydrogen cyanide.
x - 1.65 x 10"3 (250)
x = 1.65 x 10"3 (90)
x •= 1.65 x 10"3 (5)
Suspected carcinogen.
x = 1.65 x 10"3 (30)
Suspected carcinogen.
Suspected carcinogen.
x • 1.65 x 10"3 (1)
Oral LD 50, rat:, 58 mg/kg;
x « 4.77 x 10"9 (58)
By analogy to sulfurlc acid.
References
3-6
3-6
3-6
3-6
3-6
3-6
3-6
3-6
3-6
3-6
3-10
3-6, 3-9
' 3-10
3-10
3-6
3-6, 3-9
3-35
-------
TABLE 3-4. Continued
NAAQS Recommended Occupational TLV
NIOSH ACGIH ACGIH Estimated
Cone. 8-hr TWA 8-hr TWA !5-m1n STEL Cone.
ppm, ppm , ppm , ppm- ppm.
Substance (mg/m ) (ng/m ) (nq/m ) (mq/m ) (mq/m )
GASES AND
PARTICIPATES
sulfurous a b
acid
metal He a b
sulfites
sul fides
carbon a b
dlsulfide
hydrogen a b
sulfide
carbonyl a b
sulfide
metallic
thiosulfates
calcium a b
thiosulfate
magnesium a b
thiosulfate
elemental a b
sulfur
mercaptans
ethyl a b
mercaptan
sulfoxides
methyl a b
su If oxide
thiocyanates
ammonium a b
thiocyanate
potassium a b
thiocyanate
sodium a b
thiocyanate
sulfur 0.03 2
dioxide (0.08) (5)
annual arithmetic
mean
0.14
(0.365)
24-hour annual
maximum
b
b
20
(60)
10
(15)
b
b
b
(10)
0.5
(1)
b
b
b
b
5
(13)
b
b
30
(90)
15
(27)
b
b
b
b
0.5
(1)
b
b
b
b
5
(13)
(0.027)
(0.027)
0.032
(0.099)
0.016
(0.025)
0.016
(0.041)
(0.027)
(0.038)
(0.016)
0.0008
(0.0016)
(0.001)
(0.024)
(0.041)
(0.036)
0.03
(0.08)
0.14
(0.365)
Justification for Estimate References
By analogy to sulfur dioxide, with
allowance for differences In
molecular weight.
By analogy to sulfur dioxide, with
allowance for differences In
molecular weight.
x * 1.65 x 10"3 (60)
x = 1.65 x 10"3 (15)
By analogy to hydrogen sulfide.
intraperitoneal LDLo, rat: 573 mg/kg;
x = 4.77 x TO'5 (573)
3-6
3-6
3-6,
3-9
Intraperitoneal LDLo, rat: 805 mg/kg; 3-6,
x = 4.77 x 10"5 (805) 3-9
TLV for nuisance dusts;
x = 1.65 x 10'3 (10)
x = 1.65 x 10"3 (1)
Oral LD 50, rat: 20mg/kg;
x = 4.77 x ID'5 (20)
Intraperitoneal LDLo, mice: 500 mg/kg
x = 4.77 x 10"5 (500)
Oral LD 50, rat: 854 mg/kg;
x = 4.77 x 10'5 (854)
Oral LD 50, rat: 764 mg/kg;
x * 4.77 x 10"5 (764)
Annual arithmetic mean, federal
air quality standard.
24-hour maximum not to be exceeded
more than once per year, federal
air quality standard.
3-6
3-6
3-6, 3-9
3-6,
3-9
3-6,
3-9
3-6,
3-9
3-12
3-12
3-36
-------
NAAQS
TABLE 3-4. Continued
Recommended Occupational TLV
Cone.
ppm.
Substance (mg/m )
GASES AND
PARTICIPATES
sul fur a
tH oxide
carbon 9
monoxide (10)
8-hour annual
maximum
35
(40)
1-hour annual
maximum
nitric a
oxide
nitrogen 0.05
dioxide (0.1)
NIOSH
8-hr TWA
ppm 3
(ma/mj)
b
35
(38)
200 (ceiling)
(220)
25
(30)
1
(1.8)
ACGIH
8-hr TWA
,PP"> 3
.._0n.q/m )
b
50
(55)
25
(30)
5
(9)
ACGIH
lS-ra1n STEL
ppm,
(irw/m3)
b
400
(440)
35
(45)
5
(9)
annual arithmetic
mean
carbon a
dioxide
30
phosphorus a
pentoxide
phosphorous a
sesquioxide
elemental a
oxygen
ozone 0.08
(0.16)
1-hour annual
maximum
metallic a
phosphates
metallic a
hydrides
elemental a
hydrogen
selenium a
compounds
hydrogen a
chloride
potassium a
chloride
sodium a
chloride
10,000
(18,000)
,000 celling
(54,000)
b
b
b
b
b
b
b
b
b
b
b
5,000
(9,000)
b
b
b
0.1
(0.2)
b
b
b
.
(0.2)
5
(7)
b
b
15,000
(18,000)
b
b
b
0.3 .
(0.6)
b
b
b
(0.2)
5
(7)
b
b
Estimated
Cone.
, ppms
(tnq/m3)
(0.002)
9
10
35
(40)
0.04
(0.05)
0.05
(0.1)
8.25
(14.85)
(0.002)
(0.0002)
0.08
(0.16)
_
(0.0003)
0.008
(0.012)
(0?12)
.
(0.14)
Justification for Estimate References
By analogy to sulfuric acid
8-hour maximum, not to be exceeded 3-12
more than once per y«r, federal
ambient air standard.
1-hour maximum, not to be exceeded 3-12
more than once per year, federal
ambient air standard.
x - 1.65 x 10"3 (30) 3-6
Annual arithmetic mean, federal 3-12
ambient air standard.
x - 1.65 x 10"3 (9,000) 3-6
By analogy with phosphoric acid; , 3-6
(TLV Of 1 mg/m3); x •= 1.65 x 10"J(1)
By analogy with PjOi;; fy^e ^s
approximately 10 times more toxic.
Non-toxic within estimated range of
emissions.
Annual 1-hour maximum, not to be 3-12
exceeded more than once per year;
NAAQS for photochemical oxidants-
Non-toxic within estimated range of
emissions.
Non-toxic within estimated range of
emissions.
Non-toxic within estimated range of
emissions.
x - 1.65 x 10"3 (.2); (as Se) 3-6
x « 1.65 x 10"3 (7) 3-6
IntrapeHtoneal LDLo, rat: 2430 mg/kg; 3-6, 3-9
x • 4.77 x 10"5 (2430)
Oral LD 50, rat: 3000 mg/kg; 3-6, 3-9
x • 4.77 x ID'5 (3000)
3-37
-------
NAAQS
TABLE 3-4. Continued
Recommended Occupational TLV
NIOSH
Cone. 8-hr TWA
ppm , ppm 3
Substance (nq/m ) (mg/m )
GASES AND
PARTICIPATES
hydrogen a b
bromide
potassium a b
bromide
sodium a b
bromide
hydorgen a b
fluoride
potassium a b
fluoride
sodium a b
fluoride
hydrogen a b
iodide
potassium a b
Iodide
sodium a b
iodide
total 0.24 b
ACGIH
8-hr TWA
ppm ,
(mq/m )
3
(10)
b
b
3
(2)
b
b
b
b
b
b
ACGIH . Estimated
15-raln STEL Cone.
ppm. pprc^
(mqV) (ma/nr)
(10)
b
b
3
(2)
b
b
b
b
b
b
0.005
(0.016)
0.0002
(0.001)
(0.167)
0.005
(0.003)
(0.012)
(0.009)
0.005
(0.016)
(0.089)
(0.207)
Justification for Estimate References
x - 1.65 x 10'3 (10)
Ry analogy with bromide (TLV of ,
0.1 ppm, 0.7mg/m3); x « 1.65 x 10
(0.7)
Oral LD 50, rat:3500 ma/kg;
x = 4.77 x ID'5 (3500)
x = 1.65 x 10"3 (2)
Oral LD 50, rat:cZ45 rag/kg;
x = 4.77 x 10"5 (245)
Oral LD 50, rat: 180 mg/kg;
x = 4.77 x 10-5 (180)
By analogy with hydrogen bromide.
Oral LDLo, mice: 1862;
x = 4.77 x 10-5 (1862)
Oral LD 50, rat: 4340 mg/kg;
x = 4.77 x 10-5 (4340)
NAAQS for hydrocarbons selected for
3-6
3-6
3-6, 3-9
3-6
3-6, 3-9
3-6, 3-9
3-6, 3-9
3-6, 3-9
3-13
hydrocarbons (0.16)
3-hour (6-9am)
annual maximum
total
particulate (0.26)
24-hour annual
maximum
(0.075)
1-year geometric
mean
achievement of NAAQS for photochem-
ical oxidants, health effects not
observed at these levels-
24-hour maximum, not to be exceeded 3-12
(0.26) more than once per year, federal
ambient air standard.
Annual geometric mean,federal 3-12
(0.075) ambient air standard.
3-38
-------
TABLE 3-4. Continued
Recommended
Occupations! TLV
ACGIH ACGIH
8-hr TWA 15 mln STEL
Substance (mq/m3) (mq/m3)
ELEMENTS
aluminum 10 10
(as A1203)
antimony 0.5 0.75
compounds
(as Sb2)
arsenic 0.5 0.5
barium, 0.5 0.5
soluble
compounds
beryllium 0.002 0.025
bismuth b b
boron oxide 10 20
cadmium
oxide 0.05 0.05
fume,
as Cd
salts, 0.05 0.15
as Cd
calcium 5 5
oxide
cerium b b
cesium b b
chromium b b
insoluble
forms
chromic 0.1 0.1
acid and
chromates,
as Cr03
soluble 0.5 0.5
salts, as
Cr
cobalt 0.1 0.1
copper 1 2
dysprosium b b
Estimated
Cone,
(mq/m3)
0.0165
0.825
uo/m3
0.825
uq/tn3
0.825
ua/m3
3.3,
na/m
0.016
0.0165
82.5,
ng/m
82.5,
ng/m
O.OD825
0.0026
0.0033
1 ,
ng/m
0.165
ug/m3
0.825
ug/m3
0.165
ug/m3
1.653
uq/m
0.003
... , Justification for Estimate
TLV for nuisance dusts: x « 1 65 x IT3 (10) .
x • 1.65 x 10'3 (0.5).
x = 1.65 x 1C"3 (0.5).
x * 1.65 x 10'3 (0.5).
x = 1.65 x 10~3 (0.002).
Based on TLV for bismuth telluride; x * 1 «5 x
10-3 (10).
x * 1.65 x 10'3 (10).
x = 1.65 x 10~3 (0.05)
x = 1.65 x 10"3 (0.05).
x = 1.65 x 10"3 (5).
Member of lanthanide series-, by analoqy to yttrium
with corrections for difference in atomic weiqht.
'Based on TLV for cesium hydroxide; x = 1.65
x ID'3 (2).
Suspected carcinoqen.
x * 1.65 x 10'3 (n.l)
x = 1 65 x 10"3 (0.5).
x * 1 65 x 10'3 (0.1).
x - 1.65 x TO"3 (1).
Member of lanthanide series; by analony to yttrium
Jtefere
3-6
3-6
3-6
3-6
3-6
3-6,
3-6
3-6
3-6
3-6
3-6,
3-6
3-6
3-6
3-6
3-6
nccs
3-8
3-B
3-39
-------
TABLE 3-4. Continued
Recommended
Occupational TLV
ACGIH ACGIH
8-hr TWA 15-mln STEL
Substance (mo/m3) (mq/m3)
ELEMENTS
erbium b b
europi urn b b
gadolinium b b
gallium b b
germanium b b
gold b b
hafnium 0.5 1.5
hoi mi urn b b
iridium b b
iron 5 10
oxide
iron 1 2
soluble
salts,
as Fe
lanthanum b b
lead 0.15 0.45
arsenate,
as Pb
lead; 0.15 0.45
inoraanic,
as Pb
lithium b b
lutetium b b
manganese 5 5
and com-
pounds ,
as Mn
magnesium 10 10
oxide
fume
Estimated
Cone.
(mq/m3)
0.0031
0.0028
0.0029
0.0052
0.001
-
0.0008
0.003
3.2
ng/m3
0.00825
1.65,
un/m
0.0026
0.2475
ug/m3
0.2475
ug/m3
0.017
0.0032
0.00825
0.0165
Justification for Estimate
Member of lanthanide series;by analooy to
yttrium with correction for difference 1n atomic
weinht.
Member of lanthanide series; by analony to
yttrium with correction for difference 1n atomic
weight.
Member of lanthanide series by analogy to
yttrium with correction for difference in atomic
weioht.
Subcutaneous LDLo, rat' 110 mq/kg; x • 4.77 x
10-5 (110).
Based on TLV for germanium tetrahydridej x =1.65
x 10-3 (0.6).
Non-toxic within range of estimated emissions.
x = 1.65 x ID"3 (0.5).
Member of lanthanide series; by analony to
yttrium with correction for difference 1n atomic
weight.
Member of platinum group? by analogy to platinum
with correction for difference in atomic weioht.
x = 1.65 x 10"3 (5).
x = 1 65 x 10"3 (1)
Member of lanthanide series; by analogy to
yttrium with correction for difference in
atomic weight.
x = 1.65 x 10'3 (0.15)
x = 1.65 x 10"3 (0.15).
Intraperitoneal LDLo, rat: 360 ma/krj; x = 4 77
x 10-5 (360). '
Member of lanthanide series ; by analooy to
yttrium with correction for difference in atomic
weioht.
x = 1.65 x 10'3 (5)
x = 1.65 x 10'3 (10).
References >L
3-6, 3-9
3-6, 3-8
3-6
3-6
3-6
3-6
3-6
3-6, 3-9
3-6
3-6
3-40
-------
TABLE 3-4. Continued
Substance
ELEMENTS
mercury
all forms,
as Hg
tlkyl
compounds ,
is Hg
molybdenum,
as Mo
Insoluble
compounds
soluble
compounds
neodymi urn
nickel,
soluble
compounds ,
as Ni
niobium
osmium
palladium
platinum
potassium
praseo-
dymi urn
rhenium
rhodium
rubidium
ruthenium
samarium
scandium
selenium
compounds ,
as Se
Recommended
Occupational TLV
ACGIH ACGIH
8-hr TWA 15-mln STEL
iiHQ/nv^) (ntQ/tn^i
0.05 0.15
0.01 0.03
10 20
5 10
b b
0.1 0.3
b b
0.002 0.006
b b
0.002 0.002
b b
b b
b b
0.1 0.3
b b
b b
b b
b b
0.2 0.2
Estimated
Cone
82.5,
ng/m
16.5,
ng/m
0.0165
0.00825
0.0027
0.165
ug/m3
0.143
3.3
1.8
ng/mj
3.3
ng/m3
-
0.0026
0.013
0.165
ng/m3
0.21
1.7
ng/m3
0.0028
0.19\
0.33
ug/m
Justification for Es1;1n«t» References
x - 1.65 x ID"3 (0.05) 3.6
x • 1.65 x 10'3 (0.01) 3_6
x • 1.65 x 10'3 (10) 3.6
x • 1.65 x 10"3 (5) 3-6
Member of lanthanide series; by analoqy to
yttrium with correction for difference in atomic
weight.
x • 1.65 x 10'3 (0.1). . 3-6
Oral LD50, rat, for potassium niobate: 3000 3-6, 3-9
mg/kg; x - 4.77 x ID'S (3000).
Based on TLV for osmium tetroxide, as Os; 3-6
x ' 1.65 x 10-3 (0.002).
Member of platinum group; by analogy to platinum
with correction for difference in atomic weight.
Based on TLV for platinum salts, as Pt; 3-6
x - 1.65 x 10-3 (0.002).
Non-toxic within estimated range of emissions.
Member of lanthanide series; by analogy to
yttrium with correction for difference in
atomic weight.
Intraperltoneal LD50, mice, for rhenium * 3-6, 3-9
trichloride: 280 mg/kg; x « 4.77 x 10° (280).
x - 1.65 x 10'3 (0.1). 3-6
By analogy to lithium with correction for
difference 1n atomic weight.
Member of platinum group; by analogy to platinum
with correction for difference 1n atomic weight.
Member of lanthanide series, by analogy to
yttrium with correction for difference In atomic
weight.
Oral LD50, mice, for scandium trichloride: 3-6, 3-9
4000 mg/kg; x • 4.77 x 10"5 (4000).
x • 1.65 x 10"3 (0.2). 3-6
3-41
-------
TABLE 3-4. Continued
Substance
ELEMENTS
silicon
silver
and
soluble
compounds ,
as Ag
sodium
strontium
tantalum
tellurium
terbium
thallium
thorium
thulium
tin
titanium,
as titanium
dioxide
tungsten
insoluble
soluble
uranium
compounds,
as U
vanadium
oxide, as V
dust
fume
ytterbium
yttrium
zinc chloride
fume
zinc oxide
fume
zirconium
Recommended
Occupational TLV
ACGIH ACGIH
8-hr TWA !5-n1n STEL
(mg/m3) (mq/m3)
10
0.01
b
b
5
0.1
b
0.1
b
b
2
10
5
1
0.2
0.5
0.05
b
1
1
5
5
20
0.03
b
b
10
0.1
b
0.1
b
b
4
20
10
3
0.6
1.5
0.05
b
3
2
10
10
Estimated
Cone,
(mq/m3)
0.0165
16.5,
ng/m
-
0.0433
0.008
0.165
ng/m3
0.0029
0.165
Jjg/m3
1 jig/m3
0.0031
0.0033
0.0165
0.0082
0.0016
0.33 ug/m3
0.825 ug/m3
82.5 ug/m3
0.0032
0.0016
1.65 ug/m3
0.00825
0.0082
8
Justification for Estimate References ^
TLV for nuisance partlculates; x « 1.65 x 3-6
10-3 (10).
x - 1.65 x 10"3 (0.01). 3-6
Non-toxic within estimated range of emissions.
IntrapeHtoneal LD50, mice, for strontium 3-6, 3-9
chloride: 908 mg/kg; x « 4.77 x 10-5 (908).
x = 1.65 x 10"3 (5). 3-6
x - 1.65 x 10'3 (0.1). 3-6
Member of lanthanide series; by analogy to
yttrium with correction for difference 1n atomic
weight.
TLV for soluble thallium salts (as Tl); 3-6
x « 1.65 x ID'3 (0.1).
Radioactive, suspected carcinogen. 3-6, 3-10
Member of lanthanide series; by analogy to
to yttrium with correction for difference 1n
atomic weight.
TLV for Inorganic tin compounds (as Sn); 3-6
x-- 1.65 x ID'3 (2)
TLV for nuisance particulates; x = 1.65 x 10"3 (10)3-6
x • 1.65 x 10'3 (5) 3-6
X = 1.65 x 10"3 (1) 3-6
x * 1.65 x 10"3 (0.2) 3-6.
x « 1.65 x 10'3 (0.5) 3-6
X = 1.65 x 10'3 (0.05) 3-6
member of lanthanide series; by analogy
to yttrium with correction for difference
1n atomic weight
x * 1.65 x 10'3 (1) 3-6
x = 1.65 x 10"3 (1) 3-6
x - 1.65 x 10"3 (5) 3-6
TLV for zirconium compounds (as Zr); 3-6
3-42
-------
TABLE 3-4. Continued
Recommended Occupational TLV
NiOSH
8-hr TWA
PP1",
Substance (mg/mj)
MISCELLANEOUS
SECONDARY
POLLUTANTS
peroxyacetyl- b
nitrate
nitrocarboxylic
acids
m-nitrobenzolc b
acid
p-nitrobenzoic b
acid
cyclic
aldehydes
fufural b
phenol b
dicarboxylic
acids
oxalic b
acid
malonic b
acid
nitrobenzene b
hydroperoxides
t-butyl b
hydroperoxide
hydrogen b
peroxide
quinone b
carbonaceous b
particulate
matter
nitrosamines b
ACGIH
8-hr TWA
PPm,
(M/«|3)
b
b
b
5
(20)
5
(19)
_
(1)
b
1
(5)
b
1
(1.4)
0.1
(0.4)
b
b
ACGIH
15-mln STEL
ppm
(mq/m3)
b
b
b
15
(60)
10
(38)
_
(2)
b
2
(10)
b
2
(2.8)
0.3
(0.1)
b
b
Estimated
Cone.
(mq/m3)
0.08
-
(0.032)
(0.093)
0.008
(0.033)
0.008
(0.031)
*
_
(0.0016)
(0.062)
.
(0.008)
(0.019)
0.0016
(0.0023)
0.00016
(0.00066)
(0.016)
_
1 ug/m3
8
Justification for Estimate References *-
Annual 1-hour maximum, not to be
exceeded more than once per year;
NAAQS for photochemical oxidants.
Intraperitoneal LD50, rat: 670 mg/kg;
x * 4.77 x 10"5 (670)..
Oral LD50. rat: 1960 mg/kg;
x - 4.77 x 10'5 (I960).
x - 1.65 x 10'3 (20)
x - 1.65 x 10'3 (19)
x - 1.65 x 10"3 (1)
Oral LD50, rat: 1310 mg/kg;
x - 4.77 x lO'5 (1310).
x =1.65 x ID'3 (5)
Oral LD50, rat: 406 mg/kg;
x « 4.77 x 10"5 (406).
x " 1.65 x lO'3 (1.4)
x « 1.65 x 10'3 (0.4)
TLV for nuisance-dusts;
x - 1.65 x 10'3 (10).
Suspected carcinogens.
3-12
3-6, 3-9
3-6, 3-9
3-6
3-6
3-6
3-6, 3-9
3-6
3-6, 3-9
3-6
3-6
3-6
3-6, 3-10
3-43
-------
TABLE 3-4. Concluded
Footnotes
a a National Ambient A1r Quality Standard does not exist for
this substance
b an occupational standard does not exist for this substance
Abbreviations
LDLo lowest published lethal dose
NAAQS National Ambient Air Quality Standard
STEL short-term exposure limit
TLV threshold limit value
TWA time-weighted average
x maximum permissible concentration for continuous exposure
o
01
3-44
-------
TABLE 3-5. ENVIRONMENTAL SIGNIFICANCE OF SOME CHEMICALS THAT WAV EXIST IN AIRBORNE, LIQUID, AND SOLID EFFLUENTS FROM STATIONARY COMBUSTION SOURCES
PART A. CARBON AND NONMETALLIC COMPOUNDS I/
Element or
Chemical Class
Paraffins (alkanes)
Oleflns (alkenes)
Alkynes
Cyclic AHphatics
Aldehydes
Carboxylic Acids
Single Ring Aroma tics
Poly nuclear AroMtics
Carbonates
Carbonyls
Carbon
Nitrates
Nitrites
Atmonium Compounds
Organic N Compounds
cyanates
amines
nltriles
nitro compounds
Toxic
Aquatic 3/
(ppm)
10-100
10-100
<1
1-10
0.7
1-10
1.02-2.0
33
10-100
10-100
0.05
1-10
0.1
0.08
2
Levels 2/
Terrestrial 4/
(mg/kg) 5/
658
42
8
8
13.8
0.2
12
10
7
8
440
10-20 ppb
1
20 ppro
0.5 ppm
265
7
7
Synerglstlc Potential
or Other Interaction
Photo-oxidation with
NOX yields some PAN
Ozonated hexene causes
plant damage
When Irradiated, causes
plant damage
4
4
Synerglstlc with NO
and Irradiation In
causing plant damage
4
Synerglstlc with NO,
and Irradiation 1n
causing plant damage
Synerglstlc with ferric
oxide
Buffering action and
affect on pH may con-
tribute to toxlclty of
high pH
4
4
4
4
Anroonla Increases
rate of S02 oxidation
4
Quaternary amines
extract metal
cyanides from highly
alkaline solutions
4
Nitrosation of water
soluble pesticides
under acidic conditions
increases variety of N-
nitroso compounds
Formation of nitros-
amines enhanced by
thio-cvanate ion
Index of
Bioaccumulation
Potential
4
4
4
1
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Index of
Impact
Aquatic
4
4
4
1
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Biological
Potential 6/
Terrestrial
4
4
4
1
4
4
4
4
4
4
4
4
4
4
4
4
4
4
U.S. Occupational
Standards (mg/m3)
658 mg/kg
4
8 ng/kg
77 ng/kg
13.8 ppm
0.2 mg/kg
12
700
7 nig/kg
3.5 mg/kg
10 ppm
140
10 ppm
0.05 ppm
2
References
3-14,15
3-14,16,17
3-14
3-14
3-14,18,19
3-14,20
3-14,18
'3-14,19,21
3-14,19,20
3-14
3-14
3-14
3-14,20,22
3-14,19,23
3-14,20
3-14,20,24
3-14,19
3-14,18,25
-------
TABLE 3-5(a). CONCLUDED
Element or
Chemical Class
i mines
amides
imides
azo compounds
azoxy compounds
Sul fates
Sulfites
Sul fides
Sulfur
Organic S Compounds
mercaptans
sulfoxiHes
thlocyanates
Oxides
Oxygen
"
Hal ides
Toxic Levels 2/
Aquatic 3/ Terrestrial 4_/
(ppm) (mg/kg) 5/
14
125
0.1
18
4
6.25 20
203 3 ppm
<40 ppm
48 ppm
15 mg/m3
8
5
3.6 0.5-0.7 ppm
1 1 ppm
0.10 ppm
Synergistic Potential R1
or Other Interaction
4
4
4
4
4
4
4
4
4
4
4
4
Sulfur dioxide syner- .
gistlc with NO- at
0.5-2.5 ppb
Ozone synergistic with
S02
Ozone synergistic with
PAN
4
accumulati
4
4
4
4
4
4
4
4
4
4
4
4
4
4
3
Index of
)n Impact
Aquatic
4
4
4
4
4
4
4
4
4
4
4
4
4
4
1
Po1en??aia6/ »"S- 0«W
Terrestrial Standards (ing/
4
4
4
4
4
4 1
4 5 ppm
4 20 ppm
4 T ppm
4 800 mg
4
4
4 0.2
4 200
1 0.1 ppm
Si — -
3-19
3-14
3-20
3-14 •
3-14
3-14,20
3-14,20
3-14,18
3-14,26
3-14
3-14
3-14
3-14,22,27,
28
3-14,22,29
3-14,18,30,
31
-------
TABLE 3-5. ENVIRONMENTAL SIGNIFICANCE OF SOME CHEMICALS THAT MAY EXIST IN AIRBORNE, LIQUID, AND SOLID EFFLUENTS FROM STATIONARY COMBUSTION SOURCES
PART B. METALLIC INORGANIC COMPOUNDS I/
Element or
Chemical Class
ATuMlnuM
Antinomy
Arsenic
Beryl HIM
BISMth
CadnlM
Calclw
Cerium
C«SllM
Chromium
Copper
Dysprosium
Erbium
Europium
Gadolinium
Gallium
Germanium
Toxic Levels 2/
Aquatic 37 Terrestrial 4/
(ppm) (mg/kg) 5/
0.320 1 ppm
10-100 2
0.520 1.4
0.15 10
150
0.0026 2
0.5-10 5
*
0.14 4
100
0.016 1
1-10 2
196
30
156
25
37
1.5 586
- Synerglstic Potential B1
or Other Interaction
Toxicity of Al complexes
1s pH dependent
4
4
Toxldty decreases with
Increasing water hardness
4
Concentration factor
greatest at low salinity
Synerglstic with Cu
and Zn
Ca In water reduces
compounds of Pb, Zn,
and Al
Ca requirement 1s less
If Hg concentration 1s
high
High K concentration
Increases tolerance for
high Ca concentration
4
K In water has a slight
depressing effect on Cs
toxicity
Concentration In clams
varied inversely as log
function of estuary
salinity
2mg chromium/1 Intensi-
fied plant injury
caused by nickel
Cu, Cd, and Zn exert
synergisttc effects
Toxlclty decreases with
Increasing water hard-
ness
4
4
4
4
4
4
Index of
oaccumulatlon
Potential
3
4
2
4
3
2
3
3
3
3
4
4
4
4
4
3
3
Index of Biological
Impact Potential 6/
Aquatic
2
4
1
1
2
1
3
2
4
2
1
4
4
4
4
4
4
Terrestrial
3
4
1
1
2
2
3
3
3
3
1
4
4
4
4
4
4
U.S. Occupational p.*.,-.,,-.
Standards (mg/m') tefepences
4.6 3-14,16,32
0.5 3-14
1 3-14.19
2 y/m3 3-14,19,30
3-16
2 3-14,16,19,
33
3-14,16,19,
32
3-14,16,19
3-14,16,19
1 3-14,16,19,
20,34
1 3-14,30,33,
35,36
3-14
3-14
3-14
3-14
3-14,34
3-14,17,34
-------
TABLE 3-5(b). CONTINUED
Element or
Chemical Class
Gold
Hafnium
Hoi mi urn
IHdium
Iron
Lanthanum
Lead
Lithium
Lutetlum
Magnesium
Manganese
Mercury
Toxic Levels 2/ „ nn-alQti. pntpntiii Index of Index of Biological
Aquatic 3/ Terrestrial 4/ / ^l.__ , ... . j.V_J Bioaccumulation Impact Potential 6/
(ppm) (mg/kg) 5/ or er n erac 1on Potential Aquatic Terrestrial
0.40 30 4 423
0.06 75 4 423
270 4 444
4 444
0.2 7 4 323
0.15 3.5 4 323
0.01-1.0 42 Pb toxlcity reduced 2 1 3
in hard water
22 mg/m3 Efflux of Na and Ca in 3 3 3
cyanide abolished by
replacing Ca with Hg
and Na with LI
161 4 444
50 - 14 Mg reduces excessive 4 33
Zn uptake
n z.n 5 0.5 MnCl.,.4H,0 less toxic 4 33
at Tow salinities
With decreasing salinity
the concentration factor
of Mn increases
Mn Injury 1n plants in-
tensified by Mo & NOo
Mn reduces severity of
Co poisoning in tomatoes
NH4NOj reduces toxlcity
to plants
Mn antagonistic to toxic
action of Ni
0.0034 2 The toxic effects of mer- 1 1 1
curie salts are accen-
tuated by the presence of
trace amounts of Cu
In varying concentrations
NaCl exhibits first a
synergistlc effect, then
an antagonistic effect
toward the toxiclty of
HgClj
Synergistlc effects found
in all 2 and 3 factor
combinations of HgCl?,
Pb(NOj)2. and ZnS04
Hg with anionic detergents
is more than addltively
toxic
Hg more toxic at low salinities
U.S. Occupational „ -
3-14,16,19
0.5 3-14,16
3-14
3-14,16,19
3-14,16,19
150 U/m3 3-14,16,19,
37
3-14,16,19
3-14
4.1 3-16,19,25
5 3-14,16,19
0.1 3-14,16,19,
32
-------
TABLE 3-5(b). CONTINUED
Element or
Chemical Class
Heodymium
Nickel
Niobium
Osmium
Palladium
Platinum
Potassium
Praseodymium
Rhenium
Rubidium
Ruthenium
Samarium
Scandium
Selenium
Silver
Sodium
Toxic Levels 2/ Svncrai-tic Potpntlil
Index of
Aquatic 3/ Terrestrial 4/ „ nthA int.«rTi Bioaccumulation
(ppra) (mg/kg) 5/ or Other Inte|-actl°n Potential
17 ug/kg 4
0.07 .5 N1 more toxic at higher
salinities
Cu/N1 and Cr/Cu/Ni an-
tagonistic
Cr/NI synergistic
130 4
0.1 4 4
19 4
0.014 . 0.9ug/kg 4
3.0 6 Excessive K increases
tolerance for high con-
centrations of Ca and Hg
Tox1c1ty of K to fish re-
duced by Ca
K In saline irrigation
water prevents intake of
excessive amounts of NaCl
Increase in K decreases
herbicidal effectiveness
of CuS04
4 4
692 4
1160 4
4
9 4
93 4
2.0 0.2 As and Se are antagon-
istic
High sulfates diminish
uptake of Se
Toxicity decreases with
increasing water
hardness
0.003 1 Toxlcity decreases with
increasing water
hardness
0.3 1 Ca/Na and Ca/K act
antagonistically
Na is effective in
reducing excessive
In uptake
4
4
4
4
4
4
4
4
4
3
3
4
3
1
1
4
Index
Impac
Aquati
4
1
4
4
4
1
3
4
4
4
4
4
4
2
1
3
of Biological „ s Occupati
t Potential 6/ standards (mg
c Terrestrial =>lanoaras *»9
3
2 1
3
2 2 wg/m3
2
1 4.6 u/m3
3 0.1
*
3
3
3
4
3
3
1 0.05
1 10 y/m3
3 2
onal
/mj)
3-14
3-14,16,19,
32
3-14
3-14
3-14
3-14
3-14,16,19,
32
3-14
3-14
3-14
3-16
3-14,16
3-14,16
3-14,35,38
3-14,19.30,
39
3-14,16,26,
V
Jt
-------
TAULt 3-btbJ. CuNLLUUbU
Element or
Chemical Class
Strontium
Toxic Levels 2/
Aquatic 3/ Terrestrial 4/
(ppm) tmg/kg) 5/
1200 123
Synergistic Potential
or Other Interaction
Marked antagonistic
action between N1NO?
Index of
Bioaccumulation
Potential
2
Index of Biological .. , „ ..< ,
Impact Potential 6/ Indicates
only the single concentration was tested and found harmful or harmless.
-' The following aquatic organisms were used for determination of nearly all the toxic level results reported: brook trout, rainbow
trout, fathead minnow, blueglll, daphnlds, ampMbods, and midges.
y The following terrestrial organisms were used for determination of nearly all the toxic level results reported: rat, mouse.
guinea pig, dog, and cat.
-1 mg/kg 1s the amount of substance administered (Ingested or Injected) per kilogram of test organism weight,
& Relative toxicity of chemical classes disregarding emission factors.
-------
• In most cases, the concentration for continuous exposure, estimated from the RTI formula,
was far lower than concentrations that have been studied in animal or human exposures or
have been measured in community or occupational epidemiologic studies. For this reason,
these estimated exposure levels cannot be compared to any specific toxicologic results
except for the general observation that, for most substances, estimated levels were
below levels at which adverse health effects have actually been observed. For example,
mechanical application of the above formulae for CCL produces an estimated concentration
limit of 8 ppm versus a natural background level of 330 ppm.
i The estimates presented are for continuous exposure to a single pollutant. Estimates
were not made for short-term exposure nor was any consideration given to pollutant
synergisms or antagonisms which would influence the concentrations presented herein.
It should be stressed that these concentration limits are for screening purposes only. They
are not standards but rather preliminary indications of ambient concentrations at which health effects
from continuous exposure should be investigated.
In addition to the review which resulted in Tables 3-4 and 3-5, the current NOX ambient air
quality standard was reviewed in greater detail as described below.
The National Ambient Air Quality Standard for oxides of nitrogen is based on only one oxide of
nitrogen -nitrogen dioxide. Nitric oxide (NO) is also a common constituent of ambient air pollu-
tion, but is nonirritant and does not appear to cause adverse health effects at typical ambient
concentrations. The national primary and secondary standard for nitrogen dioxide, promulgated in
April of 1971, is an annual arithmetic mean of 100 ug/m3 (0.05 ppm).
The health criteria upon which this standard was based included few reports of human or animal
response following exposure to low levels of nitrogen dioxide. Most of the available toxicologic
literature pertained to nitrogen dioxide concentrations higher than those expected to occur in
ambient air. The national standard for nitrogen dioxide was mostly based on a community epidemiologic
study in Chattanooga, Tennessee, in which increased acute respiratory illness, increased bronchitis
among elementary school children, and decreased pulmonary function of elementary school girls were
associated with long-term exposure to elevated levels of nitrogen dioxide (0.062-0.109 ppm,
117-205 ug/m3) and suspended nitrates (4-6 yg/m3). Although the analytical method used in this
3-51
-------
study to measure nitrogen dioxide has been proven Inaccurate (resulting in a reevaluation of this
study), this reevaluation found insufficient cause to justify revising the national standard.*
The National Academy of Sciences' Committee on Medical and Biological Effects of Environmental
Pollutants analyzed and evaluated health effects of air pollutants in 1973. They concluded that
although the data base available for setting standards was inadequate, results of research since the
standards were adopted have generally supported these standards.
"None of the panels were satisfied with the data base available currently for
setting the standards. Nevertheless, in general, these panels found that the evidence
that has accumulated since the promulgation of the Federal ambient air quality stan-
dards by the EPA Administrator on April 30, 1971 supports those standards. In fact,
the safety factors provided by the air standards are much smaller than is usual in
regulating other environmental pollutants such as radioactivity. At the same time,
the health risks generated when the air quality limits are exceeded are also less
severe and usually more transitory than those for other pollutants. On balance, the
panels found no substantial basis for changing the standards. However, the Panel on
Nitrogen Dioxide suggested that consideration be given to establishing an hourly as
well as an annual standard for N02" (Reference 3-42, p.6).
Other reviews of research on health effects of nitrogen dioxide published since adoption of
the Federal standard (References 3-41 and 3-43) generally agree with this statement. In addition,
the NAS report states:
"There is sufficient information from both human and animal studies to determine
the levels of N02 which may contribute to toxic, often fatal, reactions. There is
some evidence to show that prolonged exposure to N02 levels of 117 yg/m3 — 205 ug/m3
can contribute to increased prevalence of chronic bronchitis, increased incidence of
acute lower respiratory disease and diminished pulmonary function in school children.
Unanswered questions still remain with respect to short-term exposure of NO? and the
effect on acute and chronic disease, those levels of NOg which may contribute to
systemic effects and levels of N02 which may be necessary to control possible adverse
health effects from suspended nitrates" (Reference 3-41).
In view of these "unanswered questions" concerning short-term nitrogen dioxide exposures, the
Office of Air Quality Planning and Standards has decided to defer consideration of a short-term
standard to 1978 when the N02 air quality criteria document is revised.
Recently, the reference method for nitrogen dioxide was replaced with a new measurement
principle and calibration procedure (Reference 3-44). EPA received some comments that a new refer-
ence method makes reevaluation of the present standard necessary. The EPA responded that a reevalu-
ation was not needed, as the NAAQS incorporated an adequate margin of safety to allow for uncertain-
ties in measurement errors.
An excellent discussion of these subsequent studies is offered in EPA's Scientific and Technical
Data Base for Criteria and Hazardous Pollutants (Reference 3-41).
3-52
-------
Other speculations on the possibility of revised nitrogen oxides air quality standards have
centered on the problem of nitrates and nitrosamines (Reference 3-45). In several personal conmuni-
cations with members of ,EPA's Office of Air Quality Planning and Standards, the current status of the
federal standard for nitrogen dioxide was discussed specifically with reference to (1) potential
changes in the annual average level due solely to the health effects of nitrogen dioxide, (2) the
introduction of a short-term standard to protect health, and (3) a more stringent standard as a
guide to reducing nitrates or nitrosamines.
Within EPA, a schedule has been prepared to revise all six criteria documents on which the
federal air quality standards are based over the next 3 to 4 years. The criteria document for photo-
chemical oxidants will be revised first, followed by that for hydrocarbons, nitrogen dioxide, carbon
monoxide and, finally, sulfur dioxide and particulates, which will be revised together. The revised
criteria document for nitrogen dioxide should be ready early in 1978. Full public hearings will be
held, and within a year or so from that time, a decision is expected on whether the present federal
standard for nitrogen dioxide will be revised.
No decision on a revision of the present nitrogen dioxide standard based on health effects is
expected until after the criteria document has been revised. Short-term exposures to nitrogen dioxide
have been a serious concern; however, as EPA assesses the present situation, insufficient data are
available to support the promulgation of a short-term standard for N02.
Finally, it appears that a change in the present nitrogen dioxide standard as a guide to
reducing nitrates or nitrosamines is unlikely within the next 5 years. EPA is aware of the
evidence from recent Community Health and Environmental Surveillance System (CHESS) studies
linking suspended nitrates to adverse health effects. However, this evidence by itself
does not justify a new Federal standard. There is also evidence that nitrates may not
exist as particulates, but as nitric acid vapor; both lines of investigation are being pursued.
Current knowledge of nitrogen oxides reactions in the ambient air does not provide convincing
evidence that ambient nitrogen oxides are transformed to ambient nitrosamines. Unless there is
evidence that nitrogen dioxide promotes formation of nitrosamines in the body, EPA does not foresee
changes in the federal standard. It appears, then, that unless legal action specifically forces
EPA to promulgate a new or revised standard for nitrogen dioxide, EPA foresees no change in the
present standard until after the criteria document is revised.
3-53
-------
3.4 SUMMARY AND CONCLUSIONS
The purpose of the impact assessment task is to provide useful limits on pollutant emissions
to assist in the evaluation of NOX control techniques. These emission limits will be used within
the NO environmental assessment to reduce the possibility that recommended control strategies will
reduce NO emissions only to increase other pollutants to unacceptable levels. As such, the focus of
the effort reported in Section 3 has been to develop approximate limits on the ambient concentrations
of a variety of pollutants. Relatively little filtering of substances (elimination of species because
of low ambient concentrations) has been performed to date. Instead, data for a large number of species
have been tabulated for use in screening from this stage on. Thus, the results presented in Section
3 set the stage for three levels of activity related to impact assessment:
• Initial program planning activities will identify both N0v control processes with poten-
A
tial emission problems and pollutants which may be emitted in quantities that approach
the threshold concentrations. This activity is initiated in Section 7 and will continue
through the near future. The results will guide the selection of processes for further
review, selection of pollutants requiring particular attention, and planning of tests
to be conducted under the NO E/A.
• Additional activity under Task B.2 will reinforce the data presented in Section 3, culmi-
nating in the B.2 special report on impact assessment. Activities will include refinement
of the health effects data base by additional personal contacts with researchers in the
area and by including data on human health effects from ingestion as well as inhalation.
The examination of pollutant effects on aquatic and terrestrial biota will be substan-
tially augmented through an expanded literature search and through personal contacts with
key researchers.
As additional data become available in the extended B.2 study on both human health and
terrestrial/aquatic effects, an attempt will be made to refine the current levels. This
will reflect additional data obtained during this study and will attempt to integrate all
effects data (human, aquatic, terrestrial) for a substance into one limiting concentration.
• Activities in the testing phase of this program will also address many issues currently
unresolved for lack of specific data. Particular issues include the actual emissions
from combustion sources employing NOX controls (especially liquid and solid effluents),
pollutant fates in the atmosphere, and the cumulative effect of actual pollutant concen-
trations. The data obtained in the course of testing under this and other programs, when
3-54
-------
integrated Into the B.2 data base, should substantially Increase confidence in the resulting
concentration limits.
In addition to the data presented in Section 3.3 and the qualifications to the data presented
herein, other questions have arisen which will be addressed in the program planning activities and
in the continuing efforts under B.2. The topics listed below will require further attention as the
NOV E/A proceeds:
X
• Early in the planning process, the interaction of the impact assessment task of this
program with other ongoing EPA programs will be considered. Many aspects of the present
program may benefit from data being obtained from other efforts, particularly the other
environmental assessments. During the near-term activities, the impact assessment task
will be reexamined to minimize duplication with other programs.
• Also during the current activities, internal efforts of the EPA to set standards, parti-
cularly as these efforts are affected by recent legislative actions, will be reviewed to
ensure that all future activities in this program are based on an accurate view of poten-
tial regulatory actions.
0 As the research proceeds for the B.2 task on impact assessment, there are three elements
which must be considered:
- The influence of fugitive and nonstandard emissions (for example soot-blowing, boiler
wash, startup, shutdown, etc.) in determining permissible concentrations,
— The approach to be followed to consider potentially carcinogenic or mutagenic emissions,
- The approach to define unacceptable effects on terrestrial and aquatic biota, where
irreversible effects may more readily be tolerated than in human health.
• Finally the role of pollutant interaction (both synergisms and antagonisms) must be con-
sidered in designing the bioassy experiments to be conducted under the testing phase.
In general, the effort documented in Section 3 presents preliminary guidelines for permissible
pollutant concentrations. These data are a conservative approach to determine whether NOX controls
are likely to cause unacceptable increases in other pollutants. Until reinforced by further activity
during B.2, these data should be considered as qualitative indications of potential problems rather
than precise quantitative threshold levels.
3-55
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REFERENCES FOR SECTION 3
3-1. Hidy, G. M., et al., "Characterization of Aerosols in California," ACHEX, California Air
Resources Board, Sacramento, California, 1974.
3-2. Hidy, G. M., in "Proceedings of the Conference on Health Effect of Atmospheric Salts and
Gases of Sulfur and Nitrogen in Association with Photochemical Oxidant," (T. T. Crocker, Ed)
California Air Resources Board, Sacramento, 1974, Vol. 2.
3-3. "California Air Quality Data," California Air Resources Board, 1973 to 1975.
3-4. Flocchini, R., et al., "Monitoring California's Aerosols by Size and Elemental Composition,"
Env. Sci. and Tech., Vol. 10:76, 1976.
3-5. Hanst, P. L., et al., "A Spectroscopic Study of California Smog," EPA 650-4-76-006,
Environmental Protection Agency, Office of Research and Development, National Environmental
Research Center, Research Triangle Park, North Carolina, 1975.
3-6. Handy, R. and A. Schlinder, "Estimation of Permissible Concentrations of Pollutants for
Continuous Exposure," Research Triangle Institute, EPA 600-2-76-155, NTIS-PB 253 959/AS,
June 1976.
3-7- Recommended NIOSH occupational standards obtained from the criteria document for that sub-
stance. For example: National Institute for Occupational Safety and Health. Criteria for
a Recommended Standard . . . Occupational Exposure to Ammonia.
3-8. "Threshold Limit Values for Chemical Substances and Physical Agents in the Workroom Environ-
ment with Intended Changes for 1976," American Conference of Governmental Industrial
Hygienists (ACGIH), Cincinnati, 1976.
3-9. "Registry of Toxic Effects of Chemical Substances, 1976 Edition," National Institute for
Occupational Safety and Health, U.S. GPO, June 1975.
3-10. "Suspected Carcinogens; a Subfile of the NIOSH Toxic Substances List," National Institute
for Occupational Safety and Health, DHEW Pub. No. (NIOSH) 75-188, U.S. GPO, June 1975.
3-11. "Revised Recommendation for an Occupational Exposure Standard for Benzene — INFORMATION,"
National Institute for Occupational Safety and Health, Newsletter of 25 August 1976.
3-12. "National Ambient Air Quality Standards," Code of Federal Regulations, 40 CFR 50.4 to 50.11,
1 July 1975.
3-13. "Air Quality Criteria for Hydrocarbons," U.S. Environmental Protection Agency, NAPCA Pub.
No. AP-64, U.S. GPO, March 1970.
3-14. Cristensen, H. E. and T. T. Luginbyhl (Ed), "Registry of Toxic Effects of Chemical Substances,"
U.S. Department of Health, Education and Welfare, Rockville, MD, p. 1296, 1975.
3-15. Middleton, J. T. (Ed), "Air Quality Criteria for Photochemical Oxidants," U.S. Department of
Health, Education and Welfare, Washington, D.C., 1970.
3-16. Eisler, R. and M. Wapner, "Second Annotated Bibliography on Biological Effects of Metals in
Aquatic Environments," Environmental Research Laboratory, EPA 600-3-75-008, NTIS-PB 248 211/AS,
1975.
3-17. Piersol, J. R., "Effect of Ethylene on Growth of Carnations: Preliminary Report," Colorado
Flower Growers Association, Inc., Bulletin 277, Denver, Colorado, 1973.
3-18. Lacasse, N. L. and W. J. Moroz, "Handbook of Effects Assessment Vegetation Damage," Center
for Air Environment Studies, Pennsylvania State University, University Park, Penn., 1969.
3-19. McKee, J. E. and H. E. Wolf (Ed), "Water Quality Criteria (2nd Ed.)," The Resources Agency
of California, State Water Resources Control Board Publication 3-A, 1963.
3-20. Becker, C. D. and T. 0. Thatcher (Ed), "Toxicity of Power Plant Chemicals to Aquatic Life,"
Pacific Northwest Laboratories, Richland, Washington, 1973.
3-56
-------
3-21. Clar, E., "Polycyclic Hydrocarbons, Vol. 2," Academic Press, New York, 1964.
3-22. Doudoroff, P. and M. Katz, "Critical Review of Literature on the Toxicity of Industrial
Wastes and Their Components to Fish. I. Alkalies, Acids, and Inorganic Gases," Sewage and
Industrial Wastes 22(11): 1432-1458,1950.
3-23. Greeley, R. A., et al., "Sulfates and the Environment: A Review," MTR-6895, The Mitre
Corporation, McLean, Virginia, 1975.
3-24. Copenhaver, E. D. and D. S. Harnden (Ed), "NSF-RANN Trace Contaminants Abstracts,"
ORNL/E15-96, Oak Ridge National Laboratory, Oak Ridge, Tenn., 1976.
3-25. Bruups, W. A., "Chronic Toxicity of Zinc to the Fathead Minnow, Pimephales Promelas
Rafinesque," Trans. Am. Fish Soc. 98:212-279, 1969.
3-26. "Mercury and Air Pollution: A Bibliography with Abstracts," U.S. Environmental Protection
Agency, Office of Air Programs Publication No. AP-114, 1972.
3-27. Hill, A. C. and J. H. Bennett, "Inhibition of Apparent Photosynthesis by Nitrogen Oxides,"
Pergammon Press, London, 1970.
3-28. Thompson, C. R., et al., "Acceptable Limits for Air Pollution Dosages and Vegetation Effects:
Nitrogen Dioxide," 67th Annual Meeting of the Air Pollution Control Association, Paper 74-227,
Denver, Colo., 1974.
3-29. Heggestad, H. E., et al., "Determining Acceptable Limits for Air Pollution Dosages and Vege-
tation Effects: Ozone," 67th Annual Meeting of the Air Pollution Control Association,
Paper 74-244, Denver, Colo., 1974.
3-30. Bowen, H. J., "Trace Elements in Biochemistry," Academic Press, New York, 1966.
3-31. Hill, A. C., "Air Quality Standards for Fluoride Vegetation Effects," Journal of the Air
Pollution Control Association 19:331-336, 1969.
3-32. Doudoroff, P. and M. Katz, "Critical Review of Literature on the Toxicity of Industrial
Wastes and Their Components to Fish. II. The Metals, as Salts," Sewage and Industrial
Wastes 25(7): 802-839,1953.
3-33. Eaton, J. G., "Chronic Toxicity of a Copper, Cadmium and Zinc Mixture to the Fathead Minnow
(Pimephales Promelas Rafinesque)." Water Research 7(11): 1723-1736, 1973.
3-34. Garton, R. R., "Biological Effects of Cooling Tower Slowdown," 71st National Meeting,
American Institute of Chemical Engineers, Dallas, Texas, 1972.
3-35. Davies, P. H. and J. P. Goettle, "Aquatic Life -Western Recommendations for Heavy Metals
and Other Inorganic Toxicants in Fresh Water," Submitted by Colorado Division of wildlife
for Water Quality Standards Revision Committee and Colorado Water Quality Control Commission,
1976.
3-36. Hazel, C. R. and S. J. Meith, "Bioassay of King Salmon Eggs and Sac Lay in Copper Solutions,"
California Fish and Game 56:121-124, 1970.
3-37. Schneider, R. F., "Impact of Various Metals on the Aquatic Environment," EPA Technical Report
No. 2, 1971.
3-38. Kothny, E. L. (Ed), "Trace Elements in the Environment," American Chemical Society Advances
in Chemistry Series No. 123, Washington, D.C., 1973.
3-39. Davies, P- H., et al., "Toxicity of Silver to Rainbow Trout (Salmo Gairdneri)." To be
published in Water Research, 1977.
3-40. Sinley, J. R., et al., "The Effects of Zinc on Rainbow Trout (Salmo Gairdneri)." To be
published in Water Research.
3-57
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3-41. "Scientific and Technical Data Base for Criteria and Hazardous Pollutants - 1975 ERC/RTP
Review," Health Effects Research Laboratory, EPA 600-1-76-023, 1976, NTIS-PB 253 942/AS.
3-42. "Air Quality and Automobile Emissions Control, Vol. 1, Summary Report," National Academy of
Sciences - National Academy of Engineering, Coordinating Committee on Air Quality Studies,
prepared for the Committee on Public Works, U.S. Senate, 93-24, 1974.
3-43. Ziskind, R. and D. Hausknecht, "Health Effects of Nitrogen Oxides," Science Applications,
Inc., EPRI 571-1A (PB 251264), 1976.
3-44. "Nitrogen Dioxide Measurement Principle and Calibration Procedure," Federal Register 41 (232):
52686-52695, December 1, 1976.
3-45. Fine, D. H., et al., "A Possible Nitrogen Oxide-Nitrosamine Cancer Link," Bull. Environ.
Contain. Toxicol. 11(1}:' 18-19, 1974.
3-58
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SECTION 4
NOX CONTROL CHARACTERIZATION
As a result of emission control regulations for new and existing stationary sources, there
has been extensive development and implementation of NO controls in the past 10 years. Nearly all
X
current NO control applications use combustion process modifications. Other approaches, e.g.,
modification or switching of fuel, use of alternate energy systems and post-combustion flue gas
treatment are being evaluated for potential future application along with more advanced combustion
process modifications. Control development experience has shown that the applicability and effec-
tiveness of combustion process modifications are strongly dependent on the specific equipment/fuel
combination to be controlled, and on whether the control is to be applied to existing field equip-
ment or new units. Accordingly, control development efforts are directed toward specific equipment
categories and fuel types. In general, the following sequence of control development is being pur-
sued for each major equipment/fuel category:
0 Minor operational adjustments
• Minor retrofit modifications
• Extensive hardware changes, either retrofit or factory-installed on new units
• Major redesign of new equipment
The progress made in this sequence varies with the importance of the source in local and national
NOX regulatory strategies. The position in the sequence will also affect how the source/control
combinations will be treated in the NO E/A. The developmental status of control, together with
results of field tests, will influence both the sequence of assessment and the level of effort in
the subsequent process studies. As a first step, this section evaluates the user experience, ef-
fectiveness, developmental status and projected uses of NOX controls in general and of specific
source/control combinations. Although the emphasis is on combustion modifications, other control
options are evaluated for potential far-term application.
The evaluation of NO control technology in this section is a link in the preliminary prior-
itization of source/control combinations concluded in Section 7. Section 2 gave preliminary group-
ing and screening of fuel combustion sources. This section notes current and impending control
4-1
-------
regulations for these sources and relates specific controls to the source to identify which source/
control combinations are the most promising to achieve given levels of control. The associated
evaluation of potential adverse environment impacts is given in Section 6. This effort scopes the
source/controls to be evaluated in the near-term effort in the NOX E/A. The results are further
evaluated in Section 7 to scope the later effort on far-term applications of NOX controls. Also
in Section 7, the potential adverse impacts of near-term applications are screened to prioritize
environmental assessment and testing requirements.
4.1 SURVEY OF NOX CONTROL REGULATIONS
Although the emphasis in the NOX E/A is on assessment of NOX control techniques, some con-
sideration must be made of the underlying regulatory strategy. This is because the relative prior-
ities in the NOV E/A for assessment of the various source/control combinations depend largely on
X
the current and anticipated control implementation requirements to attain and maintain ambient air
quality for NO,,. The Section 1 Introduction gave a broad overview of NOX control implementation
requirements and indicated the trend toward more widespread use of NO controls, particularly on
new equipment. This discussion supplements that overview by citing existing and impending NOX
emission regulations for stationary fuel combustion sources. It is intended to give perspective to
the subsequent review of the status and trends of control technology and to assist in setting prior-
ities on source/control combinations.
The incentive for NOV control development derives from two separate regulatory mechanisms,
A
the Federal Standards of Performance for New Stationary Sources (NSPS), and the State Implementation
Plans (SIPS). The NSPS are intended largely to assist in air quality maintenance by offsetting in-
creases due to source growth. The EPA sets NSPS from time to time based on the application of the
best system of emission reductions. Part of the NOX control development effort is directed at devel-
oping and demonstrating best systems of emission reduction in support of the setting of future NSPS.
The primary responsibility for air quality attainment and maintenance rests with the states. Emis-
sion standards in addition to the NSPS are set through the SIPS if required to attain and/or main-
tain the National Ambient Air Quality Standards in Air Quality Control Regions within the jurisdic-
tion of the states. Part of the NOX control development effort is directed at facilitating com-
pliance with existing standards.
4-2
-------
Table 4-1 summarizes the current and Impending NSPS for" NOX control from stationary fuel
combustion sources. All current and impending standards are based on application of combustion pro-
cess modifications. To date, NOX standards have been set only for utility and large industrial
boilers. The technology to support these standards was derived in part from demonstration of retro-
fit controls implemented in areas with attainment problems. A more stringent standard is being con-
sidered for coal-fired units based on technology demonstrated in control development since 1971.
No additional stringency is justified for new gas- or oil-fired units since no units of this type
are being sold. The standard being considered for gas turbines is also based on retrofit technology
demonstrated as part of SIPS. The standards under study for 1C engines and industrial boilers are
being based on EPA and private sector control development since there has been little retrofit con-
trol application for these sources.
As indicated in Section 1, maintenance of air quality in the 1980's and 1990's will require
NOX regulations in addition to those existing or planned. New source controls will be emphasized
since experience has shown them to be more effective, less costly and less disruptive than retrofit
control of existing equipment. Thus, EPA's Office of Air Quality Planning and Standards anticipates
additions to the standards shown on Table 4-1. These additions may involve both inclusion of
sources not presently regulated and setting more stringent standards for sources with current or
impending controls. In both cases, the driving force for the standards will be the best systems of
emission reductions demonstrated in the control development program.
State and local standards for new and existing stationary fuel combustion equipment are
listed in Table 4-2. As is the case for NSPS, the basis for the state and local standards is ap-
plication of combustion process modifications. This information was obtained through contacts with
local regulatory agencies and from the Environmental Reporter (Reference 4-1). Standards for new
sources which are the same as the Federal NSPS have been omitted. With the exception of the
Southern California Air Pollution Control District (SCAPCD), the standards are largely directed at
future air quality maintenance rather than attainment. Some areas have exercized the option to set
standards more stringent than required for maintenance by the SIPS. The SCAPCD has a serious attain-
ment problem and has accordingly instituted the most comprehensive and stringent emission regula-
tions. In fact, the control development in the SCAPCD has been so intense that it is useful as a
guide to the limits of current technology for existing gas- and oil-fired equipment. The trend in
the SCAPCD and elsewhere has been toward regulating smaller equipment categories and tightening the
regulations on larger equipment. The SCAPCD regulations are currently being evaluated as part of
the SIP revision to determine if further emission reductions are practical.
4-3
-------
TABLE 4-1. CURRENT OR PLANNED FEDERAL STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
Source
i
•to
Steam generators; heat input
>73 MW (250 MBtu/hr)
Gaseous fossil fuel-fired
Liquid fossil fuel-fired
Solid fossil fuel-fired
(except lignite)
Mixed fossil fuel-fired
Lignite coal-fired
Wood residue-fired
Coal-fired (except lignite)
Gas turbines; heat input
>2.2 MW (7.5 MBtu/hr)
Stationary 1C engines
Intermediate size steam
generators
Status
Promulgated 12-23-71
Promulgated 12-23-71
Promulgated 12-23-71
Promulgated 12-23-71
Proposed 12-22-76
Amended 11-22-76
SSEIS under review
SSEIS under review
SSEIS under review
Under study
Standard
86 ng/J (0.2 lb/106 Btu)
130 ng/J (0.3 lb/106 Btu)
300 ng/J (0.7 lb/106 Btu)
86X + 130Y + 3QOZa
ng/J
X + Y + Z
260 ng/J (0.6 lb/106 Btu)
Add wood residue to per-
missible mixed fuel firing
standard
260 ng/J (0.6 lb/106 Btu)
75 ppm (15 percent 02)
Reference
36 FR 24877
36 FR 24877
36 FR 24877
36 FR 24877
41 FR 55792
41 FR 51397
aX, Y, and Z are the percent of total heat input derived from gaseous, liquid and solid fossil fuels
Standards Support and Environmental Impact Statement
-------
TABLE 4-2. SUMMARY OF STATE AND LOCAL NOX EMISSION STANDARDS6
CALIFORNIAf
Bay Area APCD
Monterey Bay
San Diego
San Joaquln
Kern Co.
Santa Barbara APCD
Counties in SCAPCD:
LA Co.c
Orange Co.c
San Bernardino Co.
Riverside Co.c
New or
Existing
New
All
New
All
All
All
New
New
New
New
Any
All
All
New
Existing
Existing
Existing
Existing
Existing
Existing
Existing
Existing
Equipmentd
Type
Heat transfer
Heat transfer
Fuel burning
Fuel burning
Fuel burning
Fuel burning
Fuel burning
Fuel burning
Fuel burning
Fuel burning
Fuel burning
Equipment
Equipment
Equipment
Equipment
Equipment
Equipment
Equipment
Steam generators
Equipment
Equipment
Equipment
Heat Input
Capacity3
>73 (250)
>513 (1,750)
>440 (1,500)
>440 (1,500)
>15 (50)
>520 (1,775)
>520 (1,775)
>520 (1,775)
>520 (1 ,775)
>73 (250)
147-630
'(500-2,150)
>630 (2,150)
>520 (1,775)
147-520
(500-1,775)
>205 (700)
>205 (700)
>520 (1,775)
Gas
Fired
125 ppm
175 ppm
64 kg/hr9
125 ppm
225 ppm
125 ppm
64 kg/hr9
125 ppm
64 kg/hr9
64 kg/hrg
125 ppm
225 ppm
125 ppm
125 ppm
225 ppm
225 ppm
125 ppm
125 ppm
125 ppm
225 ppm
125 ppm
125 ppm
Standard
Oil
Fired
225 ppm
300 ppm
64 kg/hr9
225 ppm/hr
225 ppm
225 ppm
64 kg/hr9
225 ppm
64 kg/hr9
64 kg/hr9
225 ppm
325 ppm
225 ppm
225 ppm
325 ppm
325 ppm
225 ppm
225 ppm
225 ppm
325 ppm
225 ppm
225 ppm
i
Coal
Fired
64 kg/hr9
225 ppm
64 kg/hr9
225 ppm
64 kg/hr9
64 kg/hr9
_
-
-
-
-
-
—
Effective
Date
4/19/75
9/16/76
1/1/75
1/1/75
12/31/71
12/31/74
12/31/72
12/31/72
12/31/75
1/1/75
1/1/75
12/31/71
12/31/74
1/1/75
Comments
Applies to West Central
Area Only
Applies to West Central
Area Only
Applies to Balance of
County
(continued on p. 4-6)
-------
TABLE 4-2. Continued
SCAPCD
Ventura Co. APCD
CONNECTICUT
DELAWARE
New Castle Co.
DISTRICT OF COLUMBIA
FLORIDA
Tampa
ILLINOIS
Lake, Will, Du
Page, McHenry,
Kara, Grundy,
Kendall, Kankakee,
Macon, St. Clair,
Madison Cos.
Cook Co.
New or
Existing
New
All
All
All
All
New
New
All
All
Existing
New
Existing
All
All
Existing
Existing
Existing
New
Existing
Equipment
Type
Equipment
Fuel burning
Fuel burning
Steam generating
Fuel burning
Fuel burning
Fuel burning
Fuel burning
Fuel burning
Fuel burning
Fuel burning
Fuel burning
6T
Steam generators
Steam generators
Steam boilers
Fuel combustion
Fuel combustion
Fuel combustion
Heat Input
Capacity
523-628
(1,786-2,143)
>628 (2,143)
>163 (555)
161-523
(550-1,786)
>73 (250)
73-630
(250-2,150)
>630 (2,150)
>73 (250)
1.5-73
(5-250)
II
>147 (500)
>29 (100)
>2.9 (10)
>73 (250)
>59 (200)
j >59 (200)
Gas
Fired
64 kg/hr9
225 ppm
125 ppm
125 ppm
300 ppm
64 kg/hr9
125 ppm
250 ppm
125 ppm
86.1 (0.2)
86.1 (0.2)
86.1 (0.2)
387.3 (0.9)
86.1 (0.2)
86.1 (0.2)
86.1 (0.2)
129 (0.3)
86.1 (0.2)
129 (0.3)
Standard6
Oil
Fired
64 kg/hr9
325 ppm
225 ppm
225 ppm
400 ppm
64 kg/hr9
225 ppm
250 ppm
225 ppm
129 (0.3)
129 (0.3)
129 (0.3)
387.3 (0.9)
129 (0.3)
129 (0.3)
129 (0.3)
129 (0.3)
1Z9 (0.3)
129 (0.3)
Coal
Fi red
64 kg/hr9
325 ppm
225 ppm
225 ppm
400 ppm
64 kg/hr9
-
250 ppm
387.3 (0.9)
301 (0.7)
387.3 (0.9)
387.3 (0.9)
129 (0.3)
301 (0.7)
301 (0.7)
387.3 (0.9)
301 (0.7)
387.3 (0.9)
Effective
Date
1/1/77
7/1/76
7/1/75
Comments
Except peaking units at
Mandal ay
Except GT, 1C
Except GT, 1C
Except GT, 1C; variances
permi tted
Except for certain
sources governed by
operation permit
Except lignite
Except cyclone &
horizontally opposed
fired boilers burn-
ing solid fuel
ii n
-------
uonzinuea
INDIANA
MARYLAND
MINNESOTA
NEW MEXICO
NEW YORK
New York City
NORTH CAROLINA
OHIO
OKLAHOMA
SOUTH DAKOTA
TEXAS
Dallas-Fort Worth S
Houston- Calves ton
ACQR'S
VERMONT
New or
Existing
Existing
New
Existing
New
Existing
New
Existing
All
All
All
Existing
Existing
New
All
All
New
New
Equipment
Type
Fuel burning
Fuel burning
Boilers
Coal burning
Coal burning
Gas burning
Gas burning
Oil burning
GT, 1C
Boilers
Boilers
Boilers
Fuel burning
Fuel burning
Steam generators
Opposed fired
Front fired
Tangential fired
Combustion
GT
Heat Input
Capacity
>:73 (250)
>73 (250)
>73 (250)
>73 (250)
>73 (250)
>1 ,055,000 GJ/
yr (1,000,000
MBtu/yr)
II
^73 (250)
>147 (500)
2.73 (250)
>J3 (250)
>15 (50)
>272.200 kq/hr
max (>600,000
Ibs/hr max)
continuous
capacity
2.73 (250)
>73 (250)
Gas
Fired
86.1 (0.2)
86.1 (0.2)
129 (0.3)
86.1 (0.2)
129 (0.3)
86.1 (0.2)
73.2 (0.17)
258.2 (0.6)
86.1 (0.2)
86.1 (0.2)
86.1 (0.2)
301 (0.7)
215.2 (0.5)
107.6 (0.25)
~~
Standard
Oil
Fired
129 (0.3)
129 (0.3)
172.1 (0.4)
129 (0.3)
129 (0.3)
77.5 (0.18)
258.2 (0.6)
129 (0.3)
129 (0.3)
129 (0.3)
—
-
129 (0.3)
129 (0.3)
Coal
Fired
301 (0.7)
215.2 (0.5)
193.6 (0.45)
301 (0.7)
301 (0.7)
86.1 (0.2)
559.4 (1.3)
387.3 (0.9)
301 (0.7)
—
—
-
-
Effective
Date
12/31/74
12/31/74
12/31/74
7/1/72
8/31/72
7/1/71
7/1/73
Conments
Applies to "Priority
Basin A" only — none
at present
Applies to Priority I
AQCR's only
Applies only to
Priority I regions
Except GT
(continued on p. 4-8)
-------
TABLE 4-2. Concluded
WYOMING
New or
Existing
New
Existing
New
New
Existing
Existing
New
Existing
Equipment
Type
Gas burning
Gas burning
Oil burning
Oil burning
Oil burning
Oil burning
Solid fired equip
Solid fired equip
Heat Input
Capaci tya
>0.29 (1)
<0.29 (1)
>73 (250)
<73 (250)
Standard15
Gas Oil Coal
Fired Fired Fired
86.1 (0.2)
99 (0.23)
129 (0.3)
258.2 (0.6)
197.9 (0.45)
258.2 (0.6)
301 (0.7)
322.7 (0.75)
*
Ef f ecti ve
Date
Except 1C <59 (200)
Except 1C <59 (200)
Except 1C <59 (200)
Except 1C <59 (200)
Except 1C <59 (200)
Except 1C <59 (200)
Except 1C <59 (200)
Except lignite
aUnless stated otherwise, units are MW (10s Btu/hr)
bUnless stated otherwise, units are ng/J (lb/106 Btu).
°Rules put into effect before SCAPCD was formed and replaced by SCAPCD rules
dGT refers to gas turbines; 1C refers to reciprocating internal combustion engines
eNOv emission standards in chronological order In so far as possible
f A
All ppm standards are at 3 percent 02
9140 Ibs/hr
-------
In summary, the sources and emission levels listed in Tables 4-1 and 4-2 establish the scope
of sources and levels of controls to be evaluated in the near-term effort of the NO E/A to assess
the incremental impacts of current NOX control technology. The remainder of this section evaluates
the available control technology to establish the source/control combinations to be emphasized in
the near-term effort. It also notes the emerging technology which will be considered in the far-
term as discussed in more detail in Section 7.
4.2 COMBUSTION PROCESS MODIFICATIONS
Modifying the combustion process conditions is the most effective and widely used technique
for achieving moderate (40 to 60 percent) reduction in combustion-generated oxides of nitrogen.
This subsection evaluates the combustion modification techniques either demonstrated or currently
under development. The discussion begins by reviewing the formation mechanisms of NO and the
general principles for suppressing NO emissions by process modifications.
4.2.1 General Concepts on NO Formation and Control
Oxides of nitrogen formed in combustion processes are due either to the thermal fixation of
atmospheric nitrogen in the combustion air, which produces "thermal NOX", or to the conversion of
chemically-bound nitrogen in the fuel, which produces "fuel NOX." For natural gas and light distil-
late oil firing, nearly all NOV emissions result from thermal fixation. With residual oil, crude
X
oil, and coal, the contribution from fuel-bound nitrogen can be significant and, in certain cases,
predominant.
4.2.1.1 Thermal NOX
During combustion, nitrogen oxides are formed by the high temperature, thermal fixation of
N2. Nitric oxide (NO) is the major product, even though N02 is thermodynamically favored at lower
temperatures. The residence time in most stationary combustion processes is too short for NO to be
oxidized to N02>
The detailed chemical mechanism for thermal NO formation is not fully understood. However,
it is widely accepted that thermal fixation in the post-combustion zone occurs according to the
extended form of the Zeldovich chain mechanism (Reference 4-2):
N2 + 0 ? NO + N (4-1)
N + 02 t NO + 0 (4-2)
N + OH £ NO + H (4-3)
4-9
-------
assuming that the combustion reactions have reached equilibrium. Reaction (4-1) has a large activa-
tion energy (75.8 kcal/mole) and is generally believed to be rate determining. Oxygen atom concen-
trations are assumed to have reached equilibrium according to:
02 + M?0 + 0 + M (4-4)
where M denotes any third substance (usually N2).
In the flame zone itself, the Zeldovich mechanism with the equilibrium oxygen assumption is
not adequate to account for experimentally observed NO formation rates. Several investigators have
observed the production of significant amounts of "prompt" NO, which is formed very rapidly in the
flame front (References 4-3 through 4-11), but there is no general agreement on how it is produced.
Prompt NO is believed to stem from the existence of "superequilibrium" radical concentrations
(References 4-11, 4-12, and 4-13) within the flame zone which result from hydrocarbon chemistry and/
or nitrogen specie reactions, such as suggested by Fenimore (Reference 4-14). To date, prompt NO
has only been explicitly measured in carefully controlled laminar flames, but the mechanism almost
certainly exists in typical combustor flames as well. Of course, in an actual combustor, both the
hydrocarbon and NO kinetics are directly coupled to turbulent mixing in the flame zone.
Recent experiments at atmospheric pressure indicate that under certain conditions the amount
of NO formed in heated N-, Op and Ar mixtures can be expressed as (Reference 4-15):
[NO] = k1 exp (-k2/T)[N2][02]1/2t (4-5)
where [ ] = mole fraction
k,, k2 = constants
T = temperature (K)
t = time (sec)
Although this expression certainly will not adequately describe NO formation in a turbulent flame,
it does summarize thermal NOX formation. It reflects the strong dependence of NO formation on
temperature. It also shows that NO formation is directly proportional to N2 concentration and to
residence time, and proportional to the square root of oxygen concentration.
Based on the above relations, thermal NOX can theoretically be reduced using four tactics:
• Reduce local nitrogen concentrations at peak temperature
• Reduce local oxygen concentrations at peak temperature
4-10
-------
• Reduce the residence time at peak temperature
• Reduce peak temperature
Since reducing N2 levels is quite difficult, efforts in the field have focused on reducing
oxygen levels, peak temperatures, and time of exposure in the N0x-producing regions of a combustor.
On a macroscopic scale, techniques such as lowered excess air and off-stoichiometric (or staged)
combustion have been used to lower local 02 concentrations in boilers. Since internal combustion
(1C) engines and gas turbines typically operate at excess air levels far greater than stoichiometric,
lowering excess air levels in these equipment classes does not control thermal NO . However, off-
X
stoichiometric combustion in the form of stratified charge cylinder design has been used successfully
in 1C engines.
Flue gas recirculation and reduced air preheat have been used in boilers to control thermal NO
X
by lowering peak flame temperatures. Analogously, exhaust gas recirculation (EGR), reduced manifold
air temperature (1C engines) and reduced air preheat have been applied to 1C engines and gas turbines.
Other techniques designed to lower peak temperatures in prime movers include water injection and
altered air/fuel ratios.
Techniques which reduce residence time at peak temperature have been more easily applied to
prime mover equipment classes. Although flue gas recirculation (and EGR) reduces combustion gas
residence time, it acts as a thermal NO control primarily through temperature reduction. Tech-
niques which specifically reduce exposure time at high temperatures include ignition retard for 1C
engines and early quench with secondary air for gas turbines.
It is important to recognize that the above-mentioned techniques for thermal NOX reduction
alter combustion conditions on a macroscopic scale. Although these macroscopic techniques have all
been relatively successful in reducing thermal NOX> local microscopic combustion conditions ulti-
mately determine the amount of thermal NO formed. These conditions are in turn intimately related
to such variables as local combustion intensity, heat removal rates, and internal mixing effects.
Modifying these secondary combustion variables at microscopic levels requires fundamental changes
in combustion equipment design.
For example, recent studies on the formation of thermal NO in gaseous flames have confirmed
that internal mixing can have large effects on the total amount of NO formed (References 4-16, 4-17).
Burner swirl, combustion air velocity, fuel injection angle and velocity, quarl angle and confinement
ratio all affect the mixing between fuel, combustion air and recirculated products. Mixing, in turn,
alters the local temperatures and specie concentrations which control the rate of NO formation.
4-11
-------
Unfortunately, generalizing these effects is difficult, because the interactions are complex.
Increasing swirl, for example, may both increase entrainment of cooled combustion products (hence
lowering peak temperatures) and increase fuel/air mixing (raising local combustion intensity). The
net effect of increasing swirl can be to either raise or lower NOX emissions, depending on other
system parameters.
In summary, a hierarchy of effects depicted in Table 4-3 produces local combustion conditions
which promote thermal NO formation. Although combustion modification technology seeks to affect
the fundamental parameters of combustion, modifications must be made by changing the primary equip-
ment and fuel parameters. Control of thermal NOV, which began by altering inlet conditions and
A
external mass addition, has moved to more fundamental changes in combustion equipment design.
4.2.1.2 Fuel NOX
The role of fuel-bound nitrogen as a source of NOX emissions from combustion sources has been
recognized since 1968 (Reference 4-18). Although the relative contribution of fuel and thermal NO
A
to total NO emissions from sources firing nitrogen-containing fuels has not been definitively
established, recent estimates indicate that fuel NOX is significant and may even predominate. In
one recent study (Reference 4-19), residual oil and pulverized coal were burned in an argon/oxygen
mixture to eliminate thermal NO effects. Results show that fuel NO can account for over 50 per-
X X
cent of total NOV production from residual oil firing and approximately 80 percent of total NOV
X A
from coal firing. Therefore, as coal is increasingly used as a national energy source, the control
of fuel NO will become more important.
Fuel-bound nitrogen occurs in coal and petroleum fuels. However, the nitrogen containing
compounds in petroleum tend to concentrate in the heavy resin and asphalt fractions upon distilla-
tion (Reference 4-20). Therefore fuel NOX is of importance primarily in residual oil and coal fir-
ing. The nitrogen compounds found in petroleum include pyrroles, indoles, isoquinolines, acridines,
and porphyrins. Although the structure of coal is not known with certainty, it is believed that
coal-bound nitrogen also occurs in aromatic ring structures such as pyridine, picoline, quinoline,
and nicotine (Reference 4-20).
The nitrogen content of residual oil varies from 0.1 to 0.5 percent. Nitrogen content of
most U.S. coals lies in the 0.5 to 2 percent range (Reference 4-21); anthracite coals contain the
least and bituminous coals the most nitrogen. Figure 4-1 illustrates the nitrogen content of various
U.S. coals, expressed as Ib N02 produced per million Btu for 100 percent conversion of the fuel
4-12
-------
TABLE 4-3. FACTORS CONTROLLING THE FORMATION OF THERMAL NO,
Primary Equipment
and Fuel Parameters
Secondary
Combustion Parameters
Fundamental
Parameters
Inlet temperature,
velocity
Firebox design
Fuel composition
Injection pattern
of fuel & air
Size of droplets
or particles
Burner swirl
External mass
addition
Combustion intensity
Heat removal rate
Mixing of combustion
products into
flame
Local fuel-air ratio
Turbulent distortion
of flame zone
Oxygen level
Peak temp.
Exposure time
at peak
temp.
Thermal
NO..
-------
3,000
c
o
S-
OJ
> 2,000
c
o
o
6-5
O
O
,-, 1 ,000
C\J
0
•z.
O)
G
Q
-
6
Z
p
I/)
«™eiH«.Le»»
/ N»5 Comtnn
/
r^ n
^^ "^3 D 0 1
<>A~tf|i5QO ^ "
A <
r~" •
EPA Sto
1
a
rvj
rl «*•
/» a
A (
rd
1
•3 - •
* * o 1
I
o
1 1 1
—
« 0
I
/
Q a
1 1 1
01 234 56789 10
!b. SO2MO6 8TU 1OO % CONVERSION
I l I l
0 1,000 2,000 3,000 4,000
ng S02/J 100% conversion
Figure 4-1. Nitrogen and sulfur content of U.S.
coal reserves (Reference 4-22).
4-14
-------
nitrogen (Reference 4-22). The figure clearly shows that 1f-all coal-bound nitrogen were converted
to NOX, emissions for all coals would exceed New Source Performance Standards. Fortunately, only a
fraction of the fuel nitrogen is converted to NOX for both oil and coal firing, as shown in Figure
4-2 (Reference 4-23). Furthermore, the figure indicates that fuel nitrogen conversion decreases as
nitrogen content increases. Thus, although fuel NO emissions undoubtedly increase with increasing
fuel nitrogen content, the emissions increase is not proportional. In fact, recent data indicate
only a small increase in N0¥ emissions as fuel nitrogen increases (Reference 4-24). From observations
A
such as these, the effectiveness of partial fuel denitrification as a NO control method seems doubtful.
Although the precise mechanism by which fuel nitrogen is converted to NO is not understood,
A
certain aspects are clear, particularly for coal combustion. In a large pulverized coal utility
boiler, the coal particles are conveyed by an air stream into the hot combustion chamber, where they
are heated at a rate in excess of lO^K/sec. Almost immediately volatile species, containing some of
the coal-bound nitrogen, vaporize and burn homogeneously, rapidly (-10 msec) and probably detached
from the original coal particle. Combustion of the remaining solid char is heterogeneous and much
slower (~300 msec).
Figure 4-3 summarizes what may happen to fuel nitrogen during this process (Reference 4-25).
In general, nitrogen evolution parallels evolution of the total volatiles, except during the initial
10 to 15 percent volatilization in which little nitrogen is released (Reference 4-26). Both total
mass volatilized and total nitrogen volatilized increase with higher pyrolysis temperature; the
nitrogen volatilization increases more rapidly than that of the total mass. Total mass volatilized
appears to be a stronger function of coal composition than total nitrogen volatilized (Reference
4-27). This supports the relatively small dependence of fuel NOX on coal composition observed in
small scale testing (Reference 4-19).
Although there is not absolute agreement on how the volatiles separate into species, it ap-
pears that about half the total volatiles and 85 percent of the nitrogeneous species evolved react
to form other reduced species before being oxidized. Prior to oxidation, the devolatilized nitrogen
may be converted to a small number of common, reduced intermediates, such as HCN and NH3> in the
fuel-rich regions of the flame. The existence of a set of common reduced intermediates would explain
the observations that the form of the original fuel nitrogen compound does not influence its con-
version to NO (e.g., References 4-20, 4-28). More recent experiments suggest that HCN is the predom-
inant reduced intermediate (Reference 4-29). The reduced intermediates are then either oxidized to
NO, or converted to N2 in the post-combustion zone. Although the mechanism for these conversions is
not presently known, one proposed mechanism postulates a role for NCO (Reference 4-30).
4-15
-------
X
0
z
° 100-
c
o
CO
1 80"
o
o
« 60-
3
4*-
*H-
0
»« 40-
20 '
u- VJ
#2 - #5 | Calif, residual fuel oil t
,Ca]if- . . .. , i Bituminous coal ,
» • i Sub-bituminous coal i
|Nero. | i Anthr-irn-f-r rml
Coal Data Sources Oil
® Pereira, et al . (1974)
•& > Pershing, et al. (1973)
tt A McCann (1970)
Q O0 Jonke (1970)
^ A H Bituminous M.I.T. (1975)
^•0^. .. ^ Lignite M.I.T. (1975)
<3^ &JD®^
& d^L ^j o
'Coal 7,000 Btu/lb
O
<^ Flagan & Appleton (1974)
A Hazard (1973)
Q Turner & Siegmund (1972)
O Fenimore (1972)
O Turner, et al . (1972)
V Martin & Berkau (1972)
I> Pershing, et al. (1973)
-------
VOLATILE FRACTIONS
(HYDROCARBONS, RN etc.)
KN
ASH
VIRTUALLY
NITROGEN
FREE
Figure 4-3. Possible fate of fuel nitrogen contained in
coal particles during combustion (Reference 4-25).
4-17
-------
Nitrogen retained in the char may also be oxidized to NO, or reduced to N2 through heteroge-
neous reactions occurring in the post-combustion zone. However, it is clear that the conversion of
char nitrogen to NO proceeds much more slowly than the conversion of devolatilized nitrogen. In
fact, based on a combination of experimental and empirical modeling studies, it is now believed
that 60 to 80 percent of the fuel NO results from volatile nitrogen oxidation (References 4-26,
X
4-31). Conversion of the char nitrogen to NO is in general lower, by factors of two to three, than
conversion of total coal nitrogen.
Regardless of the precise mechanism of fuel NOX formation, several general trends are evident,
particularly for coal combustion. As expected, fuel nitrogen conversion to NO is highly dependent
on the fuel/air ratio for the range existing in typical combustion equipment, as shown in Figure 4-4.
Oxidation of the char nitrogen is relatively insensitive to fuel/air changes, but volatile NO forma-
tion is strongly affected by fuel/air ratio changes.
In contrast to thermal NO , fuel NO production is relatively insensitive to small changes in
combustion zone temperature (Reference 4-28). Char nitrogen oxidation appears to be a very weak
function of temperature, and although the amount of nitrogen volatiles appears to increase as temper-
ature increases, this is believed to be partially offset by a decrease in percentage conversion.
Furthermore, operating restrictions severely limit the magnitude of actual temperature changes at-
tainable in current systems.
As described above, fuel NO emissions are a strong function of fuel/air mixing. In general,
any change which increases the mixing between the fuel and air during coal devolatilization will
dramatically increase volatile nitrogen conversion and increase fuel NO. In contrast, char NO for-
mation is only weakly dependent on initial mixing and therefore may represent a lower limit on the
emission level which can be achieved through burner modifications.
From the above modifications, it appears that, in principle, the best strategy for fuel NO
abatement combines low excess air firing, optimum burner design, two-stage combustion and high air
preheat. Assuming suitable stage separation, low excess air may have little effect on fuel NO, but
it increases system efficiency. Before using LEA firing, the need to get good carbon burnout and
low CO emissions must be considered.
Optimum burner design ensures locally fuel-rich conditions during devolatilization, which
promotes reduction of devolatilized nitrogen to N2> Two-stage combustion produces overall fuel-rich
conditions during the first 1 to 2 seconds and promotes the reduction of NO to NZ through reburning
4-18
-------
t
ID
X
o
§>
£
O
-P
-------
reactions. High secondary air preheat also appears desirable, because it promotes more complete
nitrogen devolatilization in the fuel-rich initial combustion stage. This leaves less char nitrogen
to be subsequently oxidized in the fuel-lean second stage. Unfortunately, it also tends to favor
thermal NO formation, and at present there is no general agreement on which effect dominates.
4.2.1.3 Summary of Process Modification Concepts
In summary of the above discussion, both thermal and fuel NOX are kinetically or aerodynami-
cally limited in that their emission rates are far below the levels which would prevail at equilib-
rium. Thus, the rate of formation of both thermal and fuel NOV is dominated by combustion condi-
A
tions and is amenable to suppression through combustion process modifications. Although the
mechanisms are different, both thermal and fuel NOX are promoted by rapid mixing of oxygen with the
fuel. Additionally, thermal NO is greatly increased by long residence time at high temperature.
The modified combustion conditions and control concepts which have been tried or suggested to combat
the formation mechanisms are as follows:
t Decrease primary flame zone 0~ level by
— Decreased overall Op level
— Controlled mixing of fuel and air
- Use of fuel rich primary flame zone
• Decrease time of exposure at high temperature by
- Decreased peak temperature:
— Decreased adiabatic flame temperature through dilution
- Decreased combustion intensity
— Increased flame cooling
- Controlled mixing of fuel and air or use of fuel rich primary flame zone
- Decreased primary flame zone residence time
• Chemically reduce NOX in post-flame region by
- Injection of reducing agent
Table 4-4 relates these control concepts to applicable combustion process modifications and
equipment types. The process modifications are further categorized according to their role in the
control development sequence: operational adjustments, hardware modifications of existing equipment
4-20
-------
TABLE 4-4. SUMMARY OF COMBUSTION PROCESS MODIFICATION CONCEPTS
Combustion
Conditions
Decrease
primary
flame zone
02 level
Decrease
peak
flame
temperature
Chemically
reduce NOX
in post-
flame region
Control
Concept
Decrease overall
02 level
Delayed mixing
of fuel and air
Increased fuel/
air mixing
Primary fuel-
rich flame
zone
Decrease
adiabatic flame
temperature
Decrease
combustion
intensity
Increased flame
zone cooling/
reduce residence
time
Inject reducing
agent
Applicable
Equipment
Boilers, furnaces
Boiler, furnaces
Gas turbines
Boilers,
furnaces, 1C
Boilers,
furnaces, 1C,
gas turbines
Boilers, furnaces
Boilers, furnaces
Boilers, furnaces
Effect on
Thermal NOX
Reduces 02-rich,
high-NOx pockets
in the flame
Flame cooling and
dilution during
delayed mix re-
duces peak temp.
Reduces local hot
stoichiometric
regions in over-
all fuel lean
combustion
Flame cooling in
low-02, low- temp.
primary zone re-
duces peak temp.
Direct suppres-
sion of thermal
NO mechanism
A
Increased flame
zone cooling
yields lower
peak temp.
Increased flame
zone cooling
yields lower
peak temp.
Decomposition
Effect on
Fuel NOX
Reduces exposure
of fuel nitrogen
intermediaries
to 0-
Volatile fuel N
reduces to N2 in
the absence of
oxygen
Increases
Volatile fuel N
reduces to N2 in
the absence of
oxygen
Ineffective
Minor direct
effect; indirect
effect on mixing
Ineffective
Decomposition
Primary Applicable Controls
Operational
Adjustments
Low excess air
firing
Burner
adjustments
Improved atomi-
zation
Burners out of
service; biased
burner firing
Reduced air
preheat
Load reduction
Burner tilt
Hardware
Modification
Flue gas recircu-
lation (FGR)
Low NOX burners
Overfire air
ports, stratified
charge
Water injection,
FGR
Ammonia injection
possible on some
units
Major
Redesign
Optimum burner/
firebox design
New can design;
premix, prevap.
Burner/firebox
design for two-
stage combustion
Enlarged firebox,
increased burner
spacing
Redesign heat
transfer sur-
faces, firebox
aerodynamics
Redesign convec-
tive section for
NH3 injection
-------
or through factory-Installed controls, and major redesigns of new equipment. The controls for de-
creased 02 are also generally effective for peak temperature reduction but have not been repeated.
The following subsections review the status of each of the applicable controls.
4.2.2 Low Excess Air Firing
Reducing the total amount of excess air supplied for combustion is an effective demonstrated
method for reducing NO emissions from utility and industrial boilers, residential and commercial
furnaces, warm air furnaces, and process furnaces. Low excess air (LEA) firing reduces the local
flame zone concentration of oxygen, thus reducing both thermal and fuel NOX formation. LEA firing
is easy to implement and increases efficiency. It is, therefore, used extensively in both new and
retrofit applications, either singly or in combination with other control measures. The ultimate
level of excess air is limited by the onset of smoke or carbon monoxide emissions which occurs when
excess air is reduced to levels far below the design conditions. Fouling and slagging may also in-
crease in heavy oil- or coal-fired applications at very low levels of excess air.
Low excess air firing is the most widespread NO control technique for utility boilers. This
technique was initially implemented to increase thermal efficiency and reduce stack gas opacity due
to acid mist. A number of studies have shown LEA firing to be effective in reducing NOX emissions
without significantly increasing CO or smoke levels (References 4-22, 4-32 through 4-47). The major
findings are summarized in Table 4-5.
Firing with excess air levels below 5 percent is now standard practice on many large oil- and
gas-fired boilers (Reference 4-32). Reductions in NOX levels average between 15 and 20 percent,
although reductions up to 30 percent for gas and 35 percent for oil-fired boilers have been reported
(References 4-34, 4-40). For tangentially-fired boilers, practical minimums of approximately 3 to
7 percent excess air for natural gas and oil firing are recommended. Operating at 10 percent higher
excess air than the minimum established will normally increase NO emissions by an average of 20
percent for all fuels in these units (Reference 4-38).
With coal-fired boilers, the minimum practical levels of excess air are higher than for oil
and gas. Typical values are 8 to 12 percent, but in some existing units, excess air levels below 15
to 18 percent present operating problems (Reference 4-35). For tangentially-fired units, minimum
levels of 18 to 25 percent are recommended (Reference 4-38). For both wall-fired and tangentially-
fired units, reductions from 12 to 20 ppm (0 percent 02 basis) for each percentage point reduction
in excess air level have been observed (References 4-35, 4-39, 4-40, and 4-44). The average reduc-
tion in NOX levels due to LEA is approximately 20 percent from baseline conditions. For one
4-22
-------
TABLE 4-5. SUMMARY OF RESULTS WITH LOW EXCESS AIR FIRING
Equipment Category/
Fuel
Utility boilers
Gas
Oil
Coal (except
cyclone
boilers)
Industrial water-
tube boilers
Gas
Oil
Coal
Control Method/
Range
Reduce EA to
2% to 5%
Reduce EA to
3% to 7%
Reduce EA to 20%
or lower
Similar to utility
boilers; same
degree of EA reduc-
tion not always
feasible
N0x
Reduction
Up to 30%
Avg =16%
Up to 35%
Avg =19%
Up to 30%
Avg =20%
Wide variations
reported. Ap-
proximately 5%
reduction in
NOX for each
one percent re-
duction in ex-
cess 02- Units
with preheated
air exhibit
greater reduc-
tions than units
with no preheat.
7% reduction NOX
for each one per-
cent reduction in
excess 02
12.5% reduction
in NOy for each
1% reduction in
excess 02
Effect On
Operation/
Maintenance
Flame instability
excess CO & HC
emissions may
occur
Above plus soot,
acid smut possible
Above plus slagging
and corrosion pos-
sible; carbon in
flyash may affect
ESP
Greater operator
surveillance re-
quired to assure
excessive CO & HC
emissions or flame
instability do not
occur
In addition to the
operational prob-
lem above, corro-
sion and slagging
are possible. May
reduce 503.
Efficiency/
Fuel Consumption
Up to 1%
increase
in efficiency
Up to 1.5%
increase
in efficiency
Efficiency in-
creases 0.1% per
1% decrease in
excess air
Extent
Used
Used in all ret-
rofit programs;
no new units be-
ing built
Widely used new
and retrofit
Increasing use for
conservation; in-
clude in new unit
design
R&D
Status
Retrofit develop-
ment to counter
operating
problems
Included as part
of all advanced
control designs
Include in R&D
on external con-
trols & low NOX
burners
(continued on p. 4-24)
-------
TABLE 4-5. Concluded
Equipment Category/
Fuel
Industrial firetube
boilers
Gas and oil
Residential warm
air furnaces
Gas and dis-
tillate oil
Internal combus-
tion engines
Gas, dual fuel
and diesel
Control Method/
Range
See industrial WT
and utility boilers
Ineffective in
existing units; EA
reduction from 80%
to 15% achieved in
new low NOX units
with combined NOX
controls
Leaner settings of
A/F ratio by either
reducing fuel input
(essentially de-
rating) or by
increasing the air
input (through in-
stallation or re-
placement of turbo-
charger)
NOX
Reduction
Approximately 5%
reductions NOX
per ]% reduction
in excess 02
No consistent
trend apparent.
Up to 10% reduc-
tions possible.
Reductions of
up to 4.5% NOX
for 1% decrease
in A/F ratio re-
ported. Turbo-
charged and gas-
fired units
show greatest
decreases.
Effect On
Operation/
Maintenance
See industrial
WT boilers
Possible increased
maintenance
frequency
None
Efficiency/
Fuel Consumption
Same as for in-
dustrial WT
boilers
Efficiency in-
creases by
0.1-0.15% per
one percent de-
crease in excess
air
Slight increase
in efficiency
Extent
Used
Prototype only
Increasing use in
new units
Not used;
prototype only
R&O
Status
Include in R&D on
low NOX burners
and external
controls
Development of
burners operat-
ing at lower
excess air
levels (see
Section 4.2.6)
Include in com-
bustion chamber
redesign
i
r\>
-------
turbo-fired unit tested, reductions of approximately 24 ppm for each 1 percent decrease 1n excess
air level were noted (Reference 4-35). Cyclone boilers are not well suited for NO control by LEA
firing. Excess air levels In cyclone boilers are restricted to a narrow operating range to prevent
corrosion and maintain furnace slagging conditions (References 4-41, 4-42).
The minimum practical level of excess air which can be achieved 1n existing boilers, without
encountering operational problems, depends upon factors in addition to the type of fuel fired.
These factors include low load operation, nonunlformity of air/fuel ratio, fuel and air control lags
during load swings, use of upward burner tilt to increase steam superheat (for tangentially-fired
boilers), and coal quality variation and ash slagging potential (for coal-fired boilers). They tend
to increase the minimum excess air level at which the boiler can operate safely.
Other factors such as secondary air register settings and steam temperature control flexibil-
ity also affect the excess air levels. The boiler combustion control system must be modified so
that the proportioning of fuel and air is adequate under all operating conditions. Uniform distri-
bution of fuel and air to all burners is increasingly important as excess air is lowered. Excess
air levels are also affected if other NO control techniques are employed. Off-stoichiometric
combustion and operating at reduced load increases the minimum excess air levels whereas switching
from eastern to western coals would decrease the levels (References 4-34, 4-44, and 4-48).
The excess air level setting of a utility boiler may be affected by considerations other than
the operating limit set by excessive smoke and CO emissions. The maximum plant efficiency does not
necessarily occur at the minimum excess air level (Reference 4-47). For example, problems with
slagging arise in lignite-fired boilers if excess oxygen drops below about 2.5 percent in the fur-
nace (Reference 4-49). In addition, certain high sulfur eastern coals may increase corrosion, if
the excess air is dropped to levels such that local reducing atmosphere pockets occur (Reference
4-50). Medium-term tests using corrosion coupons did not show significantly accelerated rates of
corrosion (Reference 4-35); long-term test results on actual furnace tubes are underway to clarify
the problem. New boilers are designed to overcome some of the operational problems associated with
LEA, making it possible to operate at lower levels of excess air.
LEA firing is a very effective method for controlling NOX in industrial boilers. Although
it is not in widespread use as a NOX control technique for industrial boilers, LEA is generally con-
sidered as part of an energy conservation program. NOX reductions of up to 44 percent of baseline
levels and efficiency increases up to 2.5 percent have been reported (Reference 4-51) using LEA
firing. But, it is usually not feasible to reduce the amount of excess air to the levels used in
4-25
-------
utility boilers, since industrial boilers are required to function automatically over wide variations
of load with a minimum of operator supervision.
The results of several studies on industrial and packaged boilers (References 4-45, 4-52, and
4-53) are summarized in Table 4-5. Coal-fired watertube boilers showed the largest and most consis-
tent drops in NOX levels, averaging 72 ppm (0 percent 02 basis) for each percent change in excess 02.
Residual oil-fired watertube boilers averaged 24 ppm reduction per 1 percent decrease in 02> while
distillate oil-fired boilers averaged about half that amount. In most cases, N0x decreased steadily as
excess CL was reduced. However, for equipment with premixed burners, the emissions first increase, and
then decrease when the level of excess air is reduced. For gas-fired watertube boilers, no consistent
reduction in NO with lowering of excess air is apparent, unless the combustion air is preheated. For
X
firetube boilers, an average reduction of 7 ppm for each 1 percent reduction in excess 02 was observed.
However, for baseline levels lower than 240 ppm, firetube boilers were not very sensitive to excess
02 levels.
LEA firing is used primarily in residential and commercial furnaces to increase the heater
efficiency, not to control NO . As excess air is decreased in a furnace, the CO, HC, and smoke
levels are minimized, whereas NO emissions are maximized. Normal operation of a furnace is usually
bounded by excessive CO levels at high values of excess air, and excessive smoke levels at low values
of excess air. However, since the furnace efficiency increases with decreasing excess air levels,
furnaces are usually tuned to operate at the lowest possible excess air supply for which the flue
smoke level is acceptable.
The minimum excess air levels for typical warm air furnaces vary widely, ranging from 20 to
80 percent. The change in NOX emissions from decreasing the excess air therefore varies.
Table 4-5 summarizes the results of studies on residential heaters (References 4-51, 4-54, 4-55,
and 4-56). The trend for warm air furnaces is towards developing burners which will operate at
lower values of excess air to reduce NOX emissions, while increasing efficiency. An optimum geom-
etry burner operating at about 15 percent excess air has been designed and tested (Reference 4-57).
Most existing furnaces, however, must operate at excess air levels much higher than 15 percent, as
the heat exchangers are not designed to withstand the flame temperatures resulting from very low
excess air firing (Reference 4-58). This is discussed further in Section 4.2.6.
Changes in air-to-fuel ratio can be used to control NOX in internal combustion (1C) engines.
NOX emissions are highest from 1C engines at air/fuel ratios slightly higher than stoichiometric.
4-26
-------
Decreasing the ratio towards fuel-rich conditions decreases NOX but sharply Increases CO and HC
emissions. Therefore, the most practical use of adjusting the air-to-fuel ratio Is to change the
setting towards leaner operation. Injection-type engines are best suited for this technique since
better control of the air-to-fuel ratio between cylinders would be necessary for carburetted en-
gines to approach lean limit operation. Reference 4-43 surveys the use of changes 1n the air-fuel
ratio as a NOX control technique for 1C engines; their findings are summarized in Table 4-5.
In gas turbines, the overall air-fuel ratio cannot be modified to control NO , since the
ratio is determined by the turbine Inlet temperature. However, local changes in the air-fuel ratio
may be employed to control NOX- This is discussed further in Section 4.2.6, Burner Modifications.
•Limited data are available on the effect of LEA on industrial process furnaces. In some
cases, the level of excess air may be dictated by process requirements (Reference 4-59). Data on
some gas and oil burners used in process furnaces show NO emission reductions of 2 to 3 percent
for each 1 percent decrease in excess air (References 4-60, 4-61). An EPA-IERL/RTP study was
recently completed to collect detailed information on NO control methods used in industrial process
furnaces (Reference 4-62).
In summary, changing the overall fuel-air ratio to control NO emissions is a simple, feasi-
ble, and effective technique for stationary sources of combustion, with the exception of gas turbine
engines. For certain applications such as utility boilers, LEA firing is presently considered a
routine operating procedure and is incorporated in all new units. Since it is efficient and easy
to implement, LEA firing will see increasing use in other applications. Most sources will require
additional control methods, in conjunction with LEA, to bring NO emissions within statutory limits.
In such cases, the extent to which excess air can be lowered will depend upon the other control
techniques employed. However, virtually all developmental programs for advanced N0x controls are
placing emphasis on operation at minimum levels of excess air. LEA will thus be an integral part of
nearly all combustion modification NO controls, both current and emerging, to be assessed in the
NOX E/A.
4.2.3 Flue Gas Recirculation
Recirculation of flue gas (FGR) or exhaust gas (EGR) is a proven NOX control technique in
which a quantity of combustion products are externally recycled into the primary combustion air.
The recirculated flue gas dilutes the reactants, reduces the attainable peak flame temperatures,
and reduces the local oxygen concentration, thereby lowering the amount of thermal NOX formed
(Reference 4-32). Table 4-6 summarizes the status and effectiveness of FGR as applied to stationary
source combustion equipment. Throughout this section, the amount of flue gas recirculation will
4-27
-------
TABLE 4-6. SUMMARY OF RESULTS WITH FLUE GAS RECIRCULATION
Equipment Category/
Fuel
Utility boilers
Gas
Oil
Coal
Industrial water-
tube boilers
Gas
Oil
Industrial fire-
tube boilers
Oil
•
Control Method/
Range
From 15% to 20%
recirculation of
flue gases to wind-
box; >50% used in
some cases; typi-
cally used with LEA
24% to 33% recircu-
lation of 'flue
gases with combus-
tion air in windbox
Up to 40% recircu-
lation of flue gas
in windbox
NOX
Reduction
Average about
50%
Up to 30%
Up to 15%
Up to 73%
reported
Up to 35%
reported
Up to 40%
Effect On
Operation/
Maintenance
Smoking excessive
vibrations, and
flame instability
occur at high re-
circulation rates
Flame instability
and blowouts at
high recircula-
tion rates
Flame instability
and blowouts at
high recircula-
tion rates
Efficiency/
Fuel Consumption
Small decrease
due to fan re-
quirement
None
None
Extent
Used
Widely used
retrofit; no new
units being built
Negligible
Prototype only
Prototype only
R&D
Status
Retrofit develop-
ment to combat
operational
problems
Inactive
Evaluation for new
unit design
Evaluation for new
unit design
A
I
-------
TABLE 4-6. Concluded
Equipment Category/
Fuel
Gas turbines
Gas
Oil
Internal combustion
engines
Gas
Dual fuel
Diesel
Control Method/
Range
Up to 26% recircu-
lation of exhaust
gas
Internal recircu-
lation by retard-
ing valve timing,
increasing back
pressure, or reduc-
ing scavenging in
2-stroke engines;
or external recir-
culation, up to 12%,
of exhaust gases to
the intake manifold
(preferably with in-
tercooling of ex-
haust gases)
NOX
Reduction
30% reported
38% reported
Up to 37%
reported
Up to 25%
reported
Up to 35%
reported
Effect On
Operation/
Maintenance
Efficiency/
Fuel Corns umpti on
Increased fouling
of valves and flow
passages, increased
smoke generation,
and contamination
of lubrication oil
possible
Increase in fuel
consumption from
1% up to 8%
reported
Extent
Used
Only on experi-
mental combustors
Only on experi-
mental engines
R&D
Status
Inactive; emphasis
on HgO injection,
can design
Inactive; emphasis
on chamber re-
design for new
units
-------
be defined as the weight fraction of recirculated flow relative to the total flow of incoming com-
bustion air plus fuel.
FGR is widely used in utility boilers burning natural gas, since natural gas combustion pro-
duces mainly thermal NO . However, since natural gas is becoming less available, utility boilers
A
have had to switch to oil. This has resulted in FGR becoming more prevalent in oil-fired units.
The prospect for FGR on new utility boilers appears unlikely, since no new large oil- or gas-fired
units are planned (Reference 4-63). Coal-fired units rarely use FGR for N0x control, and the pros-
pect of significant application of FGR to these units appears to be small. Recent tests, for example,
conducted on a utility boiler burning coal show that flue gas recirculation is ineffective in con-
trolling fuel NO (Reference 4-64).
With gas-fired units, NOV reductions of 50 to 70 percent were obtained with 10 to 15 percent
X
recirculation rates. About 45 percent NOX reduction was attained with oil-fired units, but only 15
percent NOV reduction was realized with one coal-fired unit, with flue gas recirculation rate of
A
about 15 percent.
Power boilers are usually designed for recirculation of a portion of the flue gases to con-
trol steam superheat temperatures. However, when this type of control is used, the flue gases are
injected into the bottom of the furnace to reduce the effectivenesss of the radiant section. This
procedurev however, is relatively ineffective in suppressing NO (Reference 4-65).
Retrofit addition of FGR involves addition of ductwork and recirculation fans to convey the
flue gas from a position upstream of the air preheater (344C, 650F) to mix with the preheated com-
bustion air. The specific modifications required and the operational results are very much depen-
dent on the unique characteristics of the boiler. On some units, high FGR rates have resulted in
serious operational problems (References 4-66, 4-67). Boiler vibration and flame instability have
resulted from the higher burner velocities and higher throughput in the furnace. On most units,
these problems have been successfully combatted through control development tests, usually involving
burner adjustments. The higher throughput in the furnace with FGR has also resulted in derating of
some units.
The few new oil and gas boilers designed with FGR have not encountered any operational problem
and have achieved excellent NOX reductions (Reference 4-47). When combined with other control
methods such as off-stoichiometric combustion, FGR has been effective with limited recirculation rates.
4-30
-------
FGR has been tried only experimentally on Industrial boilers (References 4-53, 4-68). Recent
tests performed on Industrial boilers show that FGR 1s very effective 1n suppressing NO for gas-
A
fired units. Mixed results were obtained when FGR was used on oil-fired watertube boilers. In one
case, NOX reductions of 35 percent were obtained with 24 percent recirculation (Reference 4-53);
and in another case, only a small (0 to 3 percent) amount of reduction was achieved (Reference 4-68).
Both the boilers experienced flame instability at recirculation rates above 25 to 27 percent.
FGR was found to be effective in the case of an oil-fired firetube boiler; approximately 30
percent NOX reduction was obtained with 40 percent recirculation (Reference 4-68). This result in-
dicates that effectiveness of FGR in suppressing NOX emissions was dependent upon boiler type.
Only a few experiments have been conducted on gas turbines with exhaust gas recirculation
(EGR). Tests performed on a one-half scale combustor show that NOX reductions of 38 percent for
oil and 30 percent for gas were achieved, with an exhaust gas recirculation rate of 26 percent. No
adverse effects due to EGR were detected on hydrocarbon and carbon monoxide emissions. The tests
are not conclusive, however. For oil-fired units, at combustor exit temperatures below 1500F, emis-
sions are greater with EGR than with no exhaust gas recirculation. However, for gas-fired units,
EGR reduces NO emissions for the entire range of combustor exit temperature (Reference 4-69). EGR
is not being actively pursued in the low-NO gas turbine combustor development programs.
A
On 1C engines, EGR can be accomplished by either recycling exhaust gases into the intake
manifold (external EGR) or by restricting the discharge of gases that would normally be exhausted
from the cylinder (internal EGR). Externally recirculated gases can also be cooled before they are
reintroduced into the cylinder (Reference 4-43).
The only data available on the use of cooled, external EGR in large bore engines were for a
two-stroke blower scavenged test engine. The use of 20 percent cooled EGR at rated conditions re-
sulted in a 55 percent NOX reduction and an increase in smoke to 17 percent opacity. HG emissions
were unchanged and CO emissions increased 72 percent. By comparison, 20 percent hot EGR resulted
in NO reductions of 51 percent at rated conditions and smoke increases to 27.5 percent opacity. HC
emissions were reduced 17 percent and CO emissions were increased 167 percent. Similar trends were
reported on tests of cooled EGR on truck-sized engines.
Internal EGR is available for both two- and four-stroke engines, either naturally-aspirated
or turbocharged. It can be used with turbocharged models, due to their leaner operation. Some of
the operational problems encountered include severe fuel penalties, engine starting difficulties,
4-31
-------
and increased smoke generation. The primary maintenance problem with E6R systems is that solid ex-
haust products accumulate in the recirculating system. This problem is more acute for diesel en-
gines. When EGR is applied to naturally-aspirated engines, the deposits build up in the ducts or
the valves used to control the recirculation rate, and may build up on the intake valves.
EGR has only been tried experimentally for internal combustion engines; it has not been pur-
sued further because of operational/maintenance problems and the absence of regulations to limit NO
emissions from these sources.
Tests conducted on a prototype residential oil burner fired at 1 ml/s (0.951 gph) showed FGR
to yield NO reductions comparable to burner modifications (Reference 4-56). NOX emission rates of
0.58 g/kg fuel, compared to 2 to 3 g/kg fuel uncontrolled, resulted with 30 percent FGR. FGR has
not been pursued for residential systems, however, since burner modifications have proven simple
and less expensive for a comparable level of control (Reference 4-57).
In summary, the primary near-term application of FGR is in gas- and oil-fired utility boilers.
Emerging applications are limited. FGR may see use in industrial boilers on a retrofit or new design
basis, but alternate approaches, e.g., low-NOx burners, off-stoichiometric combustion, are also
being evaluated and may prove more attractive. Other techniques are more effective for coal-fired
utility boilers, gas turbines and warm air furnaces. The effectiveness of FGR with process furnaces
is under evaluation.
4.2.4 Off-Stoichiometric Combustion
Off-Stoichiometric Combustion (OSC) is a NO control technique in which the mixing of fuel
with combustion air is controlled by the use of overfire air (OFA) ports, firing with some burners
out-of-service (BOOS), or biased firing. Generally, substoichiometric conditions prevail locally
in the primary combustion zone; complete combustion occurs downstream of the burners. OSC reduces
both thermal and fuel NOX- Lowering the availability of oxygen in the primary flame zone inhibits
fuel nitrogen conversion, while interstage cooling by flame radiative transfer reduces peak tempera-
tures, which, coupled with the reduced availability of oxygen, decreases the production of thermal NO .
OSC is a fairly common method of NOX control for utility and large industrial boilers. It
is usually implemented after simpler techniques, such as low excess air firing, fail to reduce NO
X
levels below statutory requirements. Most large boilers, commissioned after 1971 are equipped with
OFA ports. Older boilers with multiple burners can be adapted to OSC by biased firing, i.e., firing
some burners fuel-rich and others air-rich, or by taking some burners out of service, i.e., oper-
ating them on air only. Operating on air only, however, may result in a derating of the units if
4-32
-------
the active burners or fuel delivery system do not have the capacity to carry the extra fuel re-
quired to maintain full load.
Utility boilers have been tested extensively with OSC (References 4-24, 4-32 through 4-41,
4.44, 4-47, 4-49, 4-63, 4-64, 4-70 through 4-79). Results are summarized in Table 4-7. Gas-fired
boilers show the greatest reductions in NOX, with maximum reductions of approximately 70 percent
achieved with BOOS firing on one wall-fired and one tangentially-fired unit (References 4-33, 4-37).
Typical reductions for gas-fired utility boilers are around 45 to 50 percent (References 4-37, 4-40,
4-73). Oil-fired boilers are less responsive to OSC, with normal decreases in NO levels between
25 and 35 percent, although a 55 percent reduction has been reported for one tangentially-fired
unit with BOOS firing (References 4-33, 4-37, 4-40, 4-73, 4-74). For coal-fired boilers operated
with BOOS firing, most NOX reductions fall between 30 to 40 percent, with 50 percent or over
achieved in a few cases (References 4-35, 4-37, 4-40, 4-41, 4-44, 4-64, 4-73, 4-75).
Recently some tests have been performed on tangential coal-fired boilers equipped with OFA
ports. NOX levels decreased by 20 to 30 percent when approximately 15 percent of the total combus-
tion air was diverted through the OFA ports (References 4-24, 4-39). A preliminary report on
western coals fired in tangential units, with 95 to 100 percent stoichiometric air at the burners,
showed up to 30 percent reduction in NOX emissions (Reference 4-76). Similarly, both wall-fired
and tangential boilers firing lignite decreased NO emissions by about 30 percent when the air at
the burners was reduced to approximately 95 percent of stoichiometric (Reference 4-49).
In other tests, a coal-fired Turbofurnace was tested with a few burners near the ends of each
row operated on air only. NO reductions of up to 10 percent resulted when the air to active burners
was reduced to 80 percent of stoichiometric (Reference 4-35). However, an attempt at firing one
coal-fired cyclone boiler off-stoichiometrically by operating the upper cyclones under fuel-lean
conditions did not reduce NO emissions (Reference 4-41). A similar attempt with an oil-fired
X
cyclone boiler, with the upper cyclones operated on air only and with an increase in fuel supply to
the lower cyclones to maintain load, actually increased N0x emissions by 50 percent (Reference 4-40).
OSC presents a number of potential operational problems when applied to existing units. As
mentioned earlier, if a unit does not have OFA ports, firing with BOOS can cause derating, especially
in older coal-fired units with limited pulverizer capacities. The best BOOS firing pattern for
N0x reduction must be determined empirically for an individual boiler. In general, air-only burners
in the top row give the best results; this configuration most closely simulates overfire air injec-
tion and, hence, two-stage combustion. In tests on two wall-fired oil units, with four rows
of burners and OFA ports, the optimum firing pattern was to have the third row from the bottom
4-33
-------
TABLE 4-7. SUMMARY OF RESULTS WITH OFF-STOICHIOMETRIC COMBUSTION
Equipment Category/
Fuel
Utility boilers
Gas
Oil
Coal
Industrial boilers
Gas
Oil
Coal
Control Method/
Range
Reduce oxygen level
in primary flame
zone by firing some
or all burners fuel-
rich at about 85% to
95% theoretical air.
Remaining 15% to 25%
of total combustion
air supplied
through OFA ports,
BOOS, or biased
burners; typically
used with LEA.
Similar to that
for utility
boiler
NOX
Reduction
Average between
45% and 50%
Normally between
25% and 35%
Normally between
30% and 40%
Up to 55%
reported
Up to 50%
possible
Up to 39%
reported
Effect On
Operation/
Maintenance
Load curtailment,
flame instability
boiler vibrations,
and excessive CO
and smoke emis-
sions may occur
with retrofit use
In addition to
above, corrosion
and slagging prob-
lems may arise
Similar to those
for utility boilers
for retrofit use
Efficiency/
Fuel Consumption
Generally little
or no adverse
effect
None in new
units; possible
1% decrease with
retrofit
Decrease in
efficiency up
to 3% to 4%
possible
Maximum decrease
of 1% reported
Decreases up to
2% reported
Extent
Used
Retrofit use on
over 100 boilers
in the U.S.;
usage increasing
Inclusion in most
new unit designs
(OFA)
Prototype only
R&D
Status
Retrofit develop-
ment to combat
operational
probl ems
Evaluate corro-
sion potential
(near term);
advanced stag-
ing concepts
(long term)
Evaluation for
new unit design
-------
firing air only. In these tests, OFA ports used alone resulted In much lower NOX reductions. But,
using the combination of BOOS and OFA firing did not result 1n significant reductions from using
BOOS alone (Reference 4-74).
Fewer BOOS patterns are available for staging with coal-fired boilers, since 1t usually is
not possible to close off Individual coal burners from a pulverizer. Thus, all burners fed by a
pulverizer are either active or on air only. In some coal-fired boiler tests where it has been
possible to vary BOOS patterns systematically, burners firing air only on the top rows and on the
outer edges of the burner matrix (for wall-fired units) tend to be most effective in reducing NO
emissions at full load (References 4-36, 4-39, 4-44, 4-64). At reduced loads it is not possible
to generalize which BOOS patterns result in greatest reductions. In one test, at very low load,
all BOOS firing patterns tested increased NOX emissions. This increase is attributed to the in-
creasing levels of excess air required with decreasing load, that make it impossible to achieve
substoichiometric conditions under any combination of BOOS (Reference 4-44).
In most of the tests reported, NOX emissions decrease steadily as the stoichiometric air to
active burners is reduced. Excessive smoke and CO levels generally limit the extent to which the
burners are fired fuel rich. The fuel-rich conditions can lead to flame instability, and for coal-
fired boilers, the reducing atmosphere in the primary combustion zone can accelerate tube corrosion
and slagging (Reference 4-50).
Two utility companies have recently reported operational experience with combined OSC and
FGR for gas- and oil-fired boilers (References 4-34, 4-74). Problems encountered included flame in-
stability, boiler vibrations, load curtailment, restricted boiler load response capability, tube
failures and stack smoking conditions. Another utility company reported experience with retrofit
biased firing on a coal-fired boiler; problems reported included increased carbon losses, decreased
boiler efficiency of about one percentage point at all load levels and possible increased tube
wastage on the sidewall near the biased burners (Reference 4-44). The IERL/RTP is conducting long-
term field tests to accurately determine the effect of OSC on tube wastage. Corrective measures to
suppress tube wastage are also being examined. One utility boiler manufacturer uses a "curtain air"
oxidizing atmosphere at the tube walls to suppress wastage and control slagging (Reference 4-75).
Few existing industrial boilers have off-stoichiometric firing capability, since most smaller
units have only one or two burners and do not come equipped with OFA ports. Large industrial boilers
have multiple burner assemblies which can be operated with BOOS firing, although this usually results
in a derating of the unit.
4-35
-------
In actual field tests on a number of Industrial watertube boilers (References 4-53, 4-80),
BOOS firing .achieved maximum reductions in NOX emissions of up to 55 percent for gas-fired boilers,
31 percent for oil-fired boilers, and 39 percent for coal-fired boilers. These tests showed that
in many cases the overall excess air levels had to be increased during BOOS firing to prevent smok-
ing. In addition, a square burner pattern proved more effective than a staggered pattern. And,
removing inner burners in the top row was more effective than other burner changes in controlling
NO emissions. Some tests with OSC were also performed on stoker-fired coal units equipped with
A
air ports, or with auxiliary oil or gas burners which could be fired with air only located above the
grate. With these units, NO reductions of up to 26 percent were reported. However, OSC is not
A
effective in cases where baseline NOV levels are already low (Reference 4-53).
A
Most small to medium size watertube boilers and all firetube units do not have multiple bur-
ners and therefore cannot be'fired using BOOS or biased firing. These units can be fired off-
stoichiometrically only by installing overfire or side fire air ports. Recent experimental results
are available on single burner, oil- and gas-fired, watertube and firetube industrial boilers
equipped with hardware modifications to allow for injection of air downstream of the burner (Refer-
ences 4-52, 4-53). These results are mixed, although NO reductions up to 50 percent were reported
for oil- and gas-firing in one watertube unit with side fire air injection. In two cases of gas-fired
units (a watertube and a firetube boiler), no significant reductions in NOX were obtained with OSC.
Moreover, in the firetube boiler, there was an obvious minimum burner stoichiometry; NO levels
reached a minimum before rising again as the stoichiometric air to the burner was decreased. This
behavior is contrary to the behavior of utility boilers and may be due to low-burner momentum under
OSC inhibiting fuel-air mixing close to the burner.
Operational problems with OSC in industrial boilers are not well documented but are expected
to be similar to the problems experienced in utility boilers. Some of the problems may never occur
since higher levels of excess air are used in industrial boilers than in utility boilers, and the
overall excess air levels increase with OSC. However, increasing the excess air level generally
decreases efficiency. But, in some tests the reductions in efficiency were usually less than 1 per-
cent (Reference 4-53). In experiments where overall excess air was carefully controlled, a slight
increase in efficiency resulted (Reference 4-52).
*
In summary, off-stoichiometric combustion is a widely used, demonstrated technique for control
of thermal and fuel NO from large boilers. Near-term applications to be considered in the NO E/A
A x
include retrofit use on gas-, oil- and coal-fired utility boilers and use of factory-installed con-
trols on new coal-fired utility boilers. Potential emerging applications to be considered include
4-36
-------
use of factory-installed controls on new Industrial boilers and use of advanced staging techniques
for major redesign of utility or industrial boilers.
4.2.5 Load Reduction
Thermal NOX formation generally increases as the volumetric heat release rate or combustion
intensity increases. Reduced combustion intensity can be brought about by load reduction, or
derating, in existing units and by use of an enlarged firebox in new units. The reduced heat re-
lease rate lowers the bulk gas temperature* in nonadiabatic furnaces such as boilers. Lower bulk
gas temperature in turn, significantly decreases NOX emissions (Reference 4-71).
The heat release rate per unit volume is generally independent of unit rated power output.
However, the ratio of primary flame zone heat release to heat removal increases as the unit capacity
is increased. This causes NOX emissions for large units to be generally greater than for small
units of similar design, firing characteristics, and fuel.
The increase in NOX emissions with increased capacity is especially evident for gas-fired
boilers, since total NO emissions are due to thermal NO . However, coal-fired and oil-fired units
A A
behave differently with regard to changes in volumetric heat release rates. Up to 80 percent of the
NO from coal-fired boilers is attributed to fuel nitrogen conversion, so thermal effects associated
with volumetric heat release rates have little overall effect. Load reduction can strongly affect
firebox aerodynamics, however, and consequently affect fuel NO emissions. Table 4-8 summarizes
field experience with load reduction for NO control.
During numerous field test programs, load reductions on gas- and oil-fired utility boilers
reduced NOX emissions by 10 to 55 percent for load reductions of 18 to 55 percent of maximum rated
capacity. Gas-fired boilers showed the highest reduction, followed by oil- and coal-fired units
(References 4-35, 4-36, 4-37, 4-40, 4-81).
A field study of industrial boilers (References 4-53, 4-80) reported that the decreased N0x
emissions resulting from load reduction were somewhat offset by the increase in excess air required
for firing at the reduced load. The increased excess air was necessary to prevent CO and smoke
emissions which were promoted at the reduced load condition. NOX emissions did not change at the
lower firing rates. However, watertube gas-fired boilers equipped with air preheaters showed a re-
duction in NOX emissions with load reduction caused by a combination of low air preheat temperatures
*Bulk gas temperatures are also affected locally by circulation patterns and the proximity of cold
surfaces.
4-37
-------
TABLE 4-8. SUMMARY OF RESULTS WITH LOAD REDUCTION
Equipment Category/
Fuel
Utility boilers
Gas
Oil
Coal
Industrial water-
tube boilers
Gas
Oil
Coal
Industrial fire-
tube boilers
Gas
Oil
Control Method/
Range
In existing units
reduce load up to
about 50% by de-
creasing fuel and
air supply to all
burners, or termi-
nating fuel and
air altogether to
some burners. In
new units, lower
volumetric heat re-
lease rates achieved
by up to 30% larger
furnace dimensions.
Reduce load by up to
fuel and air supply
to al 1 burners or
terminating fuel
supply to some
burners
Reduce load up to
80% by reducing fuel
and air supply to
burner
NOX
Reduction
About 50%
25% to 40%
10% to 25%
Up to 30%
Up to 20%
Up to 10%
Up to 20%
Up to 15%
Effect On
Operation/
Maintenance
Increased soot de-
posits necessitate
more frequent use
of soot blowers.
Operational prob-
lems with control
of steam tempera-
ture at reduced
load.
Increased soot de-
posits necessitate
more frequent use
of soot blowers.
Operational prob-
lems with control
of steam tempera-
ture at reduced
load.
Efficiency/
Fuel Consumption
Decrease in
efficiency due
to associated
increase in ex-
cess air levels
at low load
operation
Decrease in
efficiency due
to associated
increase in ex-
cess air levels
at low load
operation
Decrease in
efficiency at
reduced loads
Extent
Used
Limited use for
trimming to
meet standards
Enlarged firebox
routinely used in
new units
Not used for
NOV control
X
Not used for
NO control
R&D
Status
Inactive
Evaluate optimum
heat release rate
for advanced
designs
Evaluate optimum
heat release rate
for use with ex-
ternal controls
or new burners
Evaluate optimum
heat release rate
for use with ex-
ternal controls
or new burners
a
ir
i
i-
I
u>
oo
-------
TABLE 4-8. Concluded
Equipment Category/
Fuel
Internal combustion
engines
Gas
Dual fuel
Diesel
Gas turbines
Gas and oil
Control Method/
Range
Adjust throttle or
governor setting
to restrict engine
power output in ex-
isting engines, or
equip new engines
with smaller capac-
ity pump or
carburetor
Reduce fuel flow
to combustors
N0x
Reducti on
0.25% to 0.922
per 1 percent
derate
Up to 0.94% per
1 percent derate
0.17% to 0.92%
per 1 percent
derate
10% to 20%
Effect On
Operation/
Maintenance
Increase in HC
and CO emissions
Increase CO and
smoke due to
flame quench
Efficiency/
Fuel Consumption
About 10% in-
crease in bsfc
Results in in-
creased fuel
consumption
Extent
Used
Not used for
N0x control
None at present
R&D
Status
Inactive
Evaluate optimum
can heat release
rate for dry
controls
-------
and poor fuel-air mixing. NOV reductions of about 20 percent were obtained as the firing rate was
A
dropped to 50 percent of capacity.
Load reduction can lead to operational problems apart from the obvious drawback of limiting
capacity. Higher levels of excess air are typically required to suppress CO or smoke emissions thus
leading to an overall reduction in efficiency. The increased residence time of the combustion gases
at the reduced load can cause steam temperature imbalance in the convective section. Higher excess
air or flue gas recirculation may be needed to maintain superheat temperatures. Also, operation at
greatly reduced load may exceed the practical turndown limit of the burners. Some burners may need
to be taken out of service to maintain good firebox mixing and steam temperature control.
Most of the above problems can be avoided when the unit is designed to operate at low com-
bustion intensity. Here, the use of enlarged fireboxes on new units produces NOX reductions similar
to load reduction on existing units. Some of the last gas- and oil-fired utility boilers sold were
equipped with enlarged fireboxes. New coal-fired utility boilers use fireboxes typically 30 percent
larger than was the practice in the 1960's (Reference 4-63). This practice is partly in response to
the New Source Performance Standards set in 1971 and partly to facilitate combustion of lower grade
western coals. As mentioned earlier, the NOX reduction with coal-firing due to an enlarged firebox
is largely indirect through the change in firebox aerodynamics.
Figure 4-5 shows a dramatic example of the effectiveness of enlarged firebox, or load reduc-
tion, in combination with other techniques (Reference 4-47). The Scattergood No. 3 unit of the
Los Angeles Department of Water and Power uses a firebox rated at an electrical output of 460 MW but
was converted during construction to fire at about 315 MW to meet the stringent Rule 67 emission
standard in effect when the boiler went online. With natural gas firing, operation at the reduced
load in combination with burners out of service and massive FGR yielded emission levels below 35 ppm.
Load reduction in internal combustion (1C) engines reduces cylinder pressure and temperatures
and thus lowers NOX formation rates. However, although NOX exhaust concentrations (i.e., moles of
NOX per mole of exhaust) are reduced, it is possible the reductions will be no greater than the de-
crease in power. In such a case, brake specific emissions (i.e., grams NO per horsepower-hour) are
not reduced, especially in four-stroke turbocharged engines.
NOX emission reductions due to derating were reported for a variety of engine types, fuels,
and percentages of derate in Reference 4-43. The reductions achieved ranged from 0.45 to 4.17 ug/J
(1.2 to 11.2 g/hp-hr) for naturally-aspirated or blower scavenged engines and from 0.07 to 3.28 vig/0
(0.2 to 8.8 g/hp-hr) for turbocharged units. Since these results were obtained with varying amounts
4-40
-------
120
100
o
<*>
n
<
ui
80
^
§ 60
CO
s:
Q.
Q_
20
Nitric Oxide Limit for
Compliance with LA/APCD
Rule 67
/
0
Upper 4 Burners Out of Service
or Overfire Air Ports Open and
Upper 2 Burners Out (33% Off-
StoichioAmetric)
'30%
03
Gas Recirculation Only
•Test Data 1975
Mw
295
355
ppm
25
33
Recirc 50%
72%
•Combined 33% Off-Stoichiometric Combustion
and Gas Recirculation
I
L
1
100
200
300
LOAD. MW
400
530
530
Figure 4-5. Operating results of Scattergood unit No. 3 of LADWP;
nitric oxide emissions below 35 ppm (Reference 4-47).
4-41
-------
of derating, it is more informative to compare the effectiveness of this emission control technique
on a normalized basis - i.e., percent NOX reduction per percent derate. On this basis the results
for naturally-aspirated or blower scavenged engines varied from 0.25 to 6.2 whereas those for turbo-
charged units varied from 0.01 to 2.6. No relationship was found between normalized effectiveness
and uncontrolled emission level, number of strokes per cycle, or fuel.
Derating an engine does not require additional equipment, and the only operating adjustment
is to the throttle or governor setting to restrict engine power output. However, there are some
problems associated with engine derating that reduce the attractiveness of this NOX reduction tech-
nique. When derated, the engine's efficiency is reduced, and therefore, the fuel consumption is in-
creased. For example, the data reported in Reference 4-43 showed an increase in brake specific fuel
consumption (BSFC) that ranged from 1.1 to 9.6 percent for the large bore engines investigated.
Moreover, a derated engine must be a bigger, more expensive unit to satisfy a given power
requirement. In addition, the lower temperature associated with derating an 1C engine increases
HC and CO emissions, because the temperature-dependent reactions that reduce these pollutants are
less active.
Derating a gas turbine reduces the primary flame zone temperature and increases the residence
time of the hot product gases. At a constant compressor speed, gases are cooled more at lower loads,
since more excess air is available for diluting. This dilution produces lower NOV formation. As
X
the residence time of the hot product gases in the combustor is increased, the production of NOX may
increase however.
Data on the exact effect of residence time on NOX emissions from a given gas turbine are
scarce, primarily because other variables (such as mass flowrate) change with a change in residence
time. Available data (References 4-69, 4-82), however, indicate that increased residence time
(which is inversely proportional to air flow) increases NO emissions.
A
In summary, the primary near-term applications of load reduction/enlarged firebox are for
retrofit of gas- and oil-fired utility boilers and new design of coal-fired utility boilers. Addi-
tionally, there may be application to new and existing industrial boilers as standards are set for
these units. Load reduction for existing units is unattractive due to economic and operational
penalties. Its use is thus avoided except as a last resort to achieve compliance with standards.
4.2.6 Burner Modifications
Burner or combustor modification for NOX control is applicable to all stationary combustion
equipment categories. With the possible exception of internal combustion engines, modified burners
4-42
-------
or combustion chambers can be retrofitted onto most existing units. Almost all burner modifications
use some form of 1n-flame LEA, OSC, or FGR to reduce NO emissions.
For boilers and furnaces, a number of burner parameters affect NOX emissions. These include
the geometry of the burner and fuel injection system, the method of fuel injection, the velocity
and degree of swirl of the combustion air, and the division of the total air between primary, second-
ary and teriary streams (References 4-16, 4-77, 4-83, 4-84, 4-85). The effect of most parameters
depends upon the type of fuel used. Optimizing these parameters and developing burner design
criteria have been the subjects of recent research efforts (References 4-25, 4-60, 4-86); a summary
of the results is given in Table 4-9.
For boilers and furnaces fired with natural gas, burner parameters which reduce peak and
average flame temperatures produce the least NOX emissions (References 4-85, 4-86). Entrainment of
cooler gases from the recirculating zones into the primary combustion zone is generally desirable.
However, since secondary recirculation patterns may vary considerably (depending on the geometry of
the furnace), burner parameters which reduce NOV in one furnace may increase NOV levels in another
A X
(Reference 4-86).
Nevertheless, several low-NO burners have been developed for industrial furnaces, including
some unconventional Japanese designs (References 4-61, 4-86). Full scale test results show reduc-
tions in NOX emissions from 40 to 60 percent. Subscale tests with single burners of the type nor-
mally used in utility boilers have indicated that simple changes in burner block and nozzle geometry
and in swirl vane angles can decrease NO production by up to 55 percent (Reference 4-60).
X
On oil-fired boilers and furnaces, a number of modifications are possible for low-NOx burners.
The simplest modification varies the primary to secondary air ratio, swirl level, and atomization
pressure on conventional burners. In tests on a simulated package boiler, decreases in NOX emis-
sions from about 10 to 30 percent resulted when each of the above parameters was varied individually
(Reference 4-61). The reductions are caused by changes in flame shape and flow field which produce
fuel-rich regions and dilution of air with combusted products.
Several low-NOx burners with modified air and. fuel injection techniques have recently been
developed in Japan (References 4-61, 4-87, 4-88, 4-89). Some of the more innovative methods include:
flame-splitting distributor tips which cause a flower petal flame arrangement, and atomizers with
fuel injection holes of different diameters which create fuel-rich and fuel-lean combustion zones
(References 4-25, 4-61, 4-88). Up to 55 percent reductions in NOX emissions are reported with the
use of these nozzle tips. However, the change in flame shape may cause problems due to impingement
on walls and effectiveness may belreduced as flames interact in multiburner furnaces.
4-43
-------
TABLE 4-9. SUMMARY OF RESULTS WITH BURNER MODIFICATIONS
Equipment Category/
Fuel
Utility boilers
Gas
Oil
Coal
Industrial boilers
Gas and oil
Residential and
conmercial furnaces
Oil
Control Method/
Range
Control mixing of
fuel and air at
burner to decrease
flame temp., inter-
nally recirculate
combustion gases,
and/or reduce avail-
ability of oxygen
in primary flame
zone for fuel NO
control ; burner mods
allow greater flex-
ibility with other
controls
Same as for utility
boilers
Optimum burner/
firebox design
using controlled
fuel -air mixing,
internal recircu-
lation and con-
trolled heat trans-
fer for lower
flame temperature
NOX
Reduction
Up to 55% in
single burner
experimental
furnace
About 40% to
55% in single
burner furnaces
35% in field test
on multi burner
furnace
20% to 45%
reported
About 50%
reported
Effect On
Operation/
Maintenance
Flame impingement
on walls possible
with certain bur-
ner types. Soot
emissions may
increase at low ex-
cess air levels.
As above
None
Efficiency/
Fuel Consumption
Associated use
of LEA yields
higher
efficiency
As above
Associated
use of LEA
yields higher
efficiency
Extent
Used
Limited retrofit
use; burner mods
routinely used to
allow use of other
mods (FGR, OSC)
Inclusion in new
unit design; lim-
ited retrofit use
Prototype unit
Field
demonstrations
R&D
Status
Development, test-
ing and commerciali-
zation of low NOX
burner
Develop advanced
low NOX burner
for new units
Approaching com-
mercialization;
advanced low NO
burners under
development
Approaching com-
mercialization
optimum burner/
firebox designs
n
VO
i
-------
TABLE 4-9. Concluded
Equipment Category/
Fuel
Internal combustion
engines
Gas and
diesel fuel
Gas turbines,
gas, kerosene
and diesel oil
Combustion Method/
range
Staged combustion by
fuel rich burning in
antechamber, prior
to completion of
combustion at lower
temperatures in
main chamber
Dry controls through
new can design; pre-
mix, prevap lean pri-
mary zone, controlled
dilution
NOX
Reduction
Approximately 60%
Normal range
Effect On
Operation/
Mai ntenance
None
None
Efficiency/
Fuel Consumption
Fuel consumption
increased by 5%
to 8% in one
design
Possible im-
proved effi-
ciency at
power loads
Extent
Used
None at present
None at present
R&D
Status
Evaluation for
new unit design
Extensive de-
velopment and
testing of ad-
vanced combustor
concepts
I
*.
Ul
-------
Other fuel-air modifications include a low-NOx burner (offered by at least one company in
the U.S.) for oil- and gas-fired package boilers. This burner uses shaped fuel injection ports and
controlled air-fuel mixing to create a thin stubby ring-shaped flame (References 4-61, 4-87). With
this modification, reductions in NO from 20 to 50 percent are claimed. The most extensive air-
fuel modifications involve the self-recirculating and staged combustion chamber type of burners,
used in industrial process furnaces. These burners are equipped with a prevaporization or a precom-
bustion chamber in the windbox. In the chamber, the fuel is vaporized and premixed with part of
the combustion air, or is allowed to undergo partial combustion under oxygen deficient conditions
before being discharged into the furnace. NO reductions of about 55 percent are typical of these
devices.
On pulverized coal burners, experiments have shown that the amount of NOX produced in turbu-
lent diffusion flames is strongly dependent on fuel-air mixing. High velocity axial injection of
fuel delays fuel-air mixing in the central core region of the flame; this produces local off-
stoichiometric conditions which inhibit NOX production. However, the length of the flame produced
by this method is generally unacceptable for use in existing boiler configurations (References 4-83,
4-84).
To reduce NOX emissions without altering the flame form, a triple concentric burner design
with tertiary air supply has been suggested. In subscale tests, NOX reductions of about 33 to 67
percent have resulted from injecting 50 percent of the total mass of air through the tertiary ports
(Reference 4-25).
One major utility boiler manufacturer has recently fabricated and tested a similar dual reg-
ister pulverized coal burner, designed to produce a limited turbulence, controlled diffusion flame.
The manufacturer claims NOX reductions of 50 percent (Reference 4-90). In field tests, an existing
boiler equipped with the new burners generated 35 percent less NO than an identical unit operating
under similar conditions with old burners (Reference 4-36).
Another major manufacturer also plans to install its own version of a dual register, divided
air stream burner in all its new units. The manufacturer claims that the new burners and a new
furnace design (which increases burner spacing and reduces the volumetric heat release rate) will
reduce NOX emissions by 47 percent, when compared to emissions from older units (Reference 4-91).
Burner spacing and location have an important effect on NO production, although little
quantitative data are available. Closer burner spacing increases interaction between adjacent
flames and reduces the ability to radiate to cooling surfaces. In most new utility boiler designs,
4-46
-------
the spacing between burners has been extended. Future work 1s'planned to study the influence of
burner-burner and burner-furnace interactions (Reference 4-25).
Oil-fired burners used in residential heaters and furnaces have been investigated recently,
and optimum burner and system design criteria have been established (References 4-55 to 4-58, 4-91,
4-92). For most burners with refractory-lined combustion chambers, local recirculation increased
NO emissions. It was also found that for water-cooled and air-cooled combustion chambers (which
characteristically have lower N0x emissions), entrainment from the external recirculation zone, which
has a chance to dissipate heat to the cold walls, is beneficial. Flame retention devices were, how-
ever, found to be detrimental for both types of combustion chambers. In addition, choke diameter
dimensions as a function of fuel flowrates and optimum swirler vane angles were determined. Two
burners based on these criteria were constructed, and their measured NO emissions were found to be
approximately 50 percent lower than conventional burners operating under similar conditions.
In internal combustion engines, the combustion process can be improved by:
• Predesigning chamber geometries to increase turbulence, as in high swirl engines
0 Staging, as in engines with stratified charge, precombustion chambers, or piston heat
cavities
• Using a combination of both, as with "squish lip" piston heads (Reference 4-43)
In high swirl units, the improved mixing promotes rapid, early combustion which causes high
temperatures for a long period of time. Delayed ignition can then be used to reduce peak tempera-
tures below the temperatures at which NOX forms, with less production of unburned hydrocarbons and
smoke. No data are available to compare NO emissions from a high swirl unit with those from a
conventional engine when both are retarded as far as possible.
When staged combustion is used, the fuel charge is introduced into a cavity as a rich mixture
and then ignited in an oxygen-deficient environment which inhibits NOX formation. This combusting
mixture then expands into the main chamber where it mixes with additional air at reduced temperatures
which are adequate for combustion, but below those required for NOX formation. Reduced temperatures
may, however, reduce the engine efficiency; the results are summarized in Table 4-9.
"Squish lip" designs appear to reduce NOX emission both by aerodynamic effects and staged
combustion. The vertical flow pattern created recirculates burned gases through the combustion zone
within the piston head cavity, thus incorporating a form of internal EGR. A summary of combustion
modifications for reciprocating 1C engines is given in Reference 4-43.
4-47
-------
Much research has been focused recently on the development of low-NOx gas turbine combustors
for both stationary and mobile sources (References 4-69, 4-92 through 4-100). Some of advanced com-
bustor concepts proposed depart radically from conventional designs. In general, most combustor
modifications attempt to control NOX emissions by reduced reaction flame temperatures, decreased
residence times, and controlled fuel air mixing. The techniques employed include leaning out of the
primary zone, increasing of the mass flowrate, earlier quenching with secondary air, air blast and
air assist atomization, fuel prevaporization, and premixing of fuel and air. Some of the more ad-
vanced designs propose heat removal from the combustion zone, precombustion, fuel staging, extended
flammability limits for ultra-lean combustion, fuel-rich low-intensity combustion, and staged swirl
mixing and burning. Most of these designs are still in the conceptual stage. The limited tests
performed on experimental test rigs have generally produced encouraging results with NOX reduction
ranging from 35 to 60 percent of conventional combustion; the results are summarized in Table 4-9.
In summary, new optimized design burners appear to have the capability of reducing NOX con-
centrations 40 to 65 percent from conventional burner designs on gas and oil fuels. Similar reduc-
tions are being demonstrated on prototype coal-fired units. The new low-NOx burners are designed to
attain controlled mixing of fuel and air in a pattern that keeps the flame temperature down and dis-
sipates the heat quickly. Improved burner designs may well replace the external combustion modifi-
cations now in use and achieve significantly lower NO emissions. Thus, although low-NO burners
have limited current application, they will receive primary emphasis in the NOX E/A for far-term
application.
4.2.7 Water Injection
Water injection has been shown to reduce flame temperature and is widely used in gas turbines.
Only recently has water injection been tried on utility boilers. Table 4-10 summarizes the current
state of water injection as a NOX control method for stationary combustion sources.
The Ormand Beach, California steam-generating units were tested with water injection to re-
duce NOX (Reference 4-74). The boilers, operating at 75 percent of full load (design capacity 800
MW) with 10 percent tertiary air, were emitting 400 ppm of NO. When 0.6 kg of water per kg of oil
was injected, the emissions were reduced to 228 ppm, a 43 percent reduction. Higher reductions were
obtained with flue gas recirculation and water injection combined. For example, with 15 percent gas
recirculation and injection of 0.2 kg of water/kg of oil, NO reduction of nearly 50 percent was
achieved. Compared to flue gas recirculation, water injection imposes a large energy penalty.
Water injection increased the minimum 02 requirement and significantly lowered the efficiency. For
this reason, water injection seems to be an unattractive NOX control technique for utility boilers.
4-48
-------
TABLE 4-10. SUMMARY OF RESULTS WITH WATER INJECTION
Equipment Category/
Fuel
Utility boilers
Oil
Coal
Internal combustion
engines
Gas
Diesel
Dual fuel
Gas turbines
Oil (distillate)
Gas (natural)
Control Method/
Range
Water sprayed into
windbox 0 to 0.6
kg H20/kg fuel
Water injection
0.2 kg H20/kg coal
i
Water induction
0.94 kg H90/kg
fuel i
0.17 to 0.21
kg H20/kg fuel
0.1 to 0.25
kg H20/kg fuel
Direct injection
of atomized ^0
into the primary
zone 0.3 to 1.0
kg H20/kg fuel
0.3 to 1.0
kg H20/kg fuel
NOX
Reduction
0% to 40%
(opposed wall-
firing)
15% (opposed wall
firing)
70%
20% to 40%
50% to 70%
30% to 80%
30% to 80%
Effect On
Operation/
Maintenance
Increases minimum
02 requirement-
burner flame de-
tectability
problem
Better ESP
efficiency
Increases CO and
HC emissions/
rapid buildup of
scale
Increases CO, HC
emissions
Increases HC
emissions/engine
durability
decreases
Small increase
HC and CO
emissions possible
Small increase
HC and CO
emissions possible
Efficiency
Fuel Consumption
Lowers effi-
ciency (by
roughly 10%)
Lowers effi-
ciency
(roughly 10%)
No data
No data
No data
Decreases
efficiency up
to 1%
Decrease
efficiency up
to 1%
Extent
Used
Demonstration only
Southern Calif.
Edison
Demonstration only
Arizona public
service
Experimental /not
used
Experimental /not
used
Experimental /not
used
Extensive retrofit
use; inclusion in
new unit design
R&D
Status
Inactive
Inactive
Inactive
Inactive
Continuing develop-
ment for new and
retrofit use; long-
term emphasis is on
dry controls
4*
to
-------
Water injection has not been tried on industrial boilers and no experimental or field test
data are available at this time. Based on the results obtained from utility boilers, it appears
that water injection is not a viable control technique for industrial boilers.
Water can be introduced with the intake air or injected directly into the cylinder of inter-
nal combustion engines. The effectiveness of water injection/induction depends on the degree of
atomization and mixing of the water within the combustion chamber; the reported effectiveness in
lowering NO emissions depends almost linearly on the rate at which water is added. More than 30
percent NO reductions were obtained, for large bore engines, with 0.5 kg of water per kg of fuel.
However, the effectiveness of water induction decreases at water-to-fuel ratios greater than one
(Reference 4-43).
Operational/maintenance problems associated with water injection include leakage of water
into the crankcase which contaminates the lubricating oil and rapid buildup of mineral scale around
the valves, water injection nozzles, and other components through which the water flows. The
availability of water may be a problem for those engines which are used in remote and frequently
arid locations (Reference 4-43).
Over 80 percent NO reductions have been achieved with water injection on gas turbines.
Injecting atomized water directly into the primary zone of the combustor is most effective in re-
ducing NO .
The only problems involve the quality and quantity of water injected, since these determine
the operational economics and life of the gas turbine. Most utilities which use water injection
have some sort of purification system. According to industry sources, boiler feed water quality
requirements are more stringent than those for the water injected into gas turbines (Reference 4-69).
The quantity of water used varies significantly between turbines and depends on such factors
as mechanical design, plant location, heat rate, turbine inlet temperature, fuel characteristics,
and operating mode. The water to fuel weight ratios vary from as low as 0.5/1 to as high as 1/1
(Reference 4-101).
The industry and manufacturing sources report that the water injection process does not appear
to affect turbine life; no major problems have been encountered. However, with water injection the
fuel consumption increases approximately 3 percent for water/fuel ratios of 1/1. Water injection
increases the mass flow through the turbine which, in turn, increases turbine power outout. Typical
increases in capacity are about 8 percent with a water/fuel ratio of 1/1 (Reference 4-69).
4-50
-------
In summary, water Injection has been found to be very effective 1n suppressing NO emissions
from gas turbines. However, the use of water injection may entail some undesirable operating con-
ditions, such as decreased thermal efficiency and increased equipment corrosion. It is, therefore,
an unpopular NOX reduction technique for all combustion equipment except for near-term use on gas
turbines. In the long term, it is anticipated that water injection will be replaced by advanced
combustor can design.
4.2.8 Reduced Air Preheat
NOX emissions are strongly influenced by the effective peak temperatures in the combustion
zone. Thus, any modification that lowers these temperatures, such as reducing the combustion air
temperature, should lower NOX emissions. Theory indicates that a 56K (100F) decrease in air preheat
temperature will result in an approximately 28K (50F) reduction in the adiabatic combustion tempera-
ture, which in turn will decrease thermal NOV formation by 27 percent (References 4-53, 4-72). Since
A
reduced air preheat does not significantly suppress fuel nitrogen conversion (Reference 4-102), it is
expected that this control technique would be most effective on fuels, such as natural gas and dis-
tillate oil, which have low nitrogen content.
| Reduced air preheat is potentially applicable to most utility boilers, industrial boilers
with preheated combustion air, regenerative gas turbine units and turbocharged internal combustion
engines. This method for controlling NO usually greatly lowers fuel economy, however. New designs
to reduce stack gas temperatures, for example, and redesigning the convective section of a boiler
for more heat absorption would be necessary to maintain efficiency.
Only limited field test data are available on the effect of reduced air preheat in utility
boilers due to the severe efficiency penalty incurred with this method. Some field test results and
discussions on reduced air preheat for utility boilers are available in References 4-37, 4-38, 4-40,
4-47, 4-63, 4-70 through 4-73. Conclusions and results from these references are summarized in
Table 4-11.
The data for coal showed varying trends, although a maximum reduction of 75 ppm (at 0 percent
02) per 56K (100F) reduction in air temperature was reported in one case (Reference 4-102). In
general, NO reductions of about 50 percent for gas-fired boilers and 40 percent for oil-fired boilers
A
can be expected with reduced air preheat, however, NOX reductions in coal-fired boilers were very
small (Reference 4-63).
Industrial boilers that have combustion air preheat are usually found in sizes above 15 f*l
(50 x 10s Btu/hr) input capacity. Firetube boilers are generally not equipped with air preheaters.
Field test results on the effects of reduced air preheat are given 1n References 4-45 and 4-53 and
4-51
-------
TABLE 4-11. SUMMARY OF RESULTS WITH REDUCED AIR PREHEAT
Equipment Category/
Fuel
Utility Boilers
Gas
Oil
Coal
Internal water-
tube boilers
Gas
Oil
Coal
Control Method/
Range
Reduce combustion
air temp, from
typical range of
480K to 590K
to ambient tem-
peratures, less
effective for fuel
N0x
Reduce combustion
air temp, from
typical range of
395K to 620K down to
ambient temperatures
NOX
Reducti on
Up to 25% per 56K
(100F) decrease
in air preheat
temperature
Approx. 7% per
56K (100F) de-
crease in air
temperature
Generally
ineffective
Up to 25% per 56K
(100F) decrease
in air preheat
temperature
Approx. 15% per
56K (100F) de-
crease in air
temperature
No reliable
data available
Effect On
Operation/
Maintenance
Induced draft fan
capacity must be
increased. Pos-
sible flame in-
stability.
Preheated air is
required for pul-
verizer operation.
Coals with higher
moisture contents,
e.g., lignite, re-
quire higher pri-
mary air
temperature.
Same as for util-
ity boilers
Efficiency/
Fuel Consumption
Significant
energy penalty
for existing
units — about
2% drop in
efficiency per
56K (100F) de-
crease in air
preheat tempera-
ture
Same as for
utility boilers
Extent
Used
No use due to
energy penalty
None; trend to
higher preheat
for energy con-
servation
R&D
Status
Inactive
Some evaluation
of alternate
waste heat use
to allow lower
preheat; trend
in new units gen-
erally to higher
preheat
o
^o
1
-------
TABLE 4-11. Concluded
Equipment Category/
Load
Internal combustion
engines
Gas
Dual fuel
Diesel
Control Method/
Range
For engines with
turbochargers , re-
duce air inlet tem-
peratures typically
from 330K down to
about 31 OK
N0x
Reduction
Up to 2.3% per
IK (1.8F) air
temp decrease
Up to 2.3% per
IK (1.8F) air
temp decrease
Up to 0.7% per
IK (1.8F) air
temp decrease
Effect On
Operation/
Maintenance
Heat exchanger
using air, cold
water supply, or
cooling tower
required
Efficiency/
Fuel Consumption
Up to 1.3% in-
crease in energy
consumption
Up to 0.5% in-
crease in energy
consumption
Up to 1.0? in-
crease in energy
consumption
Extent
Used
Widely used in
large turbocharged
engines
R&D
Status
-------
are summarized in Table 4-11. For both industrial and utility boilers, reduced air preheat reduces
efficiency, and is therefore not a practical control technique for existing units. Design changes
in new units, such as installing or enlarging an economizer, are required to regain the waste heat
which would otherwise be lost through the stack.
Turbocharged internal combustion engines over 373 kW (500 hp) output normally have inter-
coolers between the turbocharger and the intake manifold to increase the air density, permitting
higher mass flow rates and consequently, higher power output. However, the intercooler which de-
creases the inlet temperature also causes NO emissions to decrease.
Results of studies cited in References 4-32 and 4-43 are summarized in Table 4-11. Reduced
manifold air temperatures increase the brake specific fuel consumption, but only by a small per-
centage. Required hardware changes include the addition of heat exchangers or the installation of
larger heat exchangers. For hot, humid climates with no access to large supplies of cold water,
cooling towers must be installed.
Regenerative gas turbines use the turbine exhaust gases, which are typically at temperatures
ranging from 790K to 975K (800 to HOOF), to preheat the combustor inlet air. This results in a
significant improvement in overall cycle efficiency. Reference 4-73 tabulates results from tests
on two similar turbines: one operating in a simple cycle, the other in a regenerative cycle. The
heat rate (thermal energy consumed per unit of power output) is 18 percent lower for the regenerative
unit, but the NO emissions are greater by more than a factor of two.
Reference 4-73 also gives N0v emissions as a function of combustor inlet temperature as pre-
A
sented by Lipfert. Reducing the combustor inlet from 850K to 410K (900 to 200F) reduces NO by
90 percent. However, at lower temperatures, further reduction in combustor inlet temperature is not
expected to lead to still lower NO emissions.
In summary, reduced air preheat for gas turbines and for boilers is not a practical control
technique, unless the energy in the exhaust gases can be utilized effectively for other purposes.
One way to use this energy is to use combined gas-steam turbine cycles; this will be discussed in
Section 4.6. Reduced air preheat will be accorded low priority in the NO E/A.
A
4.2.9 Ammonia Injection
The post-flame decomposition of NOX by reducing agents has recently shown promise as a method
for augmenting combustion modifications if stringent emission limits are to be met. Exxon has
patented a process for the homogeneous gas phase selective decomposition of NOX by ammonia
4-54
-------
(Reference 4-103). The gas phase reaction in the temperature range of 980K (1.400F) to 1370K
(2.000F) converts nitric oxide, in the presence of oxygen and ammonia, into nitrogen and water
vapor (Reference 4-104).
Results of lab scale tests show that the level of NOX reduction depends on the combustion pro-
duct temperature, initial NOX concentration, and quantity of ammonia injected (Reference 4-105).
Based on the available results, ammonia injection appears to be most effective between 980K (1.300F)
and 1370K (2.000F), which corresponds to conditions in the convective section of large boilers.
Maximum NOX reductions, as much as 90 percent, were obtained at 1230K (1.750F) with molar ratios of
ammonia to initial nitric oxide ranging from 1.0 to 1.5.
Field tests were conducted on a gas-fired furnace rated at 147 kW (500 MBtu/hr), and on an
oil-fired boiler rated at 41 kW (140 Btu/hr) with both the units retrofitted for NH, injection
-------
TABLE 4-12. SUMMARY OF RESULTS WITH AMMONIA INJECTION
Equipment/
Description
Experimental
combustor,
59 kW
(200,000 Btu/hr)
firing either
gas or oil
Experimental
tubular reactor
Oil fired
41 MW
(140 MBtu/hr)
Gas-fired
furnace
147 MW
(500 MBtu/hr)
Temperature
Range Tested
(K)
920-1 ,480
870-1 ,300
870-1 ,300
—
Range of NH3
concentration
(ppm)
0-5,250
400
400
NH,.
. •* - 1 tn 4 5
N0initial
NH,
•j _ -i 4._ n r
wn i i.u t.j
""initial
Range of
Initial NOX
Concentration
(ppm)
100-1,000
250
250
—
Range of
Final NO
(ppm)
10-100
10-100
10-250
30-65%
reduction
30-80%
reduction
Comments/
Remarks
Maximum NOX
reduction occurs
at 1.230K, most
effective with
high initial NOX
concentrations
Maximum NOx
reduction occurs
at 1,230K (with-
out H£ injection)
Maximum reduction
occurs at 980K
with H« addition
—
-------
injection include the presence of ammonia as a primary pollutant in the stack gas and potential
reactions of ammonia with the flyash and sulfur compounds in coal firing. Since low temperature
stack gas reactions are important here, pilot scale tests will be of limited use. Full quantifica-
tion of potential adverse impacts of ammonia injection will await full scale demonstrations with
coal firing.
In addition to the above operational concern, there is also the strategic question of whether
sufficient ammonia would be available in the 1980's and 1990's for widespread application in utility
boilers (Reference 4-106).
In summary, ammonia injection does not appear to have near-term application for NO control
X
in the U.S. It shows promise for far-term applications, however, and will be given primary emphasis
in the NOX E/A for assessment of advanced concepts for the 1980's and 1990's.
4.2.10 Costs of Combustion Process Modifications
This section presents the most recent data on capital and operating costs of combustion modi-
fication NO controls for each equipment category. Except where otherwise noted, the costs pre-
sented here are in 1974 dollars. In some cases, earlier cost figures have been converted to 1974
dollars by applying appropriate inflation factors.
In several cases the costs presented are for combined NO controls. Generally, the effect-
X
tiveness of combined NO controls is not equal to the sum of the individual effects of each control.
Likewise, the costs of combined controls are not the sum of the costs of single controls.
4.2.10.1 Utility Boilers
The cost-effectiveness and related costs of combustion modifications in full-scale combustion
equipment for utility boilers have been fairly well documented. One of the earliest efforts was
attempted by Esso Research Labs in 1969 (Reference 4-107). Since 1969, however, it has been shown
that the effectiveness of control techniques among boilers varies widely and requires continuing
cost-effectiveness evaluations on an individual boiler basis. The most recent cost data for both
new and existing tangential, coal-fired utility boilers (Reference 4-108) are summarized in
Figures 4-6 and 4-7. The costs are for the combined use of overfire air ports and low excess air
firing, as this is the preferred control system for tangential coal-fired boilers. Capital costs
were projected over a unit size range of 25 to 1000 MW. The corresponding annual operating costs
for 500 MW units was 0.006 mils/kWhr for a new unit and 0.021 mils/kWhr for existing units. Figure
4-6 applies to new unit designs with heating surfaces adjusted to compensate for the resultant
4-57
-------
1.00
2 0.75
V,
4A-
(-" 0.50
o
o
0.25
0.00
NEW UNITS INSTALLATION COSTS
4 WINDBOX FURNACES
8WINDBOX FURNACES-
200
400 600
UNIT SIZE, MW
800
1000
Figure 4-6. 1975 capital cost of OFA on new tangential
coal-fired boilers (Reference 4-39).
4-58
-------
1.50
1.25
1.00
•vt-
_- 0.75
(0
o
o
0.50
0.25
0.00
EXISTING UNITS MODIFICATION COSTS
4 WINDBOX FURNACES
8 WINDBOX FURNACES
200
400 600 800
UNIT SIZE, MW
1000
Figure 4-7. 1975 capital cost of OFA on existing coal-fired
boilers (Reference 4-39).
4-59
-------
changes in heat transfer distribution and rates. Figure 4-7 applies to existing units with no change
in heating surface, as these changes must be calculated on an individual unit basis.
Cost ranges for existing units vary more widely than for new units, since variations in unit
. design and construction can either hinder or aid the installation of a given NOX control system.
Also, above approximately 600 MW, single cell-fired boilers exceed a practical size limit and
divided furnace designs are utilized. Since a divided tangentially-fired furnace has double the
firing corners of a single cell furnace, the costs increase significantly.
It should be kept in mind that although these cost data for utility boilers were developed
for tangentially coal-fired boilers, the range of costs presented is also generally applicable to
wall-fired boilers burning coal. And, the cost of similar combustion modifications on gas- and
oil-fired utility boilers should be no higher than for the coal-fired units.
Generally no significant additional cost for modern units or units in good condition is re-
quired for reducing excess air. However, some older units may require modifications such as alter-
ing the windbox by adding division plates, separate dampers and operators, fuel valving, air regis-
ter operators, instrumentation for fuel and air flow and automatic combustion controls. Table 4-13
shows estimated investment costs for low excess air (LEA) firing on existing utility boilers (Refer-
ence 4-109). These costs are guidelines, which can vary depending on the modifications that are
required. As unit size increases, the cost per kW decreases since the larger units typically have
inherently greater flexibility and may require less extensive modification.
The use of low excess air firing reportedly increases boiler efficiency by 0.5 to 5 percent.
Additional savings may result from decreased maintenance and operating costs, so any investment
costs can be offset by savings in fuel and operating expenses.
As an example of cost variations for combustion modifications among individual existing units,
several case studies from Pacific Gas and Electric are presented in Table 4-14. The numbers shown
are the costs incurred by PG&E during a recent program to bring eight units into compliance with local
NOX emission regulations. For the most part, the conversions involved the combination of windbox flue
gas recirculation and overfire air ports. The average cost of the modifications is about, in 1975
dollars, $10/kW (Reference 4-110).
Another West Coast electric utility company, the Los Angeles Department of Water and Power
(LADWP), has had extensive experience in implementing NOX control techniques on its gas- and oil-
fired boilers. The techniques currently utilized by the Department include burners out-of-service
(BOOS), overfire air/NOx ports, and low excess air. Although the units are operated with the lowest
4-60
-------
TABLE 4-13. 1974 ESTIMATED INVESTMENT COSTS FOR LOW EXCESS
AIR FIRING ON EXISTING BOILERS NEEDING MODIFICATIONS
(Reference 4-109)
Unit Size
(Electrical Output)
(MW)
1000
750
500
250
120
Investment Cost
($/kW)
Gas and Oil
0.12
0.16
0.21
0.33
0.53
Coal
0.48
0.51
0.55
0.64
0.73
4-61
-------
TABLE 4-14. 1975 INSTALLED EQUIPMENT COSTS FOR EXISTING PG&E RESIDUAL OIL-FIRED UTILITY BOILERS
(Reference 4-110)
i
o\
po
Unit Name
Pittsburg
#7
Pittsburg
#5 and #6
Contra Costa
19 and #10
Portrero #3
Moss Landing
#6-1 and #7-1
Design Type
CE tangential 1y-
fired, divided
B&W opposed-fired
B&W opposed-fired
Riley turbo-fired
BSW opposed-fired
Year
Online
1972
1964
1965
1972
(?)
Capacity
(MM)
730
330 (each)
345 (each)
206
750 (each)
Modification
Cost
($106)
6.2
7.8 (both)
6 (both)
3.5
2.8
$/kW
8.5
11.8
8.7
17
1.8
Year
Modified
1975
1975
1975
1975
1971
Type of Modification
Windbox FGR, Overfire Air
• Two new 5000 hp FGR fans
• FGR ducting (17% FGR)
• NOX port installation
• No new burner safeguard
system
Windbox FGR, Overfire Air
• Transferred two FGR fans from
other units
• FGR ducting (17% FGR)
• New hopper
• NOX port Installation; one for
each burner column
• New burner safeguard system;
computer, NOX control board,
02 controls on dampers, flame
scanners
Windbox FGR, Overfire Air
• New FGR fans (1 ea.) (17% FGR)
• Nominal awount of new ducting
to wlndbox
• N02 port Installation
Windbox FGR, Overfire A1r
• New FGR fan (17% FGR)
• NOX port installation, nominal
amount of ducting
• New burner safeguard system,
NOX control board, computer
Windbox FGR, Overfire Air
• Existing temperature control
FGR fans replaced with larger
fans
• New flame scanners
a.
*s
ro
-------
excess air possible, it has been found that when LEA is combined with other reduction methods, ex-
cess air levels must be increased beyond those normally required.
The Department's data indicate a unit efficiency decrease of approximately 1 percent attri-
butable to BOOS operation. As found by other operators, LEA tended to increase efficiency slightly;
a 1 percent decrease in excess oxygen increased efficiency by about 0.25 percent. Properly retro-
fitted, overfire air had no effect on efficiency.
The NOX control costs incurred by LADWP are shown in Table 4-15 for four different units. "
The figures for the BOOS techniques reflect the R&D costs that precede the retrofit. All costs are
installed equipment costs which include the labor required to implement the control methods. The
very low expense associated with overfire air on the B&W 235 MW unit is due to the base year of
the estimate (1964 to 1965), and to the fact that this modification was included in the original
boiler design.
The overfire air costs for the B&W 235 MW unit are somewhat low in Table 4-15. The LADWP
boilers were, for the most part, modified without much difficulty, and the associated costs probably
represent the lower limits of the costs for the three NO reduction tecniques implemented (Reference
A
4-111).
In addition to the increased capital costs from including a NOX reduction system in new or
existing units, the increased unit operating costs must be considered. These differential operating
costs were defined for 500 MW new and existing utility boilers and are shown in Table 4-16 (Refer-
ence 4-108). The costs are given in 1975 dollars, and the equipment costs shown are determined
from Figures 4-6 and 4-7. To put these operating costs in perspective, they can be compared to the
percent increase in generating costs shown at the bottom of Table 4-16. Except for the case of
older units, the difference in operating cost is below 0.1 percent of annual cost.
In summary, the following are the major economic considerations that the boiler operator or
designer may be faced with:
• The lowest cost method for reducing NOX emission levels on new and existing units is the
incorporation of low excess air firing. Minimal additional costs are involved.
• For most utility boilers, the second lowest cost NOX control method appears to be off-
stoichiometric combustion by biased firing, "burners out-of-service" (BOOS) or the addi-
tion of an overfire air system. Although lowering excess air (LEA) is implemented con-
currently with other control techniques, the excess air levels may have to be increased
beyond those normally required.
4-63
-------
TABLE 4-15. LADWP ESTIMATED INSTALLED 1974 CAPITAL COSTS FOR NO REDUCTION
TECHNIQUES ON GAS- AND OIL-FIRED UTILITY BOILERS X
(Reference 4-111)
Unit
Capacity
(MW)
180
235
235
350
Unit
Type
C.E. tangen-
tial ly-fi red
C.E. tangen-
tial ly-fi red
B&W Opposed-
fired
B&W Opposed-
fired
NOX Reduction
Technique
BOOS
LEA
BOOS
LEA
BOOS
Overfire air
LEA
BOOS
Overfire Air
LEA
Implementation
Method
Retrofit
Retrofit
Retrofit
Retrofit
Retrof i t
Original Design
Retrofit
Retrofit
Retrofit
Retrofit
Estimated
Cost
($)
69,400
28,900
75,200
28,900
75,200a
14,000a
28,900
266,000
100,600
28,900
$/kW
0.38
0.16
0.32
0.12
0.32
0.06
0.12
0.76
0.29
0.08
I
at
1964-65 base year
-------
TABLE 4-16. 1975 DIFFERENTIAL OPERATING COSTS OF OFA ON NEW AND EXISTING TANGENTIAL
COAL-FIRED UTILITY BOILERS (Reference 4-108) (Net Heat Rate 9,500
Btu/kWhr, March 1975 Equipment Costs)
Capital Costs $/kw
Annual Cap. Cost $
Annual Fuel Cost $
Labor & Ma int.6 $
Total Annual Cost $
Electricity Cost9
mils/kWhr
Increase - %
Increase — mils/kWhr
New
Plant
Without
Overfire Air
500.00
40,000,000a
18,000,000°
8,100,000
66,100,000
24.481
-_-
—
New
Plant
With
Overfire Air
500.20
40,016,000
18,000,000
8,100,000
66,116,000
24.487
0.024
0.006
Recent
Existing
With Added
Overfire Air
500.70
40,056,000
18,000,000
8,100,000
66,156,000
24.502
0.086
0.021
Older
Existing
Without
Overfire Air
250.00
20,000,000b
9,000,000d
8,100,000
37,100,000
13.741
___
—
Older
Existing
With Added
Overfire Air
250.70
20,056,000
9,000,000
8,100,000
37,156,000
13.762
0.153
0.021
en
tn
Based on: a
Annual fixed charge rate of 16% x 500 $/kW x 500,000 kW
b!6% x 250 $/kW x 500,000 kW
C0.70 $/106 Btu coal cost x 5,400 hr/yr x 500,000 kW x 9,500 Btu/kWhr
d0.35 $/106 Btu coal cost x 5,400 hr/yr x 500,000 kW x 9,500 Btu/kWhr
eLabor and maintenance cost of 3.0 mils/kWhr
f5,400 hr/yr at 500 MW - 2,700 gWhr/yr
9Cost at plant bus bar; transmission and distribution not included
-------
t Gas recirculation is more costly to Implement than overflre air and requires additional
fan power. In existing units, the need to reduce unit capacity to maintain acceptable
gas velocities through the boiler convective sections may impose an additional penalty.
• In general, the cost of applying any of the control methods to an existing unit will be
approximately 2 to 3 times that of a new unit design
4.2.10.2 Industrial Boilers
Cost data for combustion modifications on industrial boilers are virtually nonexistent, since
research and development, including field testing and application of NOX control methods to this
equipment category, is in its early stages. Only the most broadly-based estimates are available.
The most recent cost data are from a study in which a 5.1 MW (17.5 x 103 Ib steam/hr) D-type
watertube boiler was modified by adding staged air and flue gas recirculation capability (Reference
4-53). The windbox depth was increased and a second set of registers to control the recirculating
flue gas was installed inside the extension. The cost of these modifications was estimated at
$5,000; the current cost of new boilers of this type is about $60,000. The cost of a similar modi-
fication on other modern D-type boilers could be as high as $7,500, if the existing burner registers
cannot be used.
Manufacturers of industrial boilers in the 88 MW (300 x 103 Ib steam/hr) range and 1 mil-
lion dollar cost category estimate that, in general, a staged air installation would add from 2 to 4
percent to the boiler's cost. For A-type boilers, the added cost would be about 2 percent, and for
D-type boilers about 3 percent. Another booster air fan, if required, would increase the modifica-
tion cost by about 1 percent (Reference 4-53).
In a recent study, costs for retrofitting an existing unit to accept flue gas recirculation
were estimated (Reference 4-68). Approximate costs which include design, installation and equipment
costs associated with the retrofit of FGR systems were, in 1975 dollars, $20,340 for a 3.51 MW
firetube boiler and $21,190 for a 3.51 MW watertube boiler. However, these costs would be considerably
less for a new boiler. Reference 4-68 estimates that for a new boiler of the size mentioned above,
cost of including an FGR system will be about $6,900.
4.2.10.3 Internal Combustion Engines
There are few cost data for internal combustion engines, particularly for large (>375
kW or 500 hp) engines. Sufficient data exist, however, to give order of magnitude NO control
costs for the following engine categories:
4-66
-------
• Natural gas, dual fuel, and diesel fueled engines above 75 kW/cylinder (TOO hp/
cylinder)
• Small to medium (<75 kW/cylinder) diesel fueled engines
• Gasoline fueled engines (30 to 375 kW/cylinder)
Costs for large stationary engines can be estimated based on Reference 4-112 and information
supplied to Reference 4-43. These costs, however, relate to emission reduction achieved by engines
tested in laboratories rather than by field installations. Reference 4-94 indicates, nevertheless,
that these data are representative.
Table 4-17 lists cost impacts for control techniques applied to large stationary engines.
These cost impacts may be related to actual installations using baseline data presented in Table
4-18, which represent most applications. Basically, the controls involve an operating adjustment,
however, derating and manifold air cooling require hardware additions. Also, derating is not a
viable technique for existing installations unless additional units are added to satisfy total
power requirements.
The impact of the control costs may vary considerably, given that:
• Standby (<200 hr/yr) application control costs are primarily a result of initial cost
increases from emission control, whereas continuous service (>6,000 hr/yr) control costs
are largely a function of fuel consumption penalties
0 Controls which require additional hardware with no associated fuel penalty (e.g., mani-
fold air-cooling) may be more cost effective in continuous service (>6,000 hr/yr), than
operating adjustments which impose a fuel penalty (e.g., retard, or air-to-fuel change)
• The price of fuel can affect the impact of a control which incurs a fuel penalty. For
example, a control which imposes a fuel penalty of 5 percent for both gas and diesel
engines has more impact on the diesel fueled engine because diesel oil costs more
(2.20/106 Btu compared to $1.00/106 Btu for natural gas). This fuel impact may diminish
if gas prices increase more rapidly than oil prices.
In contrast to the large stationary engines, more published cost data exist for smaller
(<375 kW, 500 hp) gasoline and diesel engines which must meet State (California) and Federal
emission limits for mobile applications. Stationary engines in this size range are versions of
these mobile engines. Therefore, costs can be estimated based on a technology transfer from mobile
applications to stationary service, keeping in mind that in some cases mobile duty cycles (variable
4-67
-------
TABLE 4-17. COST IMPACTS OF NOX CONTROLS FOR LARGE BORE
ENGINES (Reference 4-43)
Control
Cost Impact
Retard
Air-to-fuel changes
Derate
Manifold air cooling
Combinations of above
Control techniques
Increased fuel consumption
Increased fuel consumption
Fuel penalty, additional hardware, and increased
maintenance associated with additional units
Increased cost to enlarge cooling system, and
increased maintenance for cooling tower water
treatment
Initial, fuel, and maintenance
Increases as appropriate
4-68
-------
TABLE 4-18. TYPICAL 1974 BASELINE COSTS FOR LARGE
(>75 kW/Cylinder) ENGINES3
Costs
1. Initial ,b $/kW
2. Maintenance,
$/kWhr
3. Fuel and lube,
$/kWhr
Total Operating,
2 + 3
Gas
174
4 x 10'3
10 x ID'3
14 x TO'3
Dual Fuel
174
4 x 10'3
10 x 10~3
14 x TO'3
Diesel
174
4 x 10-3
23 x 10"3
27 x 10"3
aBased on Reference 4-112 and information supplied to
Reference 4-43 by manufacturers.
Includes basic engine and cooling system.
4-69
-------
load) can differ from stationary duty cycles (rated load). Thus, costs (e.g., fuel penalties)
associated with a control technique used 1n a stationary application may vary from the mobile case.
Control costs for automotive vehicles required to meet State and Federal emission limits are typical
of the costs for small and medium gasoline and diesel fueled engines. However, more research is
required to relate specific emission control reductions to initial and operating cost increases for
stationary engine applications.
4.2.10.4 Gas Turbines
The most recent cost study of NOX controls for gas turbines was performed by the EPA (Refer-
ence 4-69). Based on information presented in this study, the best available systems of emission
reduction (considering costs) are wet systems, since these can be applied to turbines immediately
at minimal cost impact. Although dry control techniques are preferable because of their potential
simplicity, their complete development and application to large production turbines is still several
years away. Cost considerations for dry methods are, therefore, not discussed.
Table 4-19, derived from Reference 4-69, shows the expected increase in installed turbine
cost that results from using water injection to control NO to a proposed standard of 75 ppm. The
impact varies from 0.8 percent for the 820 kU (1100 hp) standby unit to 7.1 percent for the unit
that requires extensive water treatment equipment.
Table 4-20 summarizes the operating costs (in mils/kWhr), which would be incurred for 11 dif-
ferent simple cycle turbine plants meeting the proposed 75 ppm standard. This analysis was part of
a cost model developed in the EPA report (Reference 4-69).
The first two units in Table 4-20, S-l and S-2, differ only in the number of hours operated
annually. S-l operates 80 hours, and S-2 operates 200 hours per year. These units show the highest
percentage impact in terms of the added costs per net kWhr of power generation. The low number of
hours operated each year increases the cost of producing power, because fixed costs are spread over
a relatively small base. The estimated impact in both cases was roughly 2.4 percent.
Cases S-3 and S-4 are 820 kW (1100 hp) units operating the same number of hours, respectively,
as the smaller 261 kW units. These units can use exactly the same water purification system as the
smaller units. Since the costs of producing power Independent of the water injection system are
identical, the percentage impact is much less, decreasing to less than 1 percent.
Case 1-1 represents a normal, single shift gas turbine application. The unit is operated
2,000 hours per year and is slightly oversized, which negates any benefits that might be derived
4-70
-------
TABLE 4-19. IMPACT OF NOx EMISSION CONTROL ON THE INSTALLED 1975 CAPITAL COST
OF GAS TURBINES (Reference 4-69)
Application
A. Standby
1. 261 kW (350 hp)
2. 820 kW (1,100 hp)
B. Industrial
1. 3 MW (4,000 hp) -typical
2. 3 MW - offshore
C. Utility
1 . 66 MW
Installed Cost (1000$)
Without
Control s
56.6
177.9
352.8
352.8
9,900.0
With
Control s
58.0
179.3
366,8
379.8
10,070.0
% Increase
2.4
0.8
4.0
7.1
1.7
-------
TABLE 4-20. 1975 COSTS FOR WATER INJECTION, MILLS/KWHR
(Reference 4-69)
Item
Unit Size
Hours of Operation
Per Year
Annual 1 zed Fixed
Costs
Operating Cost of
Water Treatment
Hater for Injection
Energy Penalty
Mater Transport
Costs
Output Enhancement
Total
Baseline Costs
Percent Impact
Standby
S-l
261 kH
80
13.65
0.46
' 0.01
0.51
-
-
14.63
611.29
2.39
S-2
261 kW
200
5.46
0.46
0.01
0.51
—
-
6.44
264.79
2.43
S-3
820 kH
80
4.32
0.37
0.01
0.51
—
-
5.21
611.29
0.85
S-4
820 kH
200
1.73
0.37
0.01
0.51
—
-
2.62
264.79
0.99
Industrial
1-1
3 MU
2,000
0.48
0.10
0.01
0.43
—
-
1.02
43.77
2.32
1-2
3 MU
Z.OOO
0.12
0.10
0.01
0.43
—
0.09
0.57
32.53
1.75
1-3
3 MH
3,000
0.12
0.10
0.01
0.43
0.64
0.09
1.21
35.53
3.71
Utility
U-l U-2 U-3 U-4
66 MH
200
2.58
0.11
0.01
0.34
—
-
3.04
180.00
1.69
66 MU
500
1.03
0.11
0.01
0.34
—
-
1.49
85.45
1.75
66 MU
2,000
0.26
0.11
0.01
0.34
-
-
0.72
38.20
1.88
66 MU
8,000
0.06
0.11
0.01
0.34
—
o.n
0.41
26.39
1.56
Offshore
Drilling
Platform
3 MH
8,000
0.23
0.35
-.
0.43
—
0.09
0.92
32.53
2.83
ro
-------
from improved unit output. For Case 1-2, also a baseload turbine, a credit was taken for the im-
proved capacity of the unit.
The highest cost impact was recorded in Case 1-3, which represents a remote turbine applica-
tion in an arid climate in which water must be transported 50 miles at a cost of $0.02 per gallon.
The impact in such cases, including water storage facilities, is approximately a 3.7 percent in-
crease in the average cost of generating power. Since water injection results in a slight increase
in the power output capacity of the unit, a credit of 0.05 mills per kWhr was taken for the output
enhancement. A credit for enhanced output was also taken in the U-3 unit, since it is baseloaded.
In all four utility cases, the impact is less than 2 percent per kWhr.
Initially, it was thought that the offshore drilling platform would show the highest cost
impact. The unit was assumed to use sea water to fuel the water purification system, which in-
volved a substantial increase in the capital and operating cost of the system. The installed cost
of the water treatment equipment was $27,000, compared to $14,000 for an onshore application.
Despite these higher costs, the availability of water offset the costs associated with transporting
water to the remote gas compressing station application (1-3). The total cost of water injection
for the offshore platform was 0.92 mills/kWhr compared to 1.21 mills/kwhr for the remote site.
In summary, the resulting estimates showed that, except for standby units, the total change
in costs probably falls within the range of 0.4 to 1.5 mills per kWhr for turbines used in industrial
and utility applications. This cost is equivalent to about a 2 percent increase in operating costs.
Control costs for standby units were much higher, ranging from 2 to 14 mills per kwhr, because they
are used less. The cost is equivalent to approximately a 2.5 percent increase in operating costs.
4.2.10.5 Residential Heating Systems
Advanced low-NO burners in new furnace units are the best options for NOX control in space
heating equipment. A Blueray unit has been commercially available since 1974 and has been widely
tested in field installations, while a Rocketdyne unit is undergoing field demonstration preparatory
to certification and potential commercialization. With proper maintenance, both units offer NOX re-
duction potentials of 50 percent or greater and fuel savings of 5 percent or more, relative to
standard units. Using these low-NOx units in new houses and replacing obsolete conventional units
in existing houses would decrease residential NOX emissions nationwide, offsetting the potential
emissions increase from population growth, for several decades.
The 1975 cost, less installation, of the Blueray unit was $550 (Reference 4-113), compared
to conventional warm air furnaces which range from $300 to $500. The added cost of the low-NOx
4-73
-------
unit may be justified, however, since fuel savings result from the Improved thermal efficiency.
Differential costs for the Rocketdyne unit are comparable.
The prospects for cost-effective NOX control in existing space heating units are not prom-
ising. There are no modifications which significantly decrease NOX emissions. Furnace tuning and,
if required, burner head replacement are strongly recommended for reduction of carbon monoxide and
smoke and for improving unit efficiency, but thase modifications have little impact on NOX. Furnace
tuning (cleaning, nozzle replacement, leak detection, sealing and burner adjustment) costs a minimum
of $40 for the average residential unit, while head replacement costs an additional $25, less installa-
tion. This servicing is usually cost effective since it saves fuel and increases safety of operation.
4.2.10.6 Industrial Process Heating
Currently, there is very little application of NOX control to direct industrial process heat-
ing equipment. EPA's Industrial Environmental Research Laboratory (RTP)' is sponsoring a field test
program to identify the potential for NO control in a diversity of process furnaces, ovens, kilns,
and heaters. The program, scheduled for completion in 1979, will provide the data to evaluate
alternate control options.
4.3 FUEL DENITRIFICATION
To meet future NOV emission standards for stationary sources, fuel NO may have to be reduced
A X
to levels even lower than those produced by combustion modifications. "Fuel NO " emission reduction
from combustion equipment can be achieved with combustion modifications, clean fuel burning, or by
extracting the fuel bound organo-nitrogen prior to burning (fuel denitrification). This section de-
scribes the state of the art and the potential application of denitrification of oil and coal.
4.3.1 Oil Denitrification
Current technology for denitrification derives from pretreating fuel to remove sulfur. Heavy-
oil cracking (HOC), hydrodesulfurization (HDS), and coking are the three major refinery processes to
desulfurize fuel oil. Hydrodesulfurization is the most widely used and will be the only process dis-
cussed here. HDS produces a very low sulfur content liquid fuel and, at the same time, reduces
nitrogen by about 20 to 40 percent. Table 4-21 shows the performance and the reducing effect on the
nitrogen content of the fuel of one such HDS process.
Stringent federal and state regulations for sulfur dioxide emissions prohibit the direct com-
bustion of high sulfur Middle Eastern and South American crude oils. Therefore, virtually all im-
ported oils are refined for partial removal of sulfur before they are used. Presently two residuum
hydrodesulfurization techniques exist:
4-74
-------
• Vacuum gas-oil hydrodesulfurization (VGO)
• Residuum desulfurization (RDS)
The VGO process, also known as the indirect method, treats only the vacuum gas-oil product of the
vacuum distillation process with catalytic hydrodesulfurization, achieving at most 30 to 35 percent
desulfurization. Since with this process the yields of low sulfur oil are relatively small and
since only vacuum gas-oil can be treated, the residuum desulfurization technique or direct method
was developed. The advantage of residuum desulfurization is that it can catalytically desulfurize
residuum from the atmospheric distillation process.
Several feedstock desulfurization processes are used by major oil companies to produce very
low sulfur solid, liquid, and gaseous fuels. The overall desulfurization (HDS) and denitrification
(HDN) chemical reactions involved are (Reference 4-114):
(organo-sulfur compound j + H catalyst hydrocarbons + JH2s)
{organo-mtrogen compound J * (NH37
Hydrogen sulfide and ammonia are easily removed with presently available technology.
TABLE 4-21. HYDRODESULFURIZATION PERFORMANCE OF THE GULF PROCESS
Average of run properties
for 375F+ product
Gulf HDS Process
Sulfur, Wt %
Nitrogen, Wt %
Nickel , ppm
Vanadium, ppm
Gravity, API
Carbon residue (Rams), Wt%
Heat of Combustion, Btu/lb
Pour Point, F
Viscosity, SUV at F
110
210
Feed3
3.8
0.21
15
45
16.6
8.3
3,500
160
Desulfurized residual fuel oils
Type III
0.3
0.13
1.1
0.8
24.5
3.3
19,250
20
435
55
Type IV
0.1
0.11
0.2
0.1
26.0
2.2
19,350
0
320
53.5
Improved
Type III
0.3
0.13
1.8
3.3
25.4
3.3
19,300
25
375
58
aKuwait 650F+ charge to HDS
4-75
-------
Sulfided cobalt-molybdenum on alumina or nickel molybdenum on alumina are typical catalysts
in these processes. HOS and HDN occur simultaneously at suitable temperature and pressures, but
the reactions interact with each other In ways which are little understood. Satterfield (Reference
4-114) has conducted an extensive program to uncover the interactions of catalytic desulfurization
and denitrification. Thiophene and pyridine were used as model compounds because they represent some
of the less reactive organo-sulfur and organo-nitrogen compounds. The maximum conversion of pyridine
observed in Satterfield's work was 50 percent, whereas thiophene reached 100 percent conversion.
Figure 4-8 presents the results for HDN of pyridine alone on a NiMo/Al203 catalyst and in a number
of mixtures with thiophene. Up to 655K, increases in reactor temperature increase the percent con-
version of pyridine to ammonia. However, as temperature is increased beyond 655K, the percent con-
verted is decreased.
The effect of thiophene on HDN is two-fold. Below 600K the presence of sulfur compounds in-
hibits the HDN reaction, but above 600K the presence of thiophene enhances the HDN reaction. This
enhancement was attributed to the presence of H2S in the reaction, which prevents the initially sul-
fided catalyst to become rapidly desulfided.
Large deposits of shale in the U.S. are seen as a promising source of further crude oil,
but shale oil has a characteristically high concentration of nitrogen, ranging from 1.5 to 2.8 per-
cent by weight. More than two thirds of the nitrogen in crude shale oil is present in the form of
quinolines (pyridines) and indoles (pyrolles). Frost, et al. (Reference 4-115), studied the effect
of reactor temperature and pressure on the degree of fuel denitrification from crude shale oil using
the catalytic hydrogenation method. Nitrogen contents of the hydrotreated products ranged from
0.005 to 1.59 weight-percent from the original 2.18 percent in the untreated crude. Frost demon-
strated that denitrification of residual oils can be increased from 20 to 40 percent removal to
complete denitrification by progressively increasing the severity of the hydrogenation process,
either by increasing temperature or pressure or by changing to a more active catalyst.
As severity increases so does hydrogen consumption. Figure 4-9 shows the percent denitrifi-
cation as a function of hydrogen consumption. As the amount of hydrogen needed to denitrify the fuel
increases, the operating cost of the process also increases significantly- The majority of recently
reported hydrodesulfurization production costs (which produce 20 to 40 percent denitrification) are
between $5.00 and $10.70 per kiloliter of oil ($0.80-1.70/bbl) (Reference 4-116). The cost of
hydrogen is a major part of this total, contributing as much as $3.80/kl ($0.60/bbl) for a process
using approximately 170 nm3 of hydrogen per kiloliter of feed (1000 scf H2/bbl feed). In addition,
the higher pressures associated with increased process severity increase the initial investment cost,
4-76
-------
80'
c
o
c
o
o
O)
c.
-o
c:
OJ
u
O)
o.
60-
40--
20- -
I I I
Partial pressures at reactor inlet (bars)
Thiophene Pyridine
A
+
0
0.123
0.366
0.122
0.123
0.122
0.123
0.366
Run No.
5/8, 5/11, 5/38
5/26
5/29, 5/31
5/34, 5/36
Total pressure =11.2 bars
o
UN
200 300
Temperature, C
400
Figure 4-8. Pyridine HDN with NiMo/Al203 catalyst.
4-77
-------
350- -
-a
Ol
C
o
o
c
Ol
01
o
300-1-
250 - -
200 __
150 --
2200
800
20 30 40 50 60 70 80 90
Nitrogen removed, pet of total
100
Figure 4-9. Hydrogen consumption versus nitrogen removal
(Reference 4-116).
-------
since more expensive equipment is needed (Reference 4-117). Hydroprocessing is undergoing rapid tech-
nological development, as demands for low-sulfur and low-nitrogen residual oil increase.
Other denitrification methods are also being investigated. Guth and Diaz (Reference 4-118)
have patented an oxidation process to desulfurize and denitrify petroleum oils; the process has
been successfully operated at the pilot scale. In the Guth and Diaz process, the fuel nitrogen is
oxidized to the extent that the resultant compounds exhibit preferential solubility characteristics
in a solvent, usually methanol. In some cases, pretreatment of the oil to remove active groups which
cause undesirable side reactions or removal of low-sulfur fractions prior to the oxidation step are
necessary to increase the efficiency of the process. The oil is separated from the resultant solution
in a gravity separator. The extraction of the oxidized nitrogen compounds can be carried out simul-
taneously or in batches.
One possible difficulty with this process is that some oils tend to react nonselectively
during the oxidation step and form undesirable polymers and coke. This problem can be alleviated
by preheating the feed oil to 475 to 660K (300 to 600F) for 2 to 20 hours to permit the reactive
groups in the oil to combine with other hydrocarbons and thus become less active. Recent tests show
that up to 93 percent denitrification was achieved with distillate oils and 45 percent with residual
oils. This method is currently still under investigation; full scale experimentation is expected
in the near future.
This denitrification and desulfurization process is particularly attractive since it does not
require hydrogen and it operates at low temperatures and pressures. Capital costs range from $4.50
to $11.30 per liter per hour ($30 to $75 per bbl/day) using distillate oil; process operating costs
range from $0.50 to $1 per day (Reference 4-119). Costs were not given for residual oils, since the
Guth-Diaz process does not denitrify all residuals. One major application of this process is in a
small refinery (133 kl/hr or 20,000 bbl/day capacity); the capital investment would be relatively
small compared with conventional hydroprocessing.
4.3.2 Coal Denitrification
Besides coal gasification and liquefaction, alternative processes which decrease the sulfur
content of coal are presently being investigated. Some of these are:
• Solvent refined coal (SRC)
• Meyers process
• Hydrothermal desulfurization
However, none of the above processes has shown any promise in removing fuel bound nitrogen from coal.
4-79
-------
Solvent refined coal is produced by dissolving raw coal In a solvent, separating the ash from
the coal by filtration, and reconstituting the coal from the solvent. The reconstituted coal is free
of water, low in sulfur, very low in ash, and sufficiently low in melting point that it can be
handled as a fluid, if desired. Its heat content is higher than that of coal at a uniform value of
37,177 kJ/kg (16,000 Btu/lb), regardless of the original coal from which it was prepared.
Unfortunately, the nitrogen content of solvent refined coal is not reduced. The results of
two SRC tests conducted by Pittsburg and Midway Coal Mining Company (Reference 4-120) in which the
nitrogen content was essentially unchanged are as follows:
TABLE 4-22. SOLVENT REFINED COAL TESTS
% c
% H
% S
% N
% 0
% Ash
Feed
Composition
64.76
4.36
4.94
1.85
8.33
15.76
Product
Composition #1
87.50
5.23
0.882
2.040
4.17
0.179
Product
Composition #2
87.32
5.11
0.944
1.909
4.58
0.133
Increases can be attributed to errors 1n material balance procedures and to the fact that ash was
removed. Because of its significantly lower sulfur content and improved heating value SRC has great
potential for future use as a utility fuel. Its impact on "fuel NOX" emissions will be insignificant
since the fuel nitrogen content remains unchanged. However, NO emissions on a basis of Ib/MBtu may
decrease due to the higher heating value of solvent refined coal.
In the Meyers process,, the pyritic sulfur in the coal is removed by a reaction with ferric
sulfate in a solution containing ferric and ferrous sulfate and sulfamic acid, the elemental sulfur
product is extracted with an organic solvent. Analysis on the product coal showed that the nitrogen
content was essentially not affected by the Meyers process (References 4-121 and 4-122).
E. P. Stambaugh of Battelle Memorial Institute (BMI) has also developed a process for re-
moving sulfur from high-sulfur coal. The Battelle Hydrothermal Coal Process (BHCP) involves heating
a coal slurry and a chemical leachant at moderate temperature and pressure to selectively extract
the sulfur and some of the ash from the coal. As with other coal pretreatments, hydrothertnal treat-
ment does not extract the nitrogen (References 4-123 and 4-124).
In summary, with present technology, only liquid fuels can be denitrified. High temperature,
high pressure catalytic hydrodesulfurization is the most widely accepted way to denitrify residual oil.
4-80
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No new Improved technology has been investigated on a full scale basis, although some new processes
have been developed and tested with pilot scale facilities.
The present HDN processes have several disadvantages that contribute to the ever increasing
cost of desulfurization and denitrification. First, it is costly to use hydrogen to remove sulfur
and nitrogen. Hydrogen must be produced by pyrolyzing hydrocarbon materials or through combustion
of hydrocarbons to form carbon monoxide, which is subsequently reacted catalytically with water at
high temperature. Second, the process requires a heterogeneous catalyst. The surface of the solid
catalyst tends to become fouled (particularly when residual oils are desulfurized), making the pro-
cess inefficient or not feasible with some residual fuels. And thirdly, the process requires high
temperatures and high pressures, which necessitates expensive equipment. The nitrogen content
of coal is not easily reduced unless the coal is first converted to a liquid fuel (i.e., coal
liquefaction). Presently, no coal desulfurization .processes have any significant effect on fuel
nitrogen.
4.4 FUEL ADDITIVES
Fuel additives have been used for many years as agents to reduce soot and ash deposits on
heat transfer surfaces and to minimize the corrosion effects of these deposits. Fuel additives
have contributed to improved equipment performance and maintenance, but recently, fuel additives
have been investigated as possible aids in reducing nitrogen oxide emissions from small steam gen-
erators, gas turbines, and 1C engines.
Additives can theoretically reduce NO emissions through one or a combination of the follow-
X
ing effects (Reference 4-125):
• Catalytic reduction or decomposition of NO to N2
• Reduction of local concentration of atomic oxygen
• Reduction of flame temperature through increased thermal radiation and dilution
• Delay of ignition timing in 1C engines
• Decrease of fuel/air mixing through a change in spray fluid dynamics
A number of investigators have experimented with numerous fuel additives in order to reduce
NO emissions. Shaw (Reference 4-125) investigated approximately 70 additives in a jet-fueled gas
A
turbine combustor. The organometallic additives, cobalt, iron, copper, and manganese were added
to the fuel in 0.5 percent by weight concentrations. They acted as reducing and decomposing catalysts
and reduced N0x by 15 to 30 percent.
4-81
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McCreath (Reference 4-126) investigated the effect of additives on NOX emissions from diesel
engines. He found that both isoamyl nitrate and ditertiary butyl peroxide, which reduced the igni-
tion delay, could reduce the nitrogen oxides content of the exhaust gas by 15 to 18 percent using
0.15 moles of additives per liter of diesel fuel. Other organometallic compounds in concentrations
of 1 percent by volume reduced NO by 16 percent in laboratory burners (Reference 4-127).
One of the more comprehensive studies on fuel additives was reported by Martin, Pershing, and
Berkau (Reference 4-128). Over 200 currently marketed additives were tested on diesel fuel and
burned in an experimental furnace. No NO reduction was reported; instead, some of the nitrogen
containing additives increased NO emissions. In continuation of their work (Reference 4-129), four
A
of the most widely publicized materials (Trimex, Pace, KAP, and Glo-Klen) were tested in a 40 kW
(54 hp) firebox-firetube packaged boiler firing residual oil. The additives were blown into the
primary combustion zone, but the effect on NO emissions under all conditions investigated was in-
significant, and particulate emissions increased significantly. A good state-of-the-art review of
combustion additives may be found in Reference 4-130.
One problem with additives is since liquid and solid fuel additives contain large quantities
of solids and inerts, including potentially corroSive salts or toxic metals, they can create a
severe air pollution hazard or can be otherwise deleterious to equipment and surroundings. Also,
at $2 to $20 dollars per kilogram, fuel oil additives can be very expensive (Reference 4-128).
Another potential use of fuel additives is in combination with well established NO control
X
techniques; they suppress some of the negative effects that the control techniques have on other
pollutants and combustion equipment performance. For example, for large multiburner boilers firing
residual oils and coal, off-stoichiometric combustion through staged firing and low excess air are
well known combustion modification techniques with definite NO reduction effects. The degree of
implementation of these techniques is limited by adverse side effects such as
• Localized reducing atmosphere leading to heat transfer surface corrosion especially
with high sodium and high vanadium fuels
• Decreased convective heat transfer leading to loss in superheater steam temperatures
• Fouling and corrosion of air heaters
• Increased hydrocarbon particulate matter causing boiler efficiency loss
Additives with high metallic concentrations which act as oxidation-promoting catalysts can help alle-
viate these adverse side effects, thus, theoretically allowing increased flexibility of NOX reducing
combustion modifications (References 4-131 and 4-132). This concept has yet to be investigated, but
could result in lower NOX emissions. Some of the benefits of fuel additives toward NO reduction are
X
listed in Table 4-23. Most of these additives are used in utility and large industrial boilers.
4-82
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TABLE 4-23. FUEL ADDITIVES WITH POSSIBLE PERIPHERAL BENEFITS TO NO..
CONTROL TECHNIQUES IN BOILERS
Additive Function
Combustion improver
00
OJ
Corrosion inhibition
Antifoul ing
Soot, smoke and carbon
particulate reduction
Possible Benefits to
NO Control Techniques
Increased flexibility of:
Low excess air
Off stoichiometric combustion
Flue gas recirculation
Alternate fuel usage
Combination of the above
Increased flexibility of:
Low excess air
Off stoichiometric combustion
Alternate fuel usage
Combination of the above
Increased flexibility of:
Low excess air
Off stoichiometric combustion
Increased flexibility of:
Low excess air
Flue gas recirculation
Off stoichiometric combustion
Applicable Fuel
Distillate and residual oils,
coal, mixed fuels
Residual oil and coal
Residual oil and coal
Distillate and residual
oil, coal
Manufacturer Suggested
Addition Rate
Oil -0.01 to 0.1 mol %
Coal -0.01 to 0.02 wt ?.
Oil - 0.01 to 0.1 mol %
Coal - -0.005 wt %
Oil - 10 to 1,000 ppm
Coal -0.01 to 0.02 wt %
Oil -0.92 to 0.96 g/1
Coal - -0.04 wt %
-------
In summary, the results of recent studies on fuel additives for NOX control have been mixed.
In some cases additives had a significant effect on NO emissions, while in other studies they did not.
Overall, the use of additives for controlling NOX* is not attractive due to added cost, serious op-
erational difficulties and the presence of the additives as pollutants in the exhaust gas. However,
it has been proposed that some fuel additives may provide a peripheral benefit to NOX control, by
allowing increased flexibility in applying combustion modification techniques. The potential for
adverse environmental impacts due to this practice will be considered in the NOX E/A.
4.5 ALTERNATE AND MIXED FUELS
One alternate NO reduction method involves the use of a fuel with a low-nitrogen content
(to suppress fuel NO ) and/or one that burns at a lower temperature (to reduce thermal N0x). Fuels
with relatively small amounts of sulfur and chemically-bound nitrogen are referred to as "clean"
fuels, and are most desirable from an environmental point of view.
Natural gas firing (a "clean" fuel) is an attractive NO control strategy; it produces no
X
fuel NO and it provides flexibility for implementing combustion modification techniques. However,
since natural gas is becoming increasingly scarce, many large users are having to switch to coal.
At present, coal contributes only about 18 percent of the energy utilized in the U.S. annually,
but the production of coal has been projected to increase 72 percent from 56.1 Tg (618 x 106 tons) in
1974 to 94.4 Tg (1,040 x 10s tons) in 1985 (Reference 4-133). Since the direct combustion of coal
adversely affects the environment, there is a tremendous research effort directed toward making cleaner
fuels not only from coal, but also from other sources. A brief discussion on combustion experience
with these fuels and on the prospects for low NO emissions follows.
4.5.1 Western Coals
The direct combustion of western subbituminous coals in large steam generators generally pro-
duces lower N0x emissions. Three mechanisms are responsible for lower NO emissions: first, western
coals, in general, contain less bound nitrogen than eastern coals on a unit heating value basis;
second, the excess 02 in a steam generator burning western coal can be maintained at very low levels;
and third, the high moisture content of western coal produces lower flame temperatures.
N0x emissions for an 88 MW (130,000 Ib steam/hr) industrial boiler firing pulverized western
coal at baseline conditions were 24 percent lower than for eastern coals (Reference 4-48). NO emis-
sions remained unchanged when firing western coal in stokers. However, the slope of the NO vs. ex-
cess 02 curve for a water-cooled vibrating grate stoker firing western coal (Wyoming Bighorn) was
12 ppm/percent excess 02. compared to 35 ppm/percent excess 02 for eastern coal (Kentucky Vogue).
4-84
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Some specific problems associated with burning low-sulfur, high moisture content coals in
combustion equipment designed for higher quality coals are listed below (Reference 4-134):
• Poor ignition
• Reduced boiler load capacity
• Increased carbon loss
• Boiler fouling
t High superheat steam temperature
• Flame instability
• Increased boiler maintenance
• Reduced boiler efficiency
• Reduced collection efficiency of electrostatic precipitator (ESP)
4.5.2 Low-Btu Gas
NO emission data are sparse for low-Btu gas, defined here as having a net heating value of
3.0 to 5.9 MJ/nm3 (75 to 150 Btu/scf). The data available from combustion equipment firing low-Btu
gas show that NO emissions from a 1.3 MW (4.5 x 10s Btu/hr) furnace firing 100 percent low-Btu gas
X
were below 10 ppm (Reference 4-135). The same furnace burning 100 percent natural gas produced
60 ppm NO. The lower NO emissions, ranging from 0 to 10 ppm for NO, when burning low-Btu gas were
attributed to both decreased peak temperature and decreased combustion intensity. The NO emissions
were obtained using an experimental combustor can and air preheat temperatures up to 1070K (1.250F)
to simulate gas turbine conditions. Compared to natural gas and No. 2 oil, a 50 to 65 percent re-
duction in NO emissions for a 70 to 80 MW gas turbine firing low-Btu gas was projected (Reference
4-136). The fuel nitrogen cleanup of this low-Btu gas involves removing mainly NH3 (also 30 to over
50 percent of the gas is N2). The level of NH3 in the gas depends on the particular coal and gasi-
fication process used.
4-5.3 Medium- and High-Btu Synthetic Gas
Medium-Btu gas (having a heating value of about 11.8 MJ/nm3 or 300 Btu/scf) is being considered
for direct firing, after cleanup, in utility boilers located at the gasifier site with only minor
modifications to current state-of-the-art combustion equipment (Reference 4-137). Another possibility
being evaluated is burning this gas in oxygen-fired steam generators. Since bulk oxygen is needed
for the gasifier, the additional cost to supply the steam generator should not be prohibitive, but
this type of combustion process will require considerable boiler design changes.
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Medium-Btu gas and oxygen should produce combustion temperatures greater than 2790K (4.000F),
but the total NO production should still be Insignificant since molecular and fuel nitrogen are
absent (Reference 4-138).
Medium-Btu gas can be upgraded to high- (35.4 to 39.4 MJ/nm3 or 900 to 1,000 Btu/scf) Btu gas.
High-Btu gas is indistinguishable from natural gas, except it may form fuel NOX if any bound nitrogen
(NH3, HCN, etc.) is present.
4.5.4 Synthetic Oil from Coal
The physical and chemical properties of synthetic oil are a function of the coal properties
and processing conditions. Direct combustion of the oil without pretreatment represents an environ-
mental problem, since the oil typically has a high nitrogen content (0.7 to 1.8 percent by weight).
This percentage of nitrogen corresponds to 400 to 1,000 ppm of NOX emissions, based on 40 percent
fuel nitrogen conversion, and would require the use of combustion modifications to reduce NO to
acceptable levels (Reference 4-135).
4.5.5 Coal-Oil Slurry
The need to stretch domestic oil supplies has renewed government interest in using coal-oil
slurries for direct combustion in steam-generating equipment. Coal-oil slurries could be made en-
vironmentally acceptable, depending on the quantities of pollutants present in the coal and oil and
the percentages of coal and oil used in the slurry. A General Motors program investigating the use
of coal-oil slurries concluded that emissions of oxides of nitrogen increase with increasing coal
concentration and decreasing coal particle size (Reference 4-139). The quantity of coal that can be
used is limited by slurry stabilization, combustion equipment performance, and environmental aspects
(Reference 4-140).
4.5.6 Methanol
Currently, the synthesis of methane from natural gas is the major source of methanol. But
due to the shortage of natural gas, future production will have to come from synthetic gas generated
from coal. Baseline NOX emissions from the combustion of methanol in an experimental hot wall fur-
nace system were reported at 50 to 70 ppm, compared to 240 to 300 ppm for distillate oil. With flue
gas recirculation, the NOX emissions from methanol combustion were reduced to 10 ppm or 15 percent
of the baseline level (Reference 4-141). The hot wall experimental furnace also showed a 20 percent
increase in stack heat loss (SHL), compared to SHL of 14 percent for distillate oil (based on 115
percent theoretical air at a 475K stack temperature). In gas turbines 74 percent less NO was
4-86
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produced using methanol, compared to distillate oil. Turbine efficiency levels increased by
6 percent due to higher inlet temperatures.
Methanol is generally a potentially attractive fuel for use in area sources where clean
fuels are necessary for environmental reasons. Its current high price does not justify its use.
4.5.7 Water-Oil Emulsions
Residual oil emulsions with up to 35 percent water were fired in a Scotch packaged boiler
rated at 700 kW (2.5 x 10s Btu/hr). NOX emissions were not reduced from the baseline level (oil
only) for a given stoichiometric ratio. This was attributable to the high nitrogen content of
the residual oil; emulsions affect only thermal NOX (Reference 4-142). In the same experiments,
because of the reduction in smoke levels, the boiler could be operated at a lower stoichiometric
ratio, which reduced the NO emissions.
Emulsions have a definite NO reduction potential when distillate oil is used (Reference
4-143). NO emission levels from emulsions with approximately 50 mass percent water in distillate
oil approached the levels obtained from methanol combustion (Reference 4-135).
In conclusion, the feasibility of alternate fuel firing as a NO control option is contingent
in part on the cost trade-off between synthetic fuel production and the total control costs for NO
SO and particulates in conventional coal firing. There is preliminary evidence that gasification
may be more costly than flue gas cleaning of conventional systems.
4.6 ALTERNATE CONCEPTS
The recent domestic shortages in conventional clean fuels, the rising cost of oil and gas,
and above all, the need to limit the pollutant emissions resulting from burning fossil fuels have
accelerated the development of alternate energy concepts. Some concepts (e.g., catalytic combustion,
fluidized bed combustion, and gasifier combined cycle) are being developed for their potential not
only to increase system efficiency, but also to reduce total system emissions. Other alternate con-
cepts (e.g., repowering, high temperature gas turbines) are being developed mainly to increase ef-
ficiency and reduce fuel consumption.
Catalytic combustion systems and high temperature gas turbine developments are well underway.
Within the next decade catalytic combustion may find use in gas turbines and space heating; high
temperature gas turbines are expected to be commercially available in the late 1980's.
Fluidized bed combustion and combined cycle development are also in progress. Several organ-
izations are building pilot-scale fluidized bed combustion units, and commercialization of fluidized
bed combustors may take place during the late 1980's.
4-87
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Another alternate concept, repowering, is a method of upgrading existing power plants to make
them more competitive at today's fuel prices or to make more efficient use of present fuel contracts;
prospects for widespread use of this concept are presently uncertain.
4.6.1 Catalytic Combustion
Catalytic combustion refers to combustion occurring in close proximity to a solid surface which
has a special (catalytic) coating. A catalyst accelerates the rate of a chemical reaction, so that
substantial rates of burning should be achieved at low temperatures, avoiding the formation of ther-
mal NO . Moreover, the catalyst itself serves to sustain the overall combustion process, thereby
minimizing the stability problems (Reference 4-144 and 4-145). However, the overall success of a
catalytic combustion system in reducing CO and HC to low levels is a function of both heterogeneous
and gas phase reactions; surface reactions alone appear to be unable to achieve the desired low levels.
Emissions from catalytic combustion experiments have typically been: N0x < 2 ppm, HC = 4 ppm,
and CO = 10 to 30 ppm. Both gaseous and distillate fuels have been used and combustion efficiencies
above 95 percent have been obtained (Reference 4-145).
The catalyst bed temperature must be held below 1810K (2800F) to minimize the formation of
N0x. At high temperatures, above 1275K (1.830F), catalyst activity decreases. At present, cata-
lytic combustors are limited by the bed temperature capability. Excess air can be used to lower the
bed temperature; but the use of excess air is unattractive since it also reduces thermal efficiency
(except in gas turbines). Further research is underway to consider other systems, such as catalyst
bed cooling, exhaust gas recirculation, and staged combustion to maintain a low bed temperature.
Recent tests evaluated the applicability of catalytic combustors for gas turbines. Test
fuels used were No. 2 distillate oil and low Btu synthetic coal gas, for a range of pressure,
temperature, and mass flow conditions. Test results show that the catalyst bed temperature profile
at the bed exit was very uniform for low Btu gas, but not as uniform for No. 2 oil. Exceptionally
low emissions (2 to 3 ppm NO. 20 to 30 ppm CO) were achieved for both fuels, and unburned hydro-
A
carbons (HC) were less than 1 ppm (Reference 4-146). However, much additional work is needed be-
fore catalytic combustion can be applied to gas turbines in the field.
Catalytic combustion has been demonstrated to be effective in lowering emissions of pollutants
such as NOX, CO, and HC, but at present, catalytic combustors are limited by the catalyst bed tempera-
ture capability. Various government agencies and private industries are developing catalysts that
will withstand high temperatures, retain high catalyst activity, and last longer. Catalyst combustion
systems are also under development. It appears that during the next 5 to 10 years, catalyst combus-
tion concepts may be incorporated into new gas turbine and residential and commercial heating designs.
4-E
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4.6.2 Fluidized Bed Combustion
In its simplest form, a fluidized bed combustor (FBC) contains a bed of granular material such
as coal, ash and sand or limestone. Hot air is blown through a distributor in the base of the com-
bustor vessel to "fluidize" the solid particles (I.e., the particles are supported by the gas stream
and in rapid motion relative to each other). This process creates a bed which has the appearance of
a boiling liquid and exhibits many fluid-like properties.
For coal-fired FBCs, if the temperature of the bed remains above the combustion temperature
of the coal, the FBC process will be self-sustaining. The bed temperature is generally in the range
of 1075 to 1275K (1.500F to 1.900F) and the combustor may be at atmospheric pressure (AFBC) or it
may be pressurized (PFBC) (References 4-147 and 4-148). Energy added to the bed by the combustion
process is removed, in a fluidized bed boiler, by the boiler tubes, heat losses through the walls,
and the gas and solids leaving the bed.
A 30 MW AFBC pilot plant began operation in late 1976 (Reference 4-149). Pressurized sys-
tems are still being tested, with a pilot plant planned for the early 1980's.
NO emissions in fluidized bed systems depend on the equipment; significant emissions have
X
been found in some reactors (Reference 4-32). NO emissions also depend, though weakly, on coal
particle size, the type and amount of sulfur acceptor, and the amount of excess air. However, emis-
sion levels from pressurized fluidized bed combustors are significantly less than from atmospheric
combustors, probably due to greatly increased NOX decomposition rates at elevated pressures.
NO levels in most coal-fired fluidized bed experiments conducted at atmospheric pressure
are on the order of 300 to 500 ppm (Reference 4-150). NO emissions from a pressurized FBC, even at
100 percent excess air, are well below the current standards of 300 ng N02/J (0.7 lb/106 Btu).
Results of 160 ng/J (0.41 lb/106 Btu) have been reported (Reference 4-149). The principle disad-
vantages of FBCs, are (1) potentially large amounts of solid waste (the sulfur acceptor material)
and (2) heavy particulate loadings in the flue gas. The feasibility of an FBC for power generation
will depend on developing
• Efficient methods for regeneration and recycling of the dolomite/limestone materials used
for sulfur capture and removal
• Complete combustion through flyash recycle or an effective carbon burnup cell
• A hot-gas particulate removal process to permit use of the combustion products in a com-
bined cycle gas turbine without excessive blade erosion
4-89
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4.6.3 Repowering
Repowering adds a combustion turbine to an existing steam plant, providing additional capacity
at lower initial capital costs and lower energy costs than other means available to a utility.
Repowering includes: (1) steam turbine repowering, in which gas turbines and new heat re-
covery boilers are added to an existing steam electric generating plant; (2) boiler repowering in
which gas turbines are added to the existing steam generating facilities for power generation, re-
quiring the conversion of existing conventional boilers to heat recovery type boilers; and (3) gas
turbine repowering in which a steam generating plant is added to an existing gas turbine plant
(References 4-151 and 4-152).
Depending on the system and power needs, repowering of existing facilities offers the follow-
ing advantages:
• There is no need to acquire and develop a new plant site
t Repowering generally requires smaller increments of investment, saving on fixed charges
since major investment on new plants is deferred
• Repowering improves heat rate, which lowers fuel consumption
• The environmental impact is reduced, with improving schedules for" environmental and site
related approvals
t For boiler and steam turbine repowering, there is no increase in cooling water requirements
• Gas turbines may be operated independently as peaking units, which provides greater plant
flexibility
References 4-151 and 4-152 describe in detail the application of repowering to boiler, gas
turbine, and steam generating plants; savings in capital and operating costs are anticipated. Under
contract from the Electric Power Research Institute, Westinghouse Electric Corporation is evaluating
repowering conventional steam power plants without replacing the boiler. The present use of repower-
ing is very limited. It may see extensive use in the 1980's if significant increases in generating
capacity are needed.
4.6.4 Combined Cycles
Combined cycles may, in the long term, reduce emissions of sulfur oxides, nitrogen oxides,
particulate matter, and waste heat while generating power at efficiencies higher than conventional
fossil- and nuclear-fueled steam stations (Reference 4-153).
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The combined gas and steam turbine system consists of a gas turbine using a coal-deHved fuel,
which exhausts Into an unflred waste-heat-recovery boiler. At the gas turbine Inlet, the most
economical large-scale steam system would operate at 16.5 MPa (2,400 pslg) with 810K (l.OOOF) throt-
tle steam and 810K (l.OOOF) reheat temperatures. In this system, roughly 66 percent of the power
would be generated by the gas turbine; the remaining 34 percent would be generated by the steam
boiler system (Reference 4-154).
Combined cycle efficiency Improves significantly as the gas turbine Inlet temperature is in-
creased. At turbine inlet temperatures of 1,478K (2.200F), an efficiency improvement of 2 percentage
points per 56K (100F) increase in turbine inlet temperature is found.
A feasibility analysis on combined cycle systems was conducted by Solar, a division of Inter-
national Harvester. The analysis showed that with the presently available steam turbines and boilers,
the efficiencies would not be sufficient to justify a combined cycle. Therefore, Solar is developing
new small steam boiler and turbine designs which are expected to be available by 1980. Applications
of combined cycles include pipeline, offshore platform, marine, and small electric utilities
(Reference 4-155).
The current status of combined cycles has been reviewed by Papamarcos (Reference 4-156). Ac-
cording to Papamarcos, before combined cycles are commercialized, efficient fuel conversion processes
and high temperature gas turbines that can use coal-derived fuels must be developed. He estimates
that these developments will take place in some 15 to 20 years, and current ERDA projections concur
with his estimate.
4.6.5 High Temperature Gas Turbines
The efficiency and power output of a gas turbine increase significantly as the inlet tempera-
ture is increased. Turbines that are used in the field are limited to 1075 to 1275K (1,500 to 1,800F)
by the strength of the turbine materials. A gas turbine firing stoichiometrically at temperatures
above 1.920K (3.000F) would increase power output by more than 150 percent, and thermal efficiency
relative to conventional units. However, performance gains at higher temperatures can be realized
only if losses caused by the cooling system can be kept to a minimum (Reference 4-157).
The current practice of turbine cooling, using air bled from the compressor, requires bring-
ing the cooling air to the required pressure. The power output is reduced, since a substantial
Portion of the cooling air reenters the gas downstream of at least one of the bucket stages. Moreover,
once the cooling air reenters the gas, it decreases the gas temperature, which reduces the energy
available to the turbine and to the heat recovery system in the exhaust stack (Reference 4-156).
4-91
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Because a high temperature gas turbine has higher potential for Increased efficiency and
specific output, various methods which allow high temperatures are being considered. These are:
• Water cooling
• Advanced air cooling
t Steam cooling
0 Substitution of ceramic compounds
In current programs, ERDA is funding four turbine manufacturers (General Electric, Westing-
house, Curtiss-Wright, and United Technology) to develop a high temperature turbine technology
(HTTT). And more recently, EPRI has funded a HTTT program at GE. The main emphasis of these pro-
grams is to develop the high temperature portion of the gas turbine for firing temperatures of
1.700K (2,600F) and possibly up to 1,920K (3,OOOF).
Efficiency will be improved and specific costs will be reduced over the next 5 to 10 years
in high temperature gas turbine technology. Leading gas turbine manufacturers are designing high
temperature gas turbines that can be operated up to 1.920K (3.000F) with cooling of the blades. To
cool the blades, water cooling appears to be the most attractive method.
4.7 FLUE GAS TREATMENT
Flue gas treatment (FGT) processes reduce NO emissions from combustion sources through either
X
decomposition or oxidation/absorption. Flue gas treatment has potential for use with combustion
modifications when very high removal efficiencies are required. Much of the developmental work in
FGT has been done in Japan (References 4-61, 4-107, and 4-158 through 4-164).
FGT is currently applied to only a few commercial gas- and oil-fired boilers. Research in the
United States in developing flue gas treatment has been minimal, since needs have been uncertain.
However, the recent emphasis of stationary source NO emission controls has encouraged further de-
velopment of FGT in the United States (Reference 4-165).
FGT processes can be divided into two main categories: dry processes and wet processes. Dry
processes reduce NOX by catalytic reduction and operate at about 525K (700F). Wet systems remove
NOX by oxidation followed by scrubbing, and operate at 315 to 325K (100F to 120F). Table 4-24
summarizes the available wet and dry processes.
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TABLE 4-24. SUMMARY OF F6T PROCESSES
Process
Process Description
Comments
Dry Processes:
Hitachi shipbuilding
process
Selective reduction
with ammonia
Hydrogen sulfide process
Char (Bergbau - Fors-
chung - Foster Wheeler
Process)
CuO (Shell/UOP
flue gas desulfuriza-
tion process)
CO and H2 in the presence of
catalysts selectively reduce
NOX. CuO, F6203, Cr203, NiO,
C0304, MnO, V205, and Pt are
various catalysts that can be
used.
NH3 and 62 in the presence of
catalysts, reduce MOX to MO.
Pt, Vanadia, Fe-Cr oxide mix-
tures, Mo, Cu-Pb are some of the
catalysts used.
Selective catalytic reduction of
NOX in the presence of H2S (gas
phase)
A dry adsorption process.
S02, 02 and HjO in flue gas
are adsorbed in the char pores.
Adsorbed S02 reacts with 02 and
H20 to form 1^04 which is re-
tained by char pellets. NOX
is also absorbed by char.
CuO reacts with S02 in the pre-
sence of 02 at 670K to yield
CuS04
About 98% reduction can be obtained.
No wastestreams are produced.
Major drawback is that this process
requires catalysts which have the
selective behavior for promoting
faster CO/H2 - NO reaction than
CO/H2 - 02 reaction.
Above 90% reductions are achieved.
This process removes NO- and SOX
simultaneously. Careful tempera-
ture control (480K-590K)
is necessary.
NOX reductions up to 98% are ob-
tained. Removes NOX and SOX simul
taneously. Condensation of sulfur
causes catalyst to lose activity.
100% use of H2$ is important since
it is toxic.
High removal rate (95%) for SOX;
only 40-65% of NO- is removed.
S02 can be reduced directly to
elemental sulfur.
Effective for SOX removal (90%),
removes 60-70% of NOX. Low pres-
sure drop through parallel flow
sorbent bed. Easy regeneration
of sorbent. No particulate
interference.
Wet Processes:
Sodium scrubbing
(Fujikasui process)
Alkali permanganate
(MON process)
Sodium-potassium
permanganate (Nissan
process)
Alkali scrubbing
(Shinko process)
Gaseous C102 oxidizes NO to
N02. N02 scrubbed with NaC102-
NOX and SO? absorbed and
oxidized with alkali permanga-
nate to form alkali nitrate
and sulfate
Two-step method. NOX is
removed with NaOH. Off-gas
is oxidized with permanaganate
and N02 absorbed with NaOH.
NOX is scrubbed first with
liquid NaOH; off-gas is sent
to second scrubber - a packed
granular alumina reactor
sprayed with NaOH and NaC102
Over 90% NOX reductions. Low cost
and easy operation, but requires
waste water treatment because of
by-product effluents.
and
Over 90% NOX removal and virtually
all of S02- No waste material is
produced. Scrubbing agent (alkali
KOH) is expensive.
High removal rate (90%) of NOX.
Easy and flexible operation.
Byproduct potassium nitrate is a
fertilizer; however, waste water
treatment is required.
Over 95% of NOX removed with pro-
ducts of NaNOs, NaCl and gaseous
C102- However, NaC102 is expensive.
(Continued on page 4-94)
4-93
-------
TABLE 4-24. Concluded
Process
Process Description
Comments
CO
in
Chiyoda Thoroughbred 102
Alkali scrubbing
(Kyowa Kako)
Sodium sulfite
scrubbing
MHI (Mitsubishi Heavy
Industries)
Kureha reduction
Kawasaki magnesium
Chisso ammonia
scrubbing
Kobe steel process
NO is oxidized by ozone and air.
Aqueous ^504 with an iron cata-
lyst act as scrubbing agents.
NOX is first scrubbed with
NaOH, off-gas is oxidized with
H?02, and then washed with
alkaline hydrogen sulfide or
alkali sulfide
Sodium sulfite reduces NOX to
N2
Ozone is injected into flue
gas; NOX is oxidized to
NgOs; this is reduced to N£
by reacting with CaSOa in the
circulating scrubber liquor
NOX is scrubbed using 3
scrubbers: sodium acetate,
limestone slurry, and sodium
sulfate and sulfite contain-
ing acetic acid and a cata-
lyst
Magnesium hydroxide slurry is
used as a scrubbing agent to
remove NOX
NOX is removed using ammonia-
cal solution containing a
soluble catalyst
Calcium chloride solution
containing Ca(OCl)2 is used to
reduce NOV
About 60% NOX removal efficiency.
Simple and easy operation. How-
ever, a relatively low efficiency
NOX removal process and requires
wastewater treatment and expensive
ozone. Additional equipment needed
to remove ozone from the exit gas
stream.
High NOX removal (from 4,000 ppm
down to 50 ppm), but requires
waste water treatment and sludge
disposal
Over 90% NOX reduction. Absorbs NO
directly, thereby eliminating costly
oxidizing agents. Large flowrates
and excess D£ hinders NOX reduction.
Simple process, high (over 90%) NOx
removal. Does not produce waste
water. However, production of
ozone and the use of high concen-
tration of HNOs are costly.
Removes NOX and SOX simultaneously.
Produces useful gypsum and no waste
water streams. However, it is a
complex process; and costly.
Removes both NOX and SOX. Produces
marketable gypsum and calcium nitrate.
Process is complex and costly.
About 60 to 80% of NOX is removed.
Produces byproduct ammonium
sulfate. Possibility exists
for plume formation.
High NOX removal efficiency is
attained. Scrubber corrosion is a
problem.
4-94
-------
4.7.1 Dry FGT Processes
Dry processes are mainly applied to flue gas streams derived from burning gaseous fuels. Each
process developer utilizes different catalysts, catalyst supports, and bed configurations. Dry pro-
cesses are basically simple, require little space, and require no reheating of the tailgases.
Among the many dry process variations, selective catalytic reduction using ammonia has been
successful in treating combustion flue gases for removal of NO . However, the large amounts of
X
ammonia required would increase the consumption of natural gas considerably. In addition, any
ammonia left in the flue gases may combine with the S03/S(L to produce a visible plume, and by-
products, such as ammoniuni-bisulfate, which are corrosive to boiler tubes.
Molecular sieve adsorption is another dry FGT process identified as a possible NO control
technique; however, it was developed primarily for noncombustion applications, such as nitric acid
manufacturing plants. Molecular sieve adsorption is not applicable to the water-containing effluents
from combustion sources due to preferential adsorption of moisture and a resultant loss of active
sites (Reference 4-166).
4.7.2 Het FGT Processes
Wet FGT processes utilize more complex chemistry than dry processes (Reference 4-165). In
the wet processes, strong oxidants such as ozone or chlorine dioxide are used to convert the rel-
atively inactive NO in the flue gas to N02 or NpOg for subsequent absorption. Thus, most of the
wet processes create by-products such as nitric acid, potassium nitrate, ammonium sulfate, calcium
nitrate, and gypsum.
Wet FGT processes use either liquid or gaseous chemicals to complete the required NO oxidation.
Liquid phase oxidation requires extensive liquid/gas contact to absorb the inactive NO, thus the use
of liquid phase oxidation processes is limited, because of the large size and pressure drop of the
NO absorber.
Using ozone or chlorine dioxide to oxidize NO in the gas stream prior to the scrubber appears
to be a more successful approach. Chlorine dioxide is expensive, however, and using it introduces
the problem of disposing of chloride-containing liquid discharges. Ozone is also quite costly,
requiring a great deal of electrical energy to produce. Also, where ozone is utilized, additional
equipment is required for removal of excess ozone from the final gas stream. Thus, oxidant cost is
likely to be prohibitive for flue gases with high NOX concentrations.
4-95
-------
Cost estimates for FGT processes are presented in Table 4-25, but these estimates are only
preliminary since most FGT processes are in the developmental stages in the U.S. Compared to com-
bustion modifications, FGT is considerably more expensive, but is capable of greater N0x reduction.
Increased costs result from both higher capital costs and costs of chemicals and catalysts.
In general, the dry FGT techniques used in Japan can probably be applied to gas- and oil-fired
sources in the U.S. However, more pilot scale research and field tests are needed before full im-
plementation of dry processes is possible. Also, the applicability of dry processes to coal-fired
sources remains to be determined. Wet processes are less well developed and costlier than dry FGT
processes, however, wet processes have the potential to remove NO and SO simultaneously. Again,
A A
more field tests are needed to determine the costs, secondary effects, reliability, and waste disposal
problems. Flue gas treatment holds some promise as a control technique for use when high NOX removal
efficiencies are necessitated by stringent emission standards.
Ammonia injection, discussed in Section 4.2.9, is a competitive process which may prove more
cost effective for NOX control. Ammonia injection is not applicable to simultaneous NOX/SOX reduc-
tion, however.
4.8 EVALUATION AND SUMMARY
Table 4-26 summarizes current and emerging NOX control technology for the major source categories.
These results show that current technology is dominated by combustion process modification. Emerging
technology is also centered around combustion modifications. Other approaches, such as flue gas treat-
ment, may be used in the 1980's to augment combustion modification if required by stringent emission
standards.
The level of combustion modification control available for a given source depends largely on
the importance of that source in regulatory programs. Utility boilers have been the most extensively
regulated and accordingly, the technology is the most advanced. Available technology ranges from
operational adjustments such as low excess air and biased burner firing to inclusion of overfire air
ports or low-NOx burners in new units. Some adverse operational impacts have been experienced with
use of combustion modification on existing equipment. In general these have been solved through
combustion engineering or by limiting the degree of control application. With factory-installed
controls on new equipment, operational problems have been minimal.
The technology for other sources is less well developed. Control techniques shown effective
for utility boilers are being demonstrated on existing industrial boilers. Here, as for utility
boilers, the emphasis in emerging technology is on development of controls applicable to new unit
design. Advanced low-NOx burners and/or advanced off-stoichiometric combustion techniques are the
4-96
-------
TABLE 4-25. 1974 COST ESTIMATES FOR COMBUSTION FLUE GAS TREATMENT
PROCESSES (Reference 4-160}
Process
Type
Met
Wet
Dry: selective
catalytic
reduction
Dry: selective
catalytic
reduction
Process
Chiyoda Thorough-
bred 102
Sumitomo
(Mo re tana)
Sumi tomo
Sumi tomo
Hitachi
Application
Oil-fired boiler
Oil-fired boiler
Gas-fired boiler
Oil-fired boiler
Oil-fired boiler
Estimated
Capital
Costs
$70-90/kW
$70-100/kW
$40/kW
$93/kW
$60/kW
Estimated
Operating
Costs
(mill/kWhr)
3-4
7
1.2
No Data
No Data
-------
TABLE 4-26.
SUMMARY OF N0x CONTROL TECHNOLOGY
ID
o>
Equipment/
Fuel
Category
Existing coal-
fired utility
boilers
New coal -fired
utility
boilers
Existing oil-
fired
utility
boilers
Existing
gas -fired
utility
boilers
Oil-fired
industrial
watertube
boilers
Current Technology
Available
Control
Technique
LEA + OSC
(OFA, BOOS,
BBF); new
burners
LEA + OFA;
new
burners
LEA + OSC
+ FGR;
load re-
duction
LEA + OSC
+ FGR;
load re-
duction
LEA + OSC
(OFA,
BOOS,
BBF)
Achievable
NOX Emission
Level ng/J
(lb/106 Btu)
260-300
(0.6 - 0.7)
215-260
(0.5 - 0.6)
110-150
(0.25 - 0.35)
65-85
(0.15 - 0.2)
85-130
(0.2 - 0.3)
Estimated
Differential
Annual Cost
20-30
-------
TABLE 4-26. Continued
Equipment/
Fuel
Category
Stoker-fired
industrial
watertube
boilers
Gas-fired
industrial
watertube
boilers
Industrial
f i retube
boi 1 ers
Gas turbines
Current Technology
Available
Control
Technique
LEA + OFA
LEA + OSC
(OFA, BOOS,
BBF)
LEA + FGR;
LEA + OSC
Water,
steam
injection
Achievable
NOX Emission
Level ng/J
(lb/10s Btu)
150-190
(0.35 - 0.45)
86-130
(0.2 - 0.3)
65-110
(0.15 - 0.25)
110-150
(0.25 - 0.35)
\
Estimated
Differential
Annual Cost
1.8-2.34/
(kg/hr)a
1.4-1.B4/
(kg/hr)a "
7-14*/ ,
(ka/hr)a
$l-2/kW
Operational
Impact
Possible
~}% increase
in fuel con-
sumption;
corrosion;
slagging of
grate
(retrofit)
-1% increase
in fuel con-
sumption;
flame
instability;
boiler vi-
bration
(retrofit)
~1% increase
in fuel con-
sumption;
flame insta-
bility
(retrofit)
~1% increase
in fuel con-
sumption;
affects only
thermal
Emerging Technology
Near Term
1977-1982
Inclusion of
OFA in new
unit design
Low NOX bur-
ners; OFA in
new unit
design
Low NOx burn-
ers; OFA or
FGR in new
unit design
Advanced com-
bustor de-
signs for
dry NOX con-
trols
Far Term
1983-2000
Fluidized bed
combustion;
ammonia
injection
Optimized
burner/firebox
design; ammonia
injection
Optimized
burner /f i rebox
design
Catalytic com-
bustion; ad-
vanced can
designs
Comments
Current technology
still being
developed
Current technology
still undergoing
development
Development continuing
on current technology
Current technology
widely used
(Continued on page 4-100)
-------
TABLE 4-26. Concluded
Equipment/
Fuel
Category
Residential
furnaces
1C engines
Industrial
process
furnaces
Current Technology
Available
Control
Technique
Low NOX
burner/
f 1 rebox
design
(oil)
Fine
tuning;
changi ng
A/F
LEA
Achievable
NOX Emission
Level ng/J
(lb/106 Btu)
25-40
(0.06 - 0.1)
1 ,070-1 ,290
(2.5 - 3.0)
85-210
(0.2 - 0.5)
Estimated
Differential
Annual Cost
$0.1 4-0. 29/
kW
(4-8 x 10s
BTUPH)
$0.70-2.00/kW
($0.5-1.5/
BMP)
Unknown
Operational
Impact
~5% decrease
in fuel con-
sumption
5-10% in-
crease in
fuel con-
sumption;
misfiring;
poor load
response
Unknown
Emerging Technology
Near Term
1977-1982
Advanced
burner/fire-
box design
(gas & oil)
Include mod-
erate con-
trol in new
unit design
Low NOX
burners;
development
of external
controls
(FGR, OSC)
on retrofit
basis
Far Term
1983-2000
Catalytic
combustion
Advanced head
designs
*
Possible inclu-
sion in new
unit design
Comments
Current technology
still being tested
Technology still being
tested
Control development
in preliminary stages
-p.
I
o
o
akg/hr steam produced
-------
most promising concepts. This holds true for the other source categories as well. The R&D emphasis
for gas turbines, warm air furnaces and reciprocating 1C engines is on developing optimized combustion
chamber designs matched to the burner or fuel/air delivery system. Control development for the diverse
types of industrial process equipment is in a preliminary stage. To date, only minor operational
adjustments have been tried.
Table 4-27 summarizes the status and effectiveness of general control techniques. As noted
above, a number of techniques are applicable for operational adjustments and hardware modifications
of either new or existing units. The trend, however, is toward new burners or off-stoichiometric
combustion in combination with low excess air. This approach yields a higher degree of control, is
more cost effective and minimizes adverse operational impacts.
The final column on Table 4-27 evaluates controls with respect to their treatment in the NO
A
E/A. This evaluation will be discussed further in Section 7.2 where priorities are set on near- and
far-term source/control applications. This evaluation is also used to scope the evaluation of in-
cremental impacts due to NO controls discussed in Section 6.
X
The information in this section initiates the process engineering studies of major source
categories in the NO E/A. The preliminary control evaluation has shown the need for more data in
the following areas:
• Current control technology
- Impact on operation/performance
- Economics/control costs
- Environmental impact
• Emerging control technology
- New operating data as it becomes available
- Economic estimates
— Environmental concerns
The seven process engineering studies to be performed in Task 7247 will focus on these requirements,
while many of the data gaps will be filled under Task 7245 or through related ongoing programs.
Since most of the current technology has been demonstrated on utility and large industrial boilers,
the first two studies to be performed will cover these categories.
One especially important area where more accurate data are needed is in differential control
costs. During the process engineering studies, all cost procedures will be standardized and a
4-101
-------
TABLE 4-27.
OVERALL EVALUATION OF N0x CONTROL TECHNIQUES
o
rvj
Control
Technique
Low excess air
(LEA)
Flue gas recircu-
lation (FGR)
Off stoichiometric
combustion (OSC)
incl. OFA, BOOS,
BBF
Load reduction
Burner
modifications
Existing
Applications
Retrofit and new
utility boilers;
some use in indus-
trial boilers
Retrofit use on
many gas- and oil-
fired utility
boilers; demon-
strated on indus-
trial boilers
New and retrofit
use on many util-
ity boilers; dem-
onstrated on in-
dustrial boilers
Some retrofit use
on gas and oil
utility boilers;
enlarged fireboxes
on new coal units
New and retrofit
use on utility
boilers; demon-
strated on resi-
dential furnaces
Effectiveness
10% to 30% for
thermal and fuel
N0x
20% to 50% for
thermal NO,,; no
effect on fuel
N0x
20% to 50% for
thermal and fuel
NOX
0% to 40% for
thermal NO
30% to 60% for
thermal and fuel
N0x
Operational
Impact
Increase in effi-
ciency; amount lim-
ited by smoke or
CO at very low EA
Possible flame in-
stability; in-
creased vibration
No major impact
with new design;
potential for flame
instability, effi-
ciency decrease,
increased corrosion
(coal -fired) with
retrofit
Decrease in effi-
ciency and power
output; limited by
spare capacity and
smoke formation
No major impact
with new design;
retrofit use con-
strained by firebox
characteristics
Projected
Applications
Widespread use for
efficiency in-
crease; incorpor-
ate into advanced
designs all sources
Possible use in new
industrial boiler
designs
Widespread use in
large boilers; in-
corporate into ad-
vanced designs
Enlarged fireboxes
used in new unit
design; limited use
for retrofit
Incorporate into
advanced designs
utility, industrial
boilers, residen-
tial , process fur-
naces, GT; combine
with OSC
Control
Evaluation
for NOX E/A Effort
Primary emphasis near-
term and far-term appli-
cations (all sources);
combined with OSC & bur-
ner mods for far-term appl .
Primary emphasis near-term
applications large boilers;
possible far-term industrial
boiler application
Primary emphasis near-
term and far-term appli-
cations all sources
Secondary emphasis near-
term applications (boilers);
combined with OSC or burner
mods for far-term appl .
Primary emphasis near- and
far- term applications all
sources
(Continued on page 4-103)
-------
TABLE 4-27. Continued
o
OJ
Control
Technique
Water, steam
injection
Reduced air
preheat (RAP)
Ammonia injection
Fuel
denitrification
Fuel additives
Alternate and
mixed fuels
Existing
Applications
Widely used for gas
turbines
Widespread use in
large turbocharged
1C engines
Demonstrated on
oil- and gas-fired
industrial boilers
Oil denitrification
accompanies desul-
furization for some
large boilers
Fuel additives for
NOX not used
Combustion of low
nitrogen alternate
fuels being
demonstrated
Effectiveness
30% to 70% for
thermal NOV
A
10% to 40% for
thermal NO
40% to 70% for
thermal and fuel
N0x
10% to 40% for
fuel N0x
Generally in-
effective for dir-
ect NOX reduction
Varies
Operational
Impact
Slight decrease in
efficiency; limited
by CO formation;
power output
increases
Slight decrease in
efficiency, in-
crease power output
Retrofit use lim-
ited; possible ad-
verse environmental
impact
No adverse effects
Byproduct emissions
formed
Varies
Projected
Applications
Use in new gas tur-
bines; possible use
in process furnaces
Continued use in
1C engines
Use in large
boilers in some
areas (1980's)
Use of oil de-
nitrification in
large boilers as
supplement to CM
tech.
Additives for cor-
rosion, fouling,
particulate, smoke,
etc. can provide
increased flexi-
bility with CM tech.
on large boilers
Combined cycles and
residential and
commercial heating
systems
Control
Evaluation
for NOX E/A Effort
Primary emphasis near-term
applications, gas turbines;
possible far- term indus-
trial process application
Secondary emphasis
Primary emphasis far-
term application to large
boilers; evaluate impact
with coal firing
Secondary emphasis; eval-
uate as alternate fuel
Secondary emphasis; con-
sider impact of additives
Secondary emphasis far- term
application; evaluate dif-
ferential impact of fuel
switching; transfer results
of other E/A's .
(Continued on page 4-104)
-------
TABLE 4-27. Concluded
I
o
Control
Technique
Catalytic
combustion
Fluidized bed
combustion
Flue gas
treatment (FGT)
Existing
Applications
Only tested in
experimental
combustors
Tested in pilot/
prototype
combustors
Used in Japan on
large boilers
Effectiveness
>90% for thermal
N0x
20% to 50% for
fuel NOX (pres-
surized FBC)
40% to >9Q% for
fuel and
thermal N0x
Operational
Impact
Requires clean
fuel ; combustors
limited by cata-
lyst bed temp.
capability
Requires sulfur
acceptor
Requires temp, con-
trols, catalyst,
scrubbing soln.,
or oxidizing agent;
. possible adverse
environmental impact
Projected
Applications
Gas turbines and
residential and
commercial heating
systems
Combined cycle,
utility boilers,
industrial boilers
(1980's)
Possible supple-
ment to CM for
utility and large
industrial boilers
(1980's)
Control
Evaluation
for NOX E/A Effort
Primary emphasis far- term
applications; compare im-
pact to burner mods, al-
ternate fuels
Transfer results from
FBC E/A; compare impact
to combustion modifications,
conventional combustion
Secondary emphasis; trans-
fer results of other
studies to compare impact
to combustion mods
-------
common basis will be established for detailed costing of NOX control techniques. Thus, a more ac-
curate comparison of cost effectiveness between control options can be made. The first step 1n
future work on Task 7247 will be to focus on establishing this and other standardized procedures.
4-105
-------
REFERENCES FOR SECTION 4
4-1. Environment Reporter, State Air Laws (2V.) Bureau of National Affairs, Inc., Washington, D.C.
4-2. Zeldovich, J., "The Oxidation of Nitrogen in Combustion and Explosions," Acta Physiocheii
URSS. (Moscow!. Vol. 21, 1946 p. 4.
4-3. Bowman, C. T. and D. J. Seery, "Investigation of NO Formation Kinetics in Combustion Pro-
cesses: "The Methane - Oxygen - Nitrogen Reaction" in Emissions from Continuous Combustion
Systems, W. Cornelius and W. G. Agnew, eds, Plenum, 1972.
4-4 Bartok, W., et al., "Basic Kinetic Studies and Modeling of NO Formation in Combustion Pro-
cesses," AIChE Symposium Series No. 126, Vol. 68, 1972.
4-5. Halstead, C. J. and A. J. E. Munro, "The Sampling, Analysis, and Study of the Nitrogen
Oxides Formed in Natural Gas/Air Flames," Company Report, Shell Research et al., Egham,
Surrey, U. K., 1971.
4-6. Thompson, D., et al., "The Formation of Oxides of Nitrogen in a Combustion System,"
presented at 70th National AIChE Meeting, Atlantic City, N.J., 1971.
4-7. Lange, H. B., "NOX Formation in Premixed Combustion: A Kinetics Model and Experimental
Data," presented at 64th Annual AIChE Meeting, San Francisco, 1971.
4-8. Sarofim, A. F. and J. H. Pohl, "Kinetics of Nitric Oxide Formation in Premixed Laminar
Flames," 14th Symposium (International) on Combustion, The Combustion Institute, Pittsburgh,
1973.
4-9. Iverach, D., et al., "Formations of Nitric Oxide in Fuel-Lean and Fuel-Rich Flames,"
ibid., 1973.
4-10. Wendt, J. 0. L. and J. M. Ekmann, "Effect of Fuel Sulfur Species on Nitrogen Oxide Emissions
from Premixed Flames," Comb. Flame, Vol. 25, 1975.
4-11. Malte, P. C. and D. T. Pratt, "Measurement of Atomic Oxygen and Nitrogen Oxides in Jet-
Stirred Combustion," 15th Symposium (International) on Combustion, The Combustion Institute,
Pittsburgh, 1975.
4-12. Mitchell, R. E. and A. F. Sarofim, "Nitrogen Oxide Formation in Laminar Methane Air Diffu-
sion Flames," presented at the Fall Meeting, Western State Section, The Combustion
Institute, Palo Alto, Ca., 1975.
4-13. Bowman, C. T., "Non-Equilibrium Radical Concentrations in Shock Initiated Methane Oxida-
tion," 15th Symposium (International) on Combustion, The Combustion Institute, Pittsburgh,
1975.
4-14. Fem'more, C. P., "Formation of Nitric Oxide in Premixed Hydrocarbon Flames," 13th
Symposium (International) on Combustion, The Combustion Institute, Pittsburgh, 1971.
4-15. MacKinnon, D. J., "Nitric Oxide Formation at High Temperatures," J. APCA, Vol. 24, No. 3,
March 1974, pp. 237-239.
4-16. Heap, M. P., et al., "Burner Criteria for NOX Control; Volume I - Influence of Burner
Variables on NOX in Pulverized Coal Flames," EPA 600/2-76-061a, NTIS-PB 259 911/AS,
March 1976.
4-17. Bowman, C. T., et al., "Effects of Interaction Between Fluid Dynamics on Chemistry or
Pollutant Formation in Combustion," in Proceedings of the Stationary Source Combustion
Symposium; Volume I - Fundamental Research, EPA 600/2-76-152a, NTIS-PB 256 320/AS,
June 1976."
4-18. Shaw, J. T. and A. C. Thomas, "Oxides of-Nitrogen in Relation to the Combustion of Coal,"
presented at the 7th International Conference on Coal Science, Prague, June 1968.
4-106
-------
4-19. Pershing, D. W., et al., "Influence of Design Variables on the Production of Thermal and
Fuel NO from Residual Oil and Coal Combustion." AIChE Symposium Series. No. 148, Vol. 71,
1975 j pp. 19~29.
4-20.
Sarofim, A. F., et al., "Mechanisms and Kinetics of NOX Formation: Recent Developments,"
presented at 65th Annual AIChE Meeting, Chicago, November 1976.
4-21. Martin, G. B., and E. E. Berkau, "An Investigation of the Conversion of Various Fuel
Nitrogen Compounds to Nitrogen Oxides in Oil Combustion," presented at 70th National AIChE
Meeting, Atlantic City, N.J., August 1971.
4-22. Habelt, W. W. and B. M. Howe11, "Control of NO Formation in Tangentially Coal-Fired Steam
Generators," in Proceedings of the NOX Control Technology Seminar, EPRI SR-39, February 1976.
4-23. "Air Quality and Stationary Source Emission Control," U. S. Senate, Committee on Public
Works, Serial No. 94-4, March 1975.
4-24. Pohl, J. H. and A. F. Sarofim, "Fate of Coal Nitrogen During Pyrolysis and Oxidation,"
in Proceedings of the Stationary Source Combustion Symposium; Volume I - Fundamental
Research. EPA 600/2-76-152a, NTIS-PB 256 320/AS, June 1976.
4-25. Heap, M. P., et al., "The Optimization of Burner Design Parameters to Control NOX Formation
in Pulverized Coal and Heavy Oil Flames," in Proceedings of the Stationary Source Combus-
tion Symposium; Volume II - Fuels and Process Research and Development, EPA 600/2-76-152b,
NTIS-PB 256 321/AS, June 1976.
4-26. Pohl, J. H. and A. F- Sarofim, "Devolatilization and Oxidation of Coal Nitrogen," presented
at 16th International Symposium on Combustion, M.I.T., August 1976.
4-27. Blair, D. W., et al., "Devolatilization and Pyrolysis of Fuel Nitrogen from Single Coal
Particle Combustion," 16th Symposium (International) on Combustion, Cambridge, Mass., 1976.
4-28. Pershing, D. W., "Nitrogen Oxide Formation in Pulverized Coal Flames," PhD Dissertation,
University of Arizona, 1976.
4-29. Axworthy, A. E., Jr., "Chemistry and Kinetics of Fuel Nitrogen Conversion to Nitric Oxide,"
AIChE Symposium Series, No. 148, Vol. 71, 1975, pp. 43-50.
4-30. Axworthy, A. E., et al., "Chemical Reactions in the Conversion of Fuel Nitrogen to NOX,"
in Proceedings of the Stationary Source Combustion Symposium. Volume I, EPA 600/2-76-152a,
NTIS-PB 256 320/AS, June 1976.
4-31. Pershing, D. W., and J. 0. L. Wendt, "The Effect of Coal Combustion on Thermal and Fuel NOX
Production from Pulverized Coal Combustion," presented at Central States Section, The
Combustion Institute, Columbus, Ohio, April 1976.
4-32. "Control Techniques for Nitrogen Oxide Emissions from Stationary Sources -Draft Second
Edition," Aerotherm TR-76-222, Acurex Corporation/Aerotherm Division, Mountain View, CA,
October 1976.
4-33. Barr, W. H., and D. E. James, "Nitric Oxide Control -A Program of Significant Accomplish-
ments," ASME 72-WA/Pwr-13.
4-34. Barr, W. H., et al., "Retrofit of Large Utility Boilers for Nitric Oxide Emissions Pro-
duction - Experience and Status Report."
4-35. Crawford, A. R., et al., "Field Testing: Application of Combustion Modifications to
Control NOX Emissions for Utility Boilers," Exxon Research and Engineering Co.,
EPA 650/2-74-066, NTIS-PB 237 344/AS, June 1974.
4-36. Crawford, A. R., et al., "The Effect of Combustion Modification on Pollutants and Equipment
Performance of Power Generation Equipment," in Proceedings of the Stationary Source Com-
bustion Symposium; Volume III - Field Testing and Surveys, Exxon Research and Engineering
Co., EPA 600/2-76-152C, NTIS-PB 257 146/AS.
4-107
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4-37 Blakeslee, C. E., and H. E. Burbach, "Controlling NOX Emissions from Steam Generators,"
' C. E. Inc., APCA 72-75, 65th Annual Meeting of Air Pollution Control Association,
June'18-22, 1972.
4-38. Blakeslee, C. E., and H. E. Burbach, "NOX Emissions from Tangenti ally-Fired Utility
Boilers, Part II, Practice," AIChE Symposium Series No. 148, Vol. 71, 1975.
4-39 Selker A P , "Program for Reduction of NOX from Tangential Coal-Fired Boilers, Phase II
' and Ila/EPA 650/2-73-005a and b, NTIS-PB 245 162/AS and NTIS-PB 246 889/AS, June 1975.
4-40. Bartok, W., et al., "Systematic Field Study of NOX Emission Control Methods for Utility
Boilers," ESSO Research and Engineering Co., GRU.4GNOS.71, December 1971.
4-41. Hollinden, G. A., et al., "NOX Control at TVA Coal-Fired Steam Plants," ASME Air Pollution
Control Division, Proceedings of the Third National Symposium, April 24-25, 1973.
4-42. "Applicability of NOX Combustion Modifications to Cyclone Boilers (Furnaces)," (Draft)
Monsanto Research Corp., 1976.
4-43. "Standard Support Document and Environmental Impact Statement - Stationary Reciprocating
Internal Combustion Engines," Prepared by Aerotherm Division of Acurex Corporation,
Mountain View, California for U.S. Environmental Protection Agency, Contract 68-03-1318,
Task No. 7, March 1976.
4-44. Hollinden, G. A., et al., "Evaluation of the Effects of Combustion Modifications in
Controlling NOX Emissions at TVA's Widow's Creek Steam Plant," EPRI SR-39, February 1976.
4-45. "Preliminary Test Results of NOX Controls on Industrial Boilers -Appendix A,"
KVB Engineering.
4-46. McCann, C., et al., "Combustion Control of Pollutants from Multiburner Coal-Fired System,"
U.S. Bureau of Mines, EPA 650/2-74-038, NTIS-PB 233 037/AS, May 1974.
4-47. Breen, B. P., "Combustion in Large Boilers: Design and Operating Effects on Efficiency
and Emissions," KVB, Inc. Paper presented at the 16th Symposium (International) on
Combustion, Massachusetts Institute of Technology, Cambridge, Massachusetts, August 15-21,
1976.
4-48. Maloney, K. L., "Western Coal Use in Industrial Boilers," Western States Section/The
Combustion Institute, April 19-20, 1976, Salt Lake City, Utah.
4-49. "Standard Support and Environmental Impact Statement for Standards of Performance:
Lignite-Fired Steam Generators," (First Draft), EPA, March 1975.
4-50. Locklin, D. W., et al., "Design Trends and Operating Problems in Combustion Modification
of Industrial Boilers," Battelle-Columbus Lab., EPA 650/2-74-032, NTIS-PB 235 712/AS,
April 1974.
4-51. Hall, R. E., et al., "Study of Air Pollutant Emissions from Residential Heating Systems,"
EPA 650/2-74-003, NTIS-PB 229 697/AS, January 1974.
4-52. Cichanowicz, J. E., et al., "Pollutant Control Techniques for Package Boilers, Phase I
Hardware Modifications and Alternate Fuels," (Draft Report) Ultrasystems and Foster
Wheeler, November 1976.
4-53. Cato, G. A., et al., "Field Testing: Application of Combustion Modification to Control
Pollutant Emissions from Industrial Boilers -Phase II," KVB Engineering, Environmental
Protection Technology Series, EPA 600/2-76-086a, NTIS-PB 253 500/AS, April 1976.
4-54. Barrett, R. E., et al., "Field Investigation of Emissions from Combustion Equipment for
Space Heating," Battelle-Columbus Laboratories, EPA-R2-73-084a, NTIS-PB 223 148, June 1973.
4-55. Combs, L. P., and A. S. Okuda, "Commercial Feasibility of an Optimum Distillate Oil Burner
Head," Final Report, Rocketdyne Division, Rockwell International Corporation.
4-108
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4-56. Combs, L. P., and A. S. Okuda, "Residential Oil Furnace System Optimization -Phase I "
Rocketdyne Division, Rockwell International, EPA 600/2-76-038, NTIS-PB 250 878/AS
February 1976.
4-57. Combs, L. P., and A. S. Okuda, "Commercial Feasibility of an Optimum Residential Oil Burner
Head," Rocketdyne Division, Rockwell International, EPA 600/2-76-256, NTIS-PB 259 912/AS
September 1976. '
4-58. Combs, L. P., et al., "Integrated Low-Emissions Residential Furnace," Proceedings of the
Stationary Source Combustion Symposium; Volume II - Fuels and Process Research and
Development, EPA 600/2-76-152b, NTIS-PB 256 321/AS, June 1976.
4-59. Ketels, P. A., et al., "A Survey of Emissions Control and Combustion Equipment Data in
Industrial Process Heating," Final Report by Institute of Gas Technology for EPA, IGT
Project No. 8949, June 1976.
4-60. Shoffstall, D. R., "Burner Design Criteria for Control of NOX from Natural Gas Combustion,
Volume I," Institute of Gas Technology. EPA 600/2-76-098a, NTIS-PB 254 167/AS, April 1976.
4-61. Ando, J., et al., "NOX Abatement for Stationary Sources in Japan," EPA 600/2-76-013b,
NTIS-PB 250 586/AS, January 1976.
4-62. Hunter, S.C., et al., "Application of Combustion Technology for NOX Emissions Reduction on
Petroleum Process Heaters," presented at 83rd National Meeting AIChE, Houston, Texas,
March 1977.
4-63. Copeland, J. 0., "Standards Support and Environmental Impact Statement: An Investigation
of the Best Systems of Emission Reduction for Nitrogen Oxides from Large Coal-Fired Steam
Generators," (Draft) EPA, October 1976.
4-64. Thompson, R. E., et al., "Effectiveness of Gas Recirculation and Staged Combustion in
Reducing NOX on a 560 MW Coal-Fired Boiler," EPRI SR-39, February 1976.
4-65. Bagwell, F. A., et al., "Utility Boiler Operating Modes for Reduced Nitric Oxide Emissions,"
Journal of the Air Pollution Control Association, Vol. 21, pp. 702-708, 1971.
4-66. Barr, W. H., et al., "Retrofit of Large Utility Boilers for Nitric Oxide Emission
Reduction - Experience and Status Report," paper presented at the 69th Annual AIChE
Meeting, November 30, 1976.
4-67. Norton, D. M., et al., "Modifications to Ormond Beach Steam Generators for NOX Compliance,"
paper presented at the ASME Winter Annual Meeting, November 30, 1975, Houston, Texas,
ASME Paper No. 75-WA/PWR-9.
4-68. Heap, M. P., et al., "Reduction of NO Emissions from Package Boilers," Revised Draft Final
Report by Ultra Systems, Inc., Irvine, California.
4-69. Durkee, K. R., et al., "An Investigation of the Best Systems of Emission Reduction for
Stationary Gas Turbines -Standards Support and Environmental Impact Statement," (Draft)
EPA, Research Triangle Park, N.C., July 1976.
4-70. Breen, B. P., "Control of the Nitric Oxide Emissions from Fossil Fueled Boilers," The
Fourth Westinghouse International School for Environmental Management, July 15-18, 1973.
4-71. Bell, A. W., et al., "Combustion Control for Elimination of Nitric Oxide Emissions from
Fossil Fuel Power Plants," 13th International Symposium on Combustion, University of Utah,
August 23-29, 1970.
4-72. Bell, A. V., et al., "Nitric Oxide Reduction by Controlled Combustion Processes," KVB, Inc.,
Western States Section/Combustion Institute, April 20-21, 1970.
4-73. Jain, L. K., et al., "State of the Art for Controlling NOX Emissions, Part I, Utility
Boilers," Catalytic, Inc., EPA-R2-72-072a, NTIS-PB 213 297, September 1972.
4-74. Norton, D. M., et al., "Status of Oil-Fired NOX Control Technology," EPRI-SR-39,
February 1976.
4-109
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4-75. Frledrlch, J. L.. et al., "Nitrogen Oxides Reduction," Foster Wheeler Energy Corp.,
EPRI SR-39, February 1976.
4-76. Lachapelle, D. G., "Staged Combustion Technology for Tangentially-Fired Utility Boilers
Burning Western Coal," (Draft) February 1976.
4-77 Muzio, L J., et al., "Package Boiler Flame Modifications for Reducing Nitric Oxide
Emissions, Phase II of III," Ultrasysterns, Inc., EPA-R2-73-292b, NTIS-PB 236 752,
June 1974.
4-78 Seabrook, H. and B. P. Breen, "A Practical Approach to NOX Reduction in Utility Boilers,"
Con Edison Co. of New York and KVB, presented at American Power Conference,
April 18-20, 1972.
4-79 Shimizu, A. B., et al., "NOX Combustion Control Methods and Costs for Stationary Sources
Summary Study," EPA 600/2-75-046, NTIS-PB 246 750/AS, September 1975.
4-80. Cato, 6. A., et al., "Field Testing: Application of Combustion Modification to Control
Pollutant Emissions from Industrial Boilers -Phase I," KVB Engineering,
EPA 650/2-74-078a, NTIS-PB 238 920/AS, October 1974.
4-81. Heap, M.P., et al., "Application of NOX Control Techniques to Industrial Boilers,"
Ultrasystems, Inc., presented at the 69th Annual Meeting of the AIChE, Nov. 28-Dec. 2, 1976.
4-82. Fenimore, C. P-, et al., "Formation and Measurements of Nitrogen Oxides in Gas Turbines,"
ASME 70-WA/GT-3, August 3, 1970.
4-83. Heap, M. P., et al., "Burner Design Principles for Minimum NOX Emissions," EPA 650/2-73-021,
NTIS-PB 224 210/AS, September 1973.
4-84. Heap, M. P., et al., "The Effect of Burner Parameters on Nitric Oxide Formation in Natural
Gas and Pulverized Fuel Flames," IFRF, American Flame Research Committee, Sept. 6-7, 1972.
4-85. Pershing, D. W., et al., "Relationship of Burner Design to the Control of NOX Emissions
Through Combustion Modification," EPA 650/2-73-021, NTIS-PB 224 210/AS, Sept. 1973.
4-86. Shoffstall, D. R., "Burner Design Criteria for Control of Pollutant Emissions from Natural
Gas Flames," Institute of Gas Technology, EPA 600/2-76-152b, NTIS-PB 256 321/AS, June 1976.
4-87. Koppang, R. R., "A Status Report on the Commercialization and Recent Development History of
the TRW Low-N0x Burner," TRW Energy Systems Group.
4-88. Tsuji, S., et al., "Control Technique for Nitric Oxide -Development of New Combustion
Methods," IHI Engineering Review, Vol. 6, No. 2.
4-89. Ando, J., et al., "NOX Abatement for Stationary Sources in Japan," August 1976
(Preliminary Draft).
4-90. Brackett, C. E., and J. A. Barsin, "The Dual Register Pulverized Coal Burner - A NOX
Control Device," EPRI SR-39. February 1976.
4-91. Vatsky, J., and R. P. Welden, "NOX -A Progress Report," Foster Wheeler Corp., Heat
Engineering, July-Sept., 1976, Vol. 48, No. 8.
4-92. Dickerson, R. A., and A. S. Okuda, "Design of an Optimum Distillate Oil Burner for Control
of Pollutant Emissions," EPA 650/2-74-047, NTIS-PB 236 647/AS, June 1974.
4-93. Singh, P. P., et al., "Formation and Control of Oxides of Nitrogen Emissions from Gas
Turbine Combustion Systems," ASME 72-GT-22, October 1972.
4-94. Roessler, et al., "Assessment of the Applicability of Automotive Emission Control
Technology to Stationary Engines," Aerospace Corporation, EPA 650/2-74-051, NTIS-PB 237 115/AS,
July 1974.
4-95. Spadaccini, L. J., and E. J. Szetela, "Approaches to the Prevaporized-Premixed Combustor
Concept for Gas Turbines," ASME 75-GT-85.
4-110
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4-96. Anderson, David, "Effects of Equivalence Ratio and Dwell Time on Exhaust Emissions from an
Experimental Prenrixing Prevaporizing Burner," Lewis Research Center, ASME 75-GT-69.
4-97. Cornelius, W., and W. R. Wade, "The Formation and Control of Nitric Oxide in a
Regenerative Gas Turbine Burner," General Motors Corp., SAE 700708.
4-98. Wade, W. R., et al., "Low Emissions Combustion for the Regenerative Gas Turbine "
ASME 73-GT-ll, January 1974.
4-99. White, D. .J., and M. E. Ward, "Dry NOX Control Techniques," EPRI SR-39, February 1976.
4-100. Hosier, S. A., et al., "Progress in Development of Low-N0x Gas Turbine Combustors,"
United Technologies, for presentation at the 69th Annual AIChE Meeting, Nov. 28-Dec. 2, 1976.
4-101. Teixeira, D. P-, "Overview of Water Injection for NOX Control," EPRI SR-39, February 1976.
4-102. Armento, W. J., and W. L. Sage, "The Effect of Design and Operation Variables on NOX
Formation in Coal-Fired Furnaces," Alliance Research Center/B&W Pulverized Coal Combustion
Seminar, June 19-20, 1973.
4-103. Lyon, R. K., "Method for the Reduction of the Concentration of NO in Combustion Effluents
Using Ammonia," U.S. Patent No. 3,900,554, assigned to Exxon Research and Engineering
Company, Linden, New Jersey, August 1975.
4-104. Lyon, R. K., and J. P. Longwell, "Selective, Non-Catalytic Reduction of NOX by NHs,"
Proceedings of the NOx Control Technology Seminar. EPRI SR-39, February 1976.
4-105. Muzio, L. J., and T. K. Arand, "Homogeneous Gas Phase Decomposition of Oxides of Nitrogen,"
EPRI Report FP-253, August 1976.
4-106. Teixeira, D. P., "Status of Utility Application of Homogeneous NOX Reduction,"
Proceedings of the NOX Control Technology Seminar, EPRI SR-39, February 1976.
4-107. Bartok, W., et al., "Systems Study of Nitrogen Oxide Control Methods for Stationary
Sources," Final Report -Volume II, Esso Research and Engineering, Prepared for NAPCA,
NTIS-PB 192 789, November 1969.
4-108. Blakeslee, C. E., and A. P. Selker, "Program for the Reduction of NOX from Tangential
Coal-Fired Boilers, Phase I," Environmental Protection Technology Series, EPA 650/2-73-005,
NTIS-PB 226 547/AS, August 1973.
4-109. Lachapelle, D. G., et al., "Overview of the Environmental Protection Agency's NOX Control
Technology for Stationary Combustion Sources," presented at the 67th AIChE Annual Meeting,
December 1974.
4-110. Kelley, D. V., data submitted at the EPRI NOX Control Technology Seminar, San Francisco,
by Pacific Gas and Electric Company, February 1976.
4-111. Personal communication - letter from the Los Angeles Department of Water and Power to
Acurex Corporation, May 5, 1975.
4-112. "Power Costs, 1974 Report on Diesel and Gas Engines," The American Society of Mechanical
Engineers (ASME), March 1974.
4-113. Personal communication, R. J. Lenney, Blueray Systems, Inc., Weston, Massachusetts,
September 1975.
4-114. Satterfield, C. N., et al., "Catalytic Desulfurization and Denitrogenation,"
EPA 600/2-75-063, NTIS-PB 248 101/AS, October 1975.
4-115. Frost, C. M., et al., "Hydrodenitrifi cation of Crude Shale Oil," Laramie Energy Research
Center, LERC/RI-75/3, July 1975.
4-116. Jimeson, R. M., and L. W. Richardson, "Census of Oil Desulfurization to Achieve
Environmental Goals," AIChE No. 148, Vol. 71.
4-111
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4-117. Personal communication with Harry F. Mason of Chevron Research Company, Richmond,
California, January 1977.
4-118. Guth, E. D., et al., "Method for Removing Sulfur and Nitrogen in Petroleum Oils,"
U.S. Patent No. 3,847,800, Nov. 12, 1974.
4-119. Personal communication with E. D. Guth - KVB Engineering, January 11, 1977.
4-120. Wright, C. H., "Sulfur and Nitrogen Balances in the Solvent Refined Coal Process,"
Pittsburg and Midway Coal Mining Company, EPA 650/2-75-011, NTIS-PB 243 893/AS,
January 1975.
4-121. Meyers, R. A., "Desulfurize Coal Chemically," TRW Systems and Energy -Hydrocarbon
Processing, June 1975.
4-122. Personal communication with Mr. Van Nuys of TRW Systems and Energy, Redondo Beach, CA.,
January 1977-
4-123. Stambaugh, E. P., et al., "Hydrothermal Coal Desulfurization with Combustion Results,"
EPA/RTP Contract 68-02-2119.
4-124. Stambaugh, E. P., "Battelle Develops Leaching Process to Desulfurize Coal," Coal Age,
August 1975.
4-125. Shaw, H., "Reduction of Nitrogen Oxide Emissions From a Gas Turbine Combustor by Fuel
Modifications," Journal of Engineering for Power, October 1973.
4-126. McCreath, C. G., "The Effect of Fuel Additives on the Exhaust Emissions From Diesel
Engines," Combustion and Flame, Vol. 17, 1971 p. 359.
4-127. Altwicker, E. R., et al., "Pollutants From Fuel Oil Combustion and the Effects of
Additives," Paper No. 71-14, 64th Annual APCA Meeting, Atlantic City, N.J., June 1971.
4-128. Martin, G. B., et al., "Effects of Fuel Additives on Air Pollutant Emissions From
Distil late-Oil-Fired Furnaces," June 1971.
4-129. Pershing, D. W., et al., "Effectiveness of Selected Fuel Additives in Controlling
Pollution Emissions From Residual-Oil-Fired Boilers," EPA 650/2-73-031, NTIS-PB 225 037/AS,
October 1973.
4-130. Krause, H. H., et al., "Combustion Additives for Pollution Control -A State-of-the-Art
Review," EPA 600/2-77-008a, January 1977-
4-131. Giammar, R. D., et al., "The Effect of Additives in Reducing Particulate Emissions From
Residual Oil Combustion," Proceedings of the Stationary Source Combustion Symposium,
EPA 600/2-76-152c, NTIS-PB 257 146/AS, Atlanta, June 1976.
4-132. Kukin, Ira, "Additives Can Clear Up Oil-Fixed Furnaces," Apollo Chemical Corp.,
Environmental Science and Technology, July 1973.
4-133. "National Energy Outlook," FEA/N-75/713, Federal Energy, Administration, February 1976.
4-134. Ctvrtnicek, T. E., et al., "Evaluation of Low-Sulfur Western Coal Characteristics,
Utilization, and Combustion Experience," Monsanto Research Corp., EPA 650/2-75-046,
NTIS-PB 243 911/AS, May 1975.
4-135. Martin, G. B., "Environmental Considerations in the Use of Alternate Clean Fuels in
Stationary Combustion Processes."
4-136. Klepetch, R. D., and G. E. Vitti, "Gas Turbine Combustor Test Results and Combine Cycle
Systems," Combustion, Vol. 45, No. 10, pp. 35-38, April 1974.
4-137. Frendberg, A., "Performance Characteristics of Exhibiting Utility Boilers When Fired With
Low-Btu Gas, Proc. Conf. on Power Generation -Clean Fuels Today, EPRI, Monterey,
California, April 8-10, 1974.
4-112
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4-138. Joubert, J. I., and Daniel Bienstock, "Properties of Industrial Fuel Gases Manufactured
From Coal Using Commercially Proven Technology," presented at the Symposium on Environment
and Energy Conservation, Denver, Colorado, November 1975.
4-139. Shoffstall, D., "Preliminary Combustion Tests of Nine Drums of Stabilized Coal-Oil
Emulsion," Systems Research Laboratories, Dayton, Ohio, Final Report 3205-43, March 1976.
4-140. Proceedings of the "Coal-Oil Mixture Combustion Technology Exchange Workshop," sponsored
by ERDA, Report No. CONF-76T019, Washington, D.C., October 29, 1976.
4-141. Martin, G. Blair, "Evaluation of NOX Emission Characteristics of Alcohol Fuels in
Stationary Combustion Systems," presented at Joint Meeting, Western and Central States
Sections, The Combustion Institute, April 21 and 22, 1975, San Antonio, Texas.
4-142. Hall, R. E., "The Effect of Water/Residual Oil Emulsions on Air Pollutant Emissions and
Efficiency of Commercial Boilers," ASME 75-WA/APC-l, July 14, 1975.
4-143. Hall, R. E., "The Effect of Water/Distillate Oil Emulsions on Pollutants and Efficiency of
Residential and Commercial Heating Systems," APCA Paper No. 75-09.4, June 1975.
4-144. Pfefferle, W. C., et al., "CATATHERMAL Combustion: A New Process for Low-Emissions Fuel
Conversion," presented at the 1975 ASME Winter Annual Meeting, Houston, Texas, ASME
Paper No. 75-WA/FU-l.
4-145. Kesselring, J. P., et al., "Catalytic Oxidation of Fuels for NOX Control from Area Sources,"
EPA Report, EPA 600/2-76-037, NTIS-PB 252 195/AS, February 1976.
4-146. DeCorso, S. M., et al., "Catalysts for Gas Turbine Combustors -Experimental Test Results,"
paper presented at the ASME Gas Turbine Conference and Products Show, New Orleans,
March 1976, ASME Paper No. 76-GT-4.
4-147. LaNauze, R. D., "Fluidized Combustion," Energy World Number 22, December 1975.
4-148. "Design and Construction of a Fluidized-Bed Coal Combustion Sampling and Analytical Test
Rig," Acurex/Aerotherm Proposal 2167-75-A, October 1975.
4-149. "Proceedings of the 4th International Conference on Fluidized Bed Combustion," McLean,
Virginia, December 1975.
4-150. Fennelly, P. F., "Emission Estimates of NOX and Organic Compounds from Fluidized Bed
Combustion," presented at the International Conference on Photochemical Oxidant and Its
Control, Raleigh, North Carolina, September 12-17, 1976.
4-151. Gerstin, R. A., "A Technical and Economic Overview of the Benefits of Repowering,"
paper presented at the Gas Turbine Conference and Products Show, Houston, Texas, March 2-6,
1975, ASME Paper No. 75-GT-16.
4-152. Ahuja, A., "Repowering Pays Off for Utility and Industrial Plants," Power Engineering,
pp. 50-54, July 1976.
4-153. Robson, F. L. and A. J. Giramonti, "The Use of Combined-Cycle Power Systems in Nonpolluting
Central Stations," JAPCA, Vol. 22, pp. 177-180, (1972).
4-154. Amos, D. J., et al., "Energy Conversion Alternatives Study (ECAS), Westinghouse Phase I
Final Report, Volume V - Combined Gas Steam Turbine Cycles," NASA CR-134941, Volume V, 1976.
4-155. Stambler, I., "Field Test 5 MW Combined Cycle Package Set for 1978," Gas Turbine World,
March 1976, pp. 10-13.
4-156. Papamarcos, J., "Combined Cycles and Refined Coal," Power Engineering, December 1976,
pp. 34-42.
4-157. Kydd, P. H., "An Ultra High Temperature Turbine for Maximum Performance and Fuels
Flexibility," paper presented at the Gas Turbine Conference and Products Show, Houston,
Texas, March 2-6, 1975, ASME Paper No. 75-GT-81.
4-113
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4-158. Force, E. L., and R. J. Ayen, "Catalytic Reduction of 50 to 5000 ppm Nitric Oxide by
Carbon Monoxide," AIChE Symposium Series No. 126, Volume 68, 1972.
4-159. Koutsoukas, E. P., et al., "Assessment of Catalysts for Control of NOX from. Stationary
Power Plants, Phase 1, Volume 1 Final Report," EPA 650/2-75-OOla, NTIS-PB 239 745/AS,
January 1975.
4-160. Ando, J. and H. Tohata, "NOX Abatement Technology in Japan," EPA-R2-73-284, NTIS-PB 222 335,
June 1973.
4-161. "Dry Scrubbing of Utility Emissions," Environmental Science and Technology, Volume 9, No. 8.
4-162. Habib, Y., and W. F. Bischoff, "Dry System for Flue Gas Cleanup," Oil and Gas Journal,
February 24, 1975.
4-163. Pohlenz, J. P., "The Shell Flue Gas Desulfurization Process," presented at the EPA Flue
Gas Desulfurization Symposium, Atlanta, November 1974.
4-164. Ploeg, J. E., et al., "How Shell's Flue Gas Desulfurization Unit has Worked in Japan,"
Petroleum International, Volume 14, No. 7, pp. 50-58, July 1974.
4-165. Stern, R., "The EPA Development Program for NOX Flue Gas Treatment," in Proceedings of the
National Conference on Health, Environmental Effects, and Control Technology of Energy Use,
EPA Report 600/7-76-002, NTIS-PB 256 845/AS, February 1976.
4-166. Rosenberg, H. S., "Molecular Sieve NOX Control Process in Nitric Acid Plants," EPA Report
EPA 600/2-76-015, NTIS-PB 250 555/AS, January 1976.
4-114
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SECTION 5
MULTIMEDIA EMISSION INVENTORY OF NOV SOURCES
A
This section presents an inventory of multimedia emissions from the stationary fuel combus-
tion NOX sources and fuels identified in Section 2. Additionally the inventory for NO emissions
is extended to include all other sources of NOX (mobile, noncombustion, fugitive) in order to compare
the contribution from stationary combustion sources. The NOX inventory accounts for the degree of
control applied to new and existing utility boilers. Multimedia pollutants inventoried include the
primary criteria pollutants (NOX, SOX, CO, HC, particulates), sulfates, polycyclic organic material
(POM), trace metals, and liquid or solid effluent streams. Results for sulfates, polycyclic organic
matter, trace metals, and liquid and solid effluent streams are given in Appendix A. Insufficient
data exist to quantify emissions for the other potential pollutants discussed in Section 3.
This inventory will serve as the base for assessing potential pollution problems in the
absence of NOX controls and for weighing the incremental emission input due to the use of NOX con-
trols. The inventory will also serve as the reference for the subsequent projections to the year
2000 in fuel and equipment use and stationary source emissions. Data gaps identified in the emis-
sion factor compilation highlight areas where further testing is needed in the NOX E/A or other
programs.
The emission inventory was generated through the following sequence:
• Compile fuel consumption data for the categories of combustion sources specified in
Section 2 (Section 5.1)
- Subdivide fuel consumption based on fuel-bound pollutant precursor composition
• Compile multimedia emission data (Section 5.2)
- Base fuel-dependent pollutant emission factors on trace composition of fuels
- Base combustion-dependent pollutant emission factors on unit fuel consumption for
specific equipment designs
• Survey the degree to which NOV, SOV, particulates are controlled (Section 5.3)
X A
5-1
-------
• Produce emissions inventory (Section 5.4)
• Rank sources according to emission rates; compare to results of previous inventories
(Section 5.5)
5.1 FUELS: PROPERTIES AND CONSUMPTION
This section characterizes fuel composition and consumption required in the emission inventory
for stationary combustion sources of NOX_ U.S. energy use in 1974 totaled about 77 x 1015 kJ (72 x TO15
Btu) (Reference 5-1), of which 94 percent was supplied by the fossil fuels - coal, petroleum, and
natural gas. Approximately 57 percent of the total energy was consumed by stationary source equip-
ment. Fossil fuels furnished 92 percent of the energy for these stationary sources, with the
remainder supplied by nuclear, hydroelectric, and other miscellaneous sources such as waste fuels,
wood, geothermal, etc. Of the total amount of fossil fuels burned in stationary sources, coal and
natural gas contributed 26 and 44 percent, respectively, and petroleum 30 percent. Unlike petroleum,
which is also a major source of energy for transportation, coal and natural gas are consumed pri-
marily in stationary applications.
The following discussion will focus exclusively on fossil fuels since they account for essen-
tially all the energy consumed by stationary sources on a national basis. Section 5.1.1 briefly dis-
cusses each of the three major fossil fuels and their derivatives. Section 5.1.2 gives a detailed
summary of the amount of each fuel consumed by the major stationary source equipment sectors and by
individual equipment types within each sector. In the case of industrial process heating sources,
figures on annual production rather than fuel consumption are given. No estimates of either fuel
consumption or production are given for mobile, incineration, and fugitive NO emission sources.
5.1.1 Fuel Properties
Because of the variation in origin and processing, fossil fuels show large variations in both
chemical and physical properties. Since data on fuels will be used in this report to estimate multi-
media effluents produced by combustion, it is necessary to represent the majority of fuel variables
by one or more sets of average values. There were many reasons for taking this approach:
• There are no comprehensive data which relate fuel consumption with exact fuel properties
or origin
• Emission factors, with few exceptions, are in terms of average fuel properties (see
Section 5.2)
5-2
-------
• No comprehensive data exist on the various fuel cleaning practices such as blending,
washing, desulfurization, demetalllzatlon, etc., employed by suppliers or users of fuel
• The nonhomogeneous nature of any fuel sample, especially coal and oil, makes exact charac-
terization Impossible (Reference 5-2)
An exception to the rule is the sulfur content of electrical utility fuels which is rigorously
monitored. It is possible therefore to define the sulfur content of several residual oil and coal
fuels fairly accurately. Sulfur contents of the following fuels represent the fossil fuels consumed
by stationary sources:
• Petroleum products
- Residual fuel oil
• High S - 2.0 percent
• Medium S - 1.0 percent
• Low S — 0.5 percent
- Distillate fuel oil, 0.25 percent S
- Gasoline, 0.0 percent S
• Coal
— Bituminous and subbituminous
• High S — 2.8 percent (Interior Province origin)
• Medium S — 2.2 percent (Eastern Province origin)
• Low S - 1.6 percent (Western Province origin)
- North Dakota lignite, 0.4 percent S
- Pennsylvania anthracite, 0.6 percent S
• Natural gas, <0.1 percent S
The medium sulfur levels of coal and residual oil correspond to the average sulfur concen-
tration of fuels used in U.S. utilities in 1974 (Reference 5-3). Data on sulfur composition of the
fuels were available for the utility boiler sector, but there were relatively little data available
for the other sectors. When specific sulfur content for fuel consumption data was not available,
medium sulfur concentration levels were used where applicable.
The nitrogen content of fuels was treated differently than the sulfur content. This is
because, in contrast to SOV emissions, NOV emissions are highly dependent on equipment design and
X "
5-3
-------
combustion conditions and are a composite of thermal NOX and fuel nitrogen conversion. Therefore,
variations in NO emissions due to fuel nitrogen content are treated by specifying emission
factors for each equipment/fuel combination, e.g., tangential utility boilers firing bituminous coal,
watertube package boilers firing residual oil, rather than directly relating emissions to fuel nitro-
gen content.
Liquid and solid fuels invariably contain some trace element contamination; this is especi-
ally important in the combustion of residual fuel oil and coal where concentration levels are
greatest and large amounts are burned each year. Natural gas, distillate oil, and gasoline are
assumed to contain no trace elements. This assumption will have an insignificant impact on total
trace element emissions from stationary sources.
It is practical to use representative concentration levels for coal since the trace element
content of individual coal samples is highly variable. Trace element concentrations typically vary
within a single coal-producing region, and even within a single seam (Reference 5-4). More refined
specifications of the trace element content of various coals are unwarranted at this time because
the available data on trace element emission factors have proven to be of poor quality. One study,
in fact, suggests that trace element emissions from fossil fuels are so variable that they must be
determined on a plant-to-plant basis (Reference 5-5).
Trace elements in residual fuel oils are even more variable than those in coal. This is
compounded by the lack of specific data on the origin, refinery practices, and blending techniques
of the residual oil used at the burner. Demetallization, desulfurization, and blending of various
grades of oil vary from refinery to refinery. Supply and demand strongly influence the movement
of petroleum. Further, supply and demand requirements are difficult to predict so that assumptions
on refinery origins are bound to change. As a result, only a single average set of trace element
concentrations will be used for residual fuel oil. This will be further justified when emission
factors for these elements are presented in Section 5.2.
Table 5-1 gives the trace element concentrations and summarizes other important properties
of each of the major types of fossil fuels. These properties will be used throughout the remainder
of this section.
5.1.2 Fuel Consumption
This section presents estimates of stationary source fuel consumption (or of annual production
in the case of process heating sources) needed to estimate multimedia effluents. The discussion in-
cludes the sources for these estimates and comments as to the reliability of the estimates. Fuel
5-4
-------
TABLE 5-1. PROPERTIES AND TRACE ELEMENTS OF REPRESENTATIVE FOSSIL FUELS (References 5-6, 5-7, 5-8, 5-9)
in
i
Ash %
Sulfur %
Heating Value
Al (ppm)
Sb
As
Ba
Be
Bi
B
Cd
Co
Cr
Cu
Pb
Mn
Hg
Mo .
N1
P
Se
V
In
Ir
Anthracite
Coal
11.9
0.6
30,238 kJ/kg
~
0:1
9.3
54
2.8
0.1
1.0
0.1
84
112
70
8.3
169
0.3
9.3
47
—
0.2
12
31
45
Subbituminous and
Bituminous
High S Medium S
9. 9.2
2.8 2.2
27,912 27,912
12,240
1.3
15
36
1.7
1.
114
2.9
9.1
14.
40.
14
53
0.2
8.0
22
63
2.0
33
312
72
Low S
8.7
1.6
23,260
10,200
1.1
13
30
1.5
0.8
95
2.4
7.6
12.
33
12
45
0.2
6.7
19
53
1.7
28
260
60
Lignite
Coal
12.8
0.4
18,608
8,160
0.9
10
24
1.2
0.7
76
2.0
6.1
10.
26
9.2
36
0.1
5.3
15
42
1.3
22
208
48
Residual Fuel Oil
High S Medium S
0 0
2.0 1.0
39,021 kJ/X.
753
0.2
0.2
39
—
__
3.0
2.0
30.
30.
25.
19
25
0.1
2.5
1,208
-_
10
1,803
40
19
Low S
0
0.5
Distillate
Oil
0
0.25
39,021 kJ/X,
0
i
1
Gasoline
0
0
34,840 kJ/Jl
0
>
Natural
Gas
0
0
37,259 kJ/m3
0
i
n
en
-------
consumption data were compiled for the year 1974, the most recent period for which comprehensive
data were available. By way of summary, the totals for coal, petroleum, and gas combustion are given
in Table 5-2. It is important to note that these totals do not reflect the total amount of energy
consumed by stationary sources because the process industries have been excluded along with electrical
inputs originating from nonfossil fuel sources.
5.1.2.1 Utility and Large Industrial Boilers
Fuel consumption estimates for utility boilers are accurate and comprehensive in terms of
both (1) total amount consumed and (2) the fraction due to each type of fuel. This is extremely
valuable information, since relatively extensive emission factor data are also available for this
sector. Table 5-3 gives a detailed summary of the fuel consumed by those utility boiler equipment
types determined to be of significance in Section 2. The following sources of data were used to
compile this summary:
• FPC - fuel consumption by type of fuel and sulfur content (References 5-3, 5-10)
• 6CA - analysis of FPC-67 tapes to provide data on total number of boilers and equipment
and fuel breakdown (Reference 5-6)
• Monsanto - analysis of cyclone boiler population and fuel consumption (Reference 5-11)
• OAQPS - analysis of lignite-fired steam generators (Reference 5-12)
• A. D. Little — analysis of the electric utilities and equipment manufacturers (Reference
5-13)
• Battelle -analysis of boiler population and fuels for nonutility application (Reference
5-14)
• Bureau of Mines - data on domestic coal production and end use by state; data on petro-
leum products (Reference 5-15)
• "Power" Magazine -miscellaneous information on various equipment and fuel trends
(Reference 5-16)
To simplify these estimates, several basic assumptions were made:
• Distillate oil and kerosene were combined with the residual fuel oil category. The
reason for this is that distillate oil accounted for only about 5 percent of utility
steam plant total oil consumption (References 5-14 and 5-17)
• Coke, coke breeze, refuse, process gas, wood, bagasse, black liquor, sewer sludge, etc.,
have negligible application in utility boilers
5-6
-------
TABLE 5-2. 1974 STATIONARY SOURCE FUEL CONSUMPTION
Utility Boilers
Packaged Boilers
Warm Air Furnaces
and Miscellaneous
Combustion
Gas Turbines
Reciprocating
1C Engines
Total
Coal
101S kJ/yr
10.833
3.449
~~
—
_
14.282
Oil
1015 kJ/yr
3.483
5.801
2.132
0.844
0.327C
12.587
Gas
1015 kJ/yr
4.906
6.323a
4.542
0.681
0.913d
17.365
Total
1015 kJ/yr
19.222
15.573
6.674
1.525
1.240
44.234
Includes process gas
DThis sector includes steam and hot water units
M
"Includes gasoline and oil portion of dual fuel
Includes natural gas portion of dual fuel
5-7
-------
TABLE 5-3. UTILITY BOILER FUEL CONSUMPTION (kJ X 10~>s)
Utility Boilers
Tangential
Single
Wall -Fired
Opposed Wall and
Turbofurnace
Cyclone
Vertical and
Stoker
T3
4- C I/I
3 10 3
t- O
r— V} C
33-1-
t/> O E
C 3
l'i£
•^ 3iS
"U •*-* ^
O *i— 3
E: m m
2.624
1.513
0.423
0.158
0.110
•o
C
ID 3
t- 0
3 I/I C
1- 3 T-
"3 c 3
t/) •!- 4->
Ef
1-1-3
3: ca to
1.584
0.914
0.255
1.292
0.110
•o
f= t/1
10 3
O
s- in c
3 3 -i-
3 T- +J
CO E 1-
3 -O
* 4J JD
S-r- 3
_J CO l/>
0.869
0.501
0.140
—
__
5.130
2.938
0.839
1.588
0.338
T3
C
IO
IO
3
1.134
2.453
1.258
0.061
_
•*
r— t/I
+J HI
O 3
H~ *'
7.624
6.886
2.649
1.725
0.338
U1
00
-------
Coal accounted for 56 percent of the fuel consumed by utility boilers, natural gas 26 percent, and
oil 18 percent. Coal consumption In utility boilers Is about 76 percent of the total energy sup-
plied by coal to all stationary sources. For gas and oil the amounts burned 1n utility boilers
totaled only 30 and 28 percent, respectively, of the total of these fuels consumed by stationary
sources.
5.1.2.2 Packaged Boilers
Data on the fuel consumption of packaged boilers are not as reliable as data for utility
boilers. This is due in part to the large number of installed units, the diversity of design, the
wide variety of applications, and the fuel flexibility of many of these units. Table 5-4 lists the
fuel consumption estimates for the boiler designs in this sector which consume significant amounts
of fuel. These estimates were derived from a number of sources:
• Battelle -analysis of the national boiler population by capacity and fuel (Reference
5-14)
• Battelle - analysis of equipment design distribution (Reference 5-18)
• U.S. Department of Commerce —data on boiler sales 1968 to 1974 (Reference 5-19)
• TRC — historical trends in package boiler fuels (Reference 5-20)
The following assumptions were used to estimate fuel consumption for packaged boilers:
t All boilers greater than 29 MW in capacity are watertube designs and are single-wall
fired
• Pulverized coal is not fired in units of capacity less than 29 MW
• All coal burned for residential and commercial heating is used in steam and hot water
units
In 1974, energy supplied to packaged boilers was 34 percent of the total fossil fuel consumed
by stationary sources for energy conversion. Of this total consumption, coal supplied 24 percent of
the energy, oil 42 percent, and gas 34 percent. In comparison to the utility boiler sector, it is
clear that easily transported and distributed fuels are important for packaged boilers. Whereas for
utility boilers coal is the most heavily used fuel, in packaged boilers coal is used almost exclu-
sively in the larger watertube and older stoker units. Coal is seldom used in the new firetube or
the smaller watertube boilers.
5-9
-------
Table 5-4. 1974 PACKAGED BOILER FUEL CONSUMPTION (kJ x 10'15)
01
o
Packaged Boilers
Water-tube Boiler
Wall firing
>29 MW
Watertube Boiler
Stoker
>29 MW
Single Burner
Watertube
<29 MW
Single Burner
Scotch Firetube
<29 MW
Single Burner
HRT Firetube
<29 MW
Single Burner
Firebox Firetube
Single Burner
Cast Iron Boilers
Stoker Watertubes
<29 MW
Stoker Firetubes
<29 MW
Steam or Hot
Water Units
(Residential
Only)
Anthracite
_
_ .
_
_
_
__
0.021
0.042
0.014
Bituminous
or
Lignite
0.510
0.466
0.317
_
._
__
__
1.533
0.556
0.011
Total
Coal
0.510
0.466
0.317
_
_
—
1.554
0.598
0.025
Residual
Oil
0.637
_„,
0.595
0.945
0.370
0.609
0.195
_
—
0.069
Distillate
Oil
0.085
^_
0.103
0.446
0.263
0.403
0.181
—
—
0.880
Total
Oil
0.723
_
0.698
1.391
0.633
1.012
0.377
—
—
0.949
Natural
Gas
0.928
1.690
0.972
0.535
0.899
0.264
—
—
0.737
Process
Gas
0.130
_
0.130
0.019
_
0.019
—
_
—
_
Total
Fuel
2.290
0.466
2.835
2.382
1.168
1.930
0.641
1.554
0.598
1.711
-------
5.1.2.3 Warm A1r Furnaces and Other Commercial and Residential Combustion
Here again, exact fuel consumption 1s difficult to estimate because of the extremely large
number of units in the field and the large variety of available designs. Fuel consumption estimates
for commercial and residential as well as various cooking appliances, clothes dryers, refrigeration
units, etc. listed as "other" are presented in Table 5-5. The major source for these estimates was
the 1970 U.S. Census (Reference 5-21).
The basic assumptions used in making these estimates were:
• The amount of wood, refuse, and other nonfossil fuels burned in warm air furnaces is
minimal
• Units fueled by tank, bottled or liquefied petroleum gas are not a large portion of the
total units; since these units are generally rurally located, they were combined with
natural gas-fired units
• Coal is not fired in warm air furnaces, but when used in residential or commercial
heating applications, it is burned in steam or hot water units
Total warm air furnace fuel consumption in 1974 represented about 15 percent of the total used in
stationary sources for energy conversion. It is important to note that the amount of natural gas
used in this sector is approximately equivalent to the amount used by utility and packaged boilers,
whereas oil products are used considerably less.
5.1.2.4 Gas Turbines
1974 estimates of fuel consumption for gas turbines are considered to be of high quality
because of the relatively small number of major applications and manufacturers of these units and
the regulation of utility application. Table 5-6 gives the fuel consumption estimates for the
important gas turbine capacity ranges defined in Section 2. These estimates are derived from a
number of sources:
• GT-Standards Support Document -installation and generation for all applications and
capacity ranges except utility (Reference 5-22}
• FPC - installation, generation, and fuel consumption for all utility applications
(References 5-10 and 5-23)
• Sawyer's GT Catalog -miscellaneous information on utility and pipeline applications
(Reference 5-24)
• GT International -data on gas turbine electric utility installations (Reference 5-25)
5-11
-------
TABLE 5-5. 1974 WARM AIR FURNACE AND OTHER
COMMERCIAL/RESIDENTIAL COMBUSTION
(kJ x 10"15)
Warm Air Furnaces
Warm Air Central
Furnaces
Warm Air Room Heaters
Miscellaneous
Commerci al /Resi dential
Combustion
Distillate
Oil
1.405
0.727
•• ~
Natural
6asa
3.091
1.451
1.0
Total
Fuel
4.497
2.178
1.0
Includes bottled, tank or LPG
TABLE 5-6. 1974 GAS TURBINE FUEL CONSUMPTION
(kJ x TO'15)
Gas Turbines
Gas Turbines
>15 MW
Gas Turbines
4 MW to 15 MW
Gas Turbines
<4 MW
Natural
Gas
0.212
0.468
0.001
Oil3
0.264
0.579
0.001
Total
0.476
1.047
0.002
Includes distillate, diesel, residual oils
5-12
-------
These estimates were based on the following assumptions:
• Typical specific heat rates for the three capacity ranges were 10.9 MJ/kW-hr (10,300
Btu/kW-hr), 13.9 MJ/kW-hr (13,200 Btu/kW-hr) and 16.4 MJ/kW-hr (15,500 Btu/kW-hr) for
large, medium, and small capacity turbines, respectively
• Specific fuel consumption does not vary w'ith load, which means total fuel consumption
can be determined directly from specific fuel consumption and generation totals
• The amount of alternate fuels such as gasified or liquefied coals, shale oil, process
gas, pulverized coal, refuse, etc. burned in turbines is negligible
• Supplementary fjred combined-cycle turbine fuel consumption was minimal in 1974
The total energy consumed by gas turbines was about 3.5 percent of the total stationary source fuel
consumption in 1974. As Table 5-6 shows, medium-capacity units consumed more total fuel than the
large units. The bulk of the fuel consumption for these medium-capacity turbines was either in the
oil and gas industry, where units operate almost constantly, or in private sector electricity gene-
ration, where units operate about three-quarters of the time.
5.1.2.5 Reciprocating 1C Engines
This sector is composed of an extremely wide range of designs, applications and manufacturers.
A recent study (Reference 5-26), however, has extensively characterized reciprocating 1C engines in
terms of installed capacity and annual generation by fuel, and data from this study have been used
extensively for this sector. For consistency with other sections of this report, data from Refer-
ence 5-10 have been used for installed capacity, annual generation, and fuel consumption of 1C engines
used by electrical utilities. Table 5-7 gives fuel consumption figures for the significant types of
equipment for this sector as determined in Section 2.
The following assumptions were used in arriving at these estimates:
• Specific fuel consumption averaged 9.9 MJ/kW-hr (7,000 Btu/hp-hr), 11.3 MJ/kW-hr (8,000
Btu/hp-hr), and 11.3 MJ/kW-hr for large, medium, and small capacity ranges respectively
• Specific fuel consumption does not vary with load, so that overall fuel consumption can
be determined from specific fuel consumption and generation totals
• No gasoline is burned in large or medium capacity equipment
t No natural gas is burned in small capacity equipment
5-13
-------
TABLE 5-7. 1974 RECIPROCATING 1C ENGINE FUEL CONSUMPTION (kJ x 10'15)
Reciprocating 1C Engines
Compression Ignition
>75 kW/cyl
Spark Ignition
>75 kW/cyl
CI
75 kW to 75 kW/cyl
>1000 RPM
SI
75 kW to 75 kW/cyl
>1000 RPM
CI
<75 kW
SI
<75 kW
Natural
Gas
—
0.813
—
0.043
—
— •
Distillate
Oil
(Diesel)
0.054
—
0.129
•—
—
—
Gasoline
—
— —
— •
0.084
—
0.049
Dual
(Oil + Gas)
0.058 Gas
0.012 Oil
•—
—
— •
—
—
Total
Fuel
0.123
0.813
0.129
0.127
—
0.049
-------
The total energy consumed by this sector 1s about 3 percent of the total stationary source
energy converston fuel consumption. Much more natural gas 1s used than oil, predominantly in the
large-bore units. The major user of natural-gas-flred, large-bore engines is the oil and gas indus-
try, where units operate essentially full-time.
5.1.2.6 Industrial Process Heating
For the industrial process heating equipment, production totals for various processes within
the sector were used instead of fuel consumption totals. One reason for this approach is that
emission factors for industrial process heating are usually presented in terms of production totals.
Also, production figures are far more reliable than energy consumption statistics for the heating
operations in most industries.
Table 5-8a gives production data for the major process heating industries. Table 5-8b pre-
sents refinery process heating fuel consumption for 1974. Because the statistics kept by industry
associations are fairly complete, and there are a high number of reliable sources for this information,
these data are considered to be of high quality. The primary sources for these statistics were:
• Walden —data on the iron and steel industry (Reference 5-27)
• Bureau of Mines —data on the iron and steel industry, cement industry, brick and ceramic
industry (Reference 5-15}
• IGT —data on cement kilns, glass manufacture, petroleum refineries, cement industry
(Reference 5-28)
• TRC — data on brick and ceramic kilns (Reference 5-20)
• Lockheed — data on refinery flaring (Reference 5-29)
t KVB - data on refinery process heaters (Reference 5-30)
5.2 EMISSION FACTORS
This section presents uncontrolled emission factors for the significant stationary sources of
NOX identified in Section 2 of this report. Emission factors were compiled for the following fuels:
lignite, bituminous, and anthracite coal; distillate and residual oil, and natural gas. Since data
from process gas utilization are inadequate, emission factors have not been included for this fuel.
Whenever possible, emission factors will be expressed in terms of fuel inputs, i.e., nanograms N02
Per Joule heat input. If .emissions are less dependent on fuel consumption -as in the chemical
process industries - they will be expressed as a function of product output.
5-15
-------
TABLE 5-8a. 1974 INDUSTRIAL PROCESS HEATING
PRODUCTION
Industrial Process Heating
Annual Production
Cement Kilns
Glass Melting Furnaces
Glass Annealing Lehrs
Coke Oven Underfire
Steel Sintering Machines
Open Hearth Furnaces
Brick and Ceramic Kilns
Catalytic Cracking
Refinery Flares
Iron and Steel Flares
7.696 x 107 Mg
1.542 x 107 Mg
1.542 x 107 Mg
5.701 x 107 Mg
4.851 x 107 Mg
3.227 x 107 Mg
3.158 x 107 Mg
2.294 x 1011* feed
7773 Mg N0x/yra
318 Mg N0x/yra
aNO estimates
A
TABLE 5-8b. 1974 REFINERY PROCESS HEATING
FUEL CONSUMPTION (kJ x lO'15)
Heater Type
Natural Draft
Forced Draft
Total
Natural Gas
1.119
0.1282
1.2472
Oil
0.2565
0.0806
0.3371
Total
1.3755
0.2088
1.5843
5-16
-------
Criteria pollutants, NOX, SOX, HC, CO, and total participate, have been extensively tested
and the quality of the resulting emission factors 1s generally high. Unfortunately, the quality
of the measurements for less studied species - polycyclic organic material (POM), sulfates, and
trace elements -varies widely. Tables of emission factors for criteria pollutants have been
included 1n the text, while those for ROMs, sulfates and trace metals and corresponding emissions
are contained in Appendix A.
Figures for emission factors have been obtained from AP-42 (Reference 5-31) and its supple-
ments, from a survey of existing literature, and from preliminary results of ongoing test programs.
Whenever possible, AP-42 and its supplements have been used, since they typically reflect the most
recent test results. In cases where emission factors are not available for specific design types
from these sources, estimates of emission factors have been made from test results on similar equip-
ment. In some instances, a range of emission factors is available and in these cases a representative
average value has been assigned. Each of the following subsections includes a discussion of the
sources for the data given on emission factors, along with the rationale for their selection and
their relation to AP-42 emission factors. It should be emphasized that the following factors rep-
resent uncontrolled operating conditions without the use of pollution control devices, except where
noted.
5.2.1 Utility and Large Industrial Boilers
Table 5-9 gives uncontrolled emission factors for the criteria pollutants from utility
boilers. NO emission factors for these boilers were obtained from AP-42 supplements (References
5-32, 5-33). These values are in good agreement with measurements obtained from utility boiler
field testing (References 5-34 through 5-41). Values for cyclone furnaces and lignite-fired boilers
were obtained from more recent studies (References 5-11, 5-12).
Emission factors for SO , PART, HC, and CO were gathered from a search of the available
A
literature for bituminous coal-fired, tangential, single-wall-fired or opposed-wall furnaces
(References 5-34 through 5-41). Because there are very little available data for vertical-fired
boilers, AP-42 emission factors (Reference 5-31) were used for this inventory. Emission factors
for HC and CO from tangential, single- and opposed-wall, residual-oil-fired boilers were obtained
from References 5-34 through 5-41. These numbers are considerably lower than AP-42 values. Par-
ticulate and SOX emission factors from AP-42 used here are in excellent agreement with represen-
tative field testing (References 5-32, 5-33). AP-42 and its supplements were also used as a source
of emission factors for distillate oil and natural gas, but these values have not been verified
since boiler field tests of these fuels are not available.
5-17
-------
TABLE 5-9. UTILITY BOILER CRITERIA POLLUTANT EMISSION FACTORS (ng/J)
Equipment Type
Utility Boilers
Tangential
Anthracite
Bituminous and Subbituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Single Wall -Fired
Anthracite
Bituminous and Subbituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Opposed Wall and Turbofurnace
Anthracite
Bituminous and Subbituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Cyclone
Anthracite
Bituminous and Subbituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Vertical and Stoker
Anthracite
Bituminous and Subbituminous
Lignite
NOX
275
275
245
153
153
129
322
322
353
322
322
301
322
322
353
322
322
301
559
559
374
219
219
241
269
269
269
V
585S
602S
808S
482S
434S
0.3
585S
602S
808S
482S
434S
0.3
585S
602S
808S
482S
434S
0.3
585S
679S
808S
492S
6.0
0.3
585S
679S
808S
Parta'b
261A
195A
175A
30. 5S + 8.6 (30.5)
6.0
2.2 - 6.5 (4.3)
261A
186A
175A
30. 5S + 8.6 (30.5)
6.0
2.2 - 6.5 (4.3)
261A
186A
175A
30. 5S + 8.6 (30.5)
6.0
2.2 - 6.5 (4.3)
35. 7A
35. 7A
174.5A
30. 5S + 8.6 (30.5)
6.0
2.25 - 6.4 (4.3)
30. 5A
233A
188A
CO
15.5
11.2
27.1
8.6
15.5
7.3
15.5
21.9
27.1
13.3
15.5
11.6
15.5
8.6
27.1
12.5
15.5
10.7
15.5
18.1
27.1
15.5
15.5
7.3
92.0
35.7
53.7
HC
0.43
0.86
8.2
0.86
6.0
0.86
0.43
0.86
8.2
0.86
6.0
0.86
0.43
0.86
8.2
0.86
6.0
0.86
6.45
6.45
8.17
6.02
6.02
6.02
3.01
5.59
8.17
10
in
1-
S represents the percent sulfur in the fuel, A represents the percent ash in the fuel
Numbers in parentheses are average values
5-18
-------
Polycyclic organic matter (POM) values for utility boilers come from References 5-41 and
5-42. Unfortunately, values for coal-fired power plants vary by two or three orders of magnitude
depending upon equipment type. Consequently, a range of values has been given rather than a single
specific value.
Sulfate emission factors for coal-fired utility boilers were determined from field testing
(Reference 5-43).
Trace metallic emission factors for this sector come from References 5-5, 5-6, 5-9 and 5-44
through 5-48. There is fair agreement concerning the partitioning and enrichment properties of
specific trace elements presented in these studies; however, agreement is not sufficient to warrant
any more than average trace metal concentrations in the fuel. As a result, care must be used in
applying these emission factors. It should be noted that they are presented here as estimates rather
than as exact values.
5.2.2 'Packaged Boilers
Packaged boilers were divided into two capacity groupings: boilers of capacity of 23 MW
to 73 MW (100 to 250 MBtu/hr), and boilers of capacity of less than 29 MW of fuel. Table 5-10 pre-
sents uncontrolled emission factors for the criteria pollutants for these two classes of boilers.
The emission factors given come from industrial boiler field tests (References 5-49 through 5-51)
and AP-42 and its supplements (References 5-31 through 5-34).
The firing and emission characteristics of the large industrial boilers are similar to those
of utility boilers. CO and HC emission factors for bituminous coal, oil, and gas obtained from the
results of field tests (References 5-49 and 5-50) are considerably lower than those supplied by
AP-42. NO , particulates, and SO emission factors for large packaged boilers came from both field
x x
tests (References 5-49, 5-50) and AP-42 and its supplements (References 5-31 through 5-33). There
is excellent correspondence between these two data>sources. Since there has been very little field
testing of boilers firing anthracite coal, emission factors for this fuel are from AP-42.
Emission factors for the group of packaged boilers less than 29 MW capacity came largely
from field tests of industrial and commercial boilers at baseline operating conditions (References
5-49 through 5-52). The data were averaged where baseline data were available for more than one unit
of a specific design type. If test data were not available for a specific equipment/fuel combination,
AP-42 numbers or test data from similar equipment were substituted.
In general, there is excellent correspondence between AP-42 supplements (References 5-32,
5-33) and field testing (References 5-49 through 5-52) for criteria pollutants from packaged boilers.
5-19
-------
TABLE 5-10. PACKAGE BOILER CRITERIA POLLUTANT EMISSION FACTORS (ng/J)
Equipment Type
Watertube-Wall Firing
29 MW to 73 MW
Anthracite
Bituminous and Lignite
Residual Oil
Distillate Oil
Natural Gas
Process Gas
Watertube Stoker
29 to 73 MW
Anthracite
Bituminous and Lignite
Watertube
<29 MW
Residual Oil
Distillate Oil
Natural Gas
Process Gas
Firetube Scotch
Residual Oil
Distillate Oil
Natural Gas
Process Gas
Firetube/ Firebox
Residual Oil
Distillate Oil
Natural Gas
Process Gas
HRT Firetubes
Residual Oil
Distillate Oil
Natural Gas
Cast Iron Boilers
Residual Oil
Distillate Oil
Natural Gas
Watertube Stoker
<29 MW
Anthracite
Bituminous and Lignite
N0x
322
322
322
322
301
301
269
269
184
67.5
98.9
98.9
184
67.5
98.9
98.9
184
67.5
98.9
98.9
184.5
67.5
98.9
184
67.5
51.6
179
179
V
585S
559S
408S
434S
0.3
-
584. 7S
756. 6S
482S
434S
3.4
-
482S
434S
0.3
-
482S
434S
0.3
—
482S
436S
0.3
482S
434S
0.3
585S
672S
Particulates3
261A
186A
30. 5S + 8.6
7.74
1.72
-
30. 5A
233A
30. 5S + 8.6
8.2
3.4
—
30. 5S + 8.6
7.3
2.6
—
30. 5S + 8.6
7.3
2.6
—
83
3.9
2.6
30. 5S + 8.6
3.7
2.6
31A
232A
CO
0.6
0.04
3.9
-
9.0
-
92
25
3.4
1.6
8.6
—
3.4
1.6
8.6
_
3.4
1.6
8.6
_
3.4
1.7
8.6
3.4
1.6
8.6
92
21
HC
0.43
2.2
3.0
3.0
3.9
-
3.0
4.3
0.86
0.43
1.7
—
0.86
0.43
1.7
_
0.86
0.43
1.7
_
0.9
0.4
1.7
0.86
0.43
1.7
3.0
18
S represents sulfur of fuel; A represents percent ash of the fuel
5-20
-------
TABLE 5-10. Concluded
Equipment Type
Firetube Stoker
Anthracite
Bituminous and Lignite
Residential Steam Units
Anthracite
Bituminous and Lignite
Residual Oil
Distillate Oil
, Natural Gas
N0x
179
179
179.3
179.3
162
55
34.4
V
585S
672S
585S
679S
^815
434S
0.26
Particulates3
31A
232A
307
358.2
83
7.7
4.3
CO
92
21
138
1612.5
15.48
30.5
8.6
HC
3.0
18
307
358.2
3.01
4.73
3.4
.0
o
in
S represents sulfur of fuel; A represents percent ash of the fuel
5-21
-------
The only area of significant disagreement is the emission factors for small packaged oil-fired
boilers, where values from field testing (References 5-49 through 5-52) are considerably lower than
AP-42 supplement values (Reference 5-33). In general, small watertube, scotch firetube, firebox
firetube, HRT firetube, and cast iron boilers fired by single burners have quite similar combustion
characteristics and thus, similar emission factors.
POM emission factors for packaged boilers came from recent field testing (References 5-54
through 5-56), and from AP-33 (Reference 5-42). Again, there are several orders of magnitude between
AP-33 values and the results of recent field tests. Because available data are scarce and available
measurements vary widely, a range has been presented rather than specific values. In addition, it
has been assumed that scotch firetubes, HRT firetubes and firebox firetubes have the same POM emission
characteristics, and that shell boilers and cast iron boilers are also similar. A trend toward
larger POM emissions from smaller units is clearly evident. Smaller units are usually less care-
fully regulated, which means less efficient firing and operation, resulting in poor combustion.
Field testing data for sulfate emissions and trace elements from packaged boilers are quite
sparse. Some field testing has been performed (Reference 5-51), but little data have been quantified.
It is assumed that trace element emission factors will be similar for large packaged and utility
boilers since they often have similar operating characteristics to utility boilers. This assumption
does not hold, however, for small packaged boilers. Care must be exercised in using trace element
factors, since they may vary by two or more orders of magnitude depending on the fuel.
5.2.3 Warm Air Furnaces
Table 5-11 gives uncontrolled emission factors for the criteria pollutants from warm air
furnaces. NOV emission factors have been determined from the results of recent field tests (Ref-
A
erence 5-52) and from AP-42 supplements (Reference 5-33). Emission factors for the remaining cri-
teria pollutants came from field testing (References 5-52, 5-53, 5-57), studies (References 5-58,
5-59), and AP-42 supplements (References 5-32, 5-33). In general, the agreement between these dif-
ferent sources of data is excellent. As a result, values from AP-42 supplements are felt to repre-
sent the emission characteristics of warm air furnaces accurately, and the majority of the emission
factors given for warm air furnaces comes from these supplements.
Little testing has been done on POHs emitted from warm air furnaces. AP-33 (Reference 5-42)
does report some POM emissions data. Since supporting data are lacking and most POM testing is
inconsistent, these values, presented in Appendix A, are only an order of magnitude estimate of
POM emissions.
5-22
-------
TABLE 5-11. WARM AIR FURNACE AND MISCELLANEOUS COMMERCIAL
AND RESIDENTIAL COMBUSTION CRITERIA POLLUTANT
EMISSION FACTORS (ng/J)
Equipment Type
Warm Air Central Furnace
Oil
Natural Gas
Warm A1r Room Heaters
Oil
Natural Gas
Miscellaneous Combustion
Natural Gas
N0x
61.0
34.4
61.0
34.4
34.4
soxa
434S
0.358
434S
0.258
0.258
Part
7.7
2.2 - 6.5 (4.3)
7.7
2.2 - 6.5 (4.3)
2.2 - 6.5 (4.3)
CO
31
12
31
12
12
HC
4.7
3.4
4.7
3.4
3.4
S represents percent sulfur in the fuel
All miscellaneous combustion fuels (wood, LPG, etc.) combined with
natural gas
cNumbers in parentheses denote average values
5-23
-------
Sulfate emission factors from warm air furnaces were not available.
Trace element emission factors for warm air furnaces cannot be determined from the existing
data. The only significant source would be the small number of coal-fired units. These are in-
significant on a national scale but could present localized pollution problems.
5.2.4 Gas Turbines
Emission factors for gas turbines come from field studies (References 5-22, 5-60} and an
AP-42 supplement (Reference 5-61). Table 5-12 presents uncontrolled emission factors for the cri-
teria pollutants, primarily from the recent Gas Turbine Standard Support Document (Reference 5-22).
Values from the AP-42 supplement in this section for non-NOx criteria pollutants are in excellent
agreement with values from field studies (References 5-60, 5-62).
Emission factors for POMs and sulfates from gas turbines cannot be determined at present
due to the lack of representative field testing.
5.2.5 Reciprocating 1C Engines
The range of equipment design combinations for reciprocating 1C engines is so varied that
it is impossible to determine emission factors for each equipment combination using the available
data. Consequently, reciprocating 1C engines have been categorized as either spark ignition or
compression ignition engines in three capacity ranges. Table 5-13 presents uncontrolled emission
factors for the criteria pollutants for these equipment types.
NOV emission factors have been derived from values presented in a current 1C engine study
A
(Reference 5-26). Non-N0x criteria pollutant emission factors come from recent AP-42 supplements
(References 5-32, 5-33). These values correspond closely with the results of field tests (Reference
5-63).
Sufficient data are not available to quantify emission factors for POMs, sulfates, and
trace elements from reciprocating 1C engines. Trace element concentrations will vary by orders of
magnitude depending on the fuel and the operating characteristics of the reciprocating engine
measured. Because of this, determining specific emission "factors to span this range of values is
not possible.
5.2.6 Industrial Process Combustion
Direct process heat from fuel combustion has a wide range of industrial applications and
is produced by many different types of equipment. In addition, process heat is generated in many
5-24
-------
TABLE 5-12. GAS TURBINE CRITERIA POLLUTANT
EMISSION FACTORS (ng/J)
IM
tn
Equipment Types
Gas Turbine
>15 MW
Natural Gas
Diesel oil
Gas Turbine
4 MW to 15 MW
Natural Gas
Diesel oil
Gas Turbine
<4 MW
Natural Gas
Diesel oil
N0x
195
365
194
365
194
365
S0x
2.2
10.7
2.2
10.7
2.2
10.7
PART
6.0
16.0
6.0
15.5
6.0
15.5
CO
49.0
47.0
49.4
47.3
49.4
47.3
HC
8.6
8.6
8.2
9.9
8.2
9.9
-------
TABLE 5-13. RECIPROCATING 1C ENGINE CRITERIA
POLLUTANT EMISSION FACTORS (ng/J)
Comp Ignition
>75 kW/cyl
Dist Oil
Dual Fuel
Spark Ignition
>75 kW/cyl
Natural Gas
CI 75 kW to
75 kW/cyl
>1,000 RPM
Dist Oil
SI 75 kW to
75 kW/cyl
>1,000 RPM
Natural Gas
Gasoline
CI <75 kW
2-4 cyl
Dist. Oil
SI 75 kW
2-4 cyl
Gasoline
NOX
1,741
1,023
1,552
1,741
1,552
1,195
1,677
774
S0x
95.9
—
0.22
95.9
0.22
16.3
95.9
16.3
PART
103
—
—
103
—
19.8
95.9
19.8
CO
313
—
177
313
177
12,081
313
12,081
HC
115
—
555
115
555
405
115
405
5-26
-------
industries by a large number of small-scale processes which as a whole may have a significant impact,
but which are individually hard to quantify. Nonetheless, there are several industries which con-
stitute the major pollution sources, and these industries will be considered in this section. Un-
controlled emission factors for the criteria pollutants based on product output are presented in
Table 5-14a. Refinery process heating emission factors are presented in Table 5-14b.
Cement and glass industries which use kilns, furnaces, and ovens to heat raw materials are
a significant source of N0x> Emission factors for N0x from these processes come primarily from a
recent study of these industries (Reference 5-28). Non-NO criteria pollutant emission factors
X
have partially been determined from AP-42 values (Reference 5-31). Very few data are presently
available for sulfates, ROMs, and trace elements from cement kilns. Sulfate emission factors come
from Reference 5-64, although the values presented are questionable.
The extensive use of ovens and furnaces in the iron and steel industry results in the produc-
tion of major quantities of NO . Most of these emissions come from coke oven underfiring, steel
sintering machines, and open hearth furnaces. Noncriteria pollutant emissions data from the iron
and steel industry are not available. NO emission factors from the iron and steel industry have
been determined from Reference 5-27- Other criteria pollutant factors come from References 5-20 and
5-27.
Other NO sources in the petroleum industry are refinery flares, fluid catalytic crackers
X
and process heaters. NO emission factors for refinery flares and catalytic crackers were obtained
from a recent study of process heating (Reference 5-28). N0x emission factors from refinery process
heaters were obtained from a recent study conducted by KVB (Reference 5-30). The values reported here
are for both natural draft and forced draft refinery heaters firing gas and oil. The values are ten-
tative pending completion of the KVB study. Emission factors for other criteria pollutants for re-
finery process heaters are based on values reported in AP-42. Emission factors for other criteria
pollutants come from AP-42 (Reference 5-31) and from emission studies (References 5-20, 5-65). Non-
criteria emission factors are not available.
The contact process used in the production of sulfuric acid requires burning of sulfur in a
combustion chamber, which generates significant N0x emissions. The emission factor for S0x comes
from Reference 5-20.
5.3 EFFECT OF EMISSION CONTROL REGULATIONS
The preceding section provided estimates of pollutant emission factors for the major sta-
tionary combustion sources without accounting for control devices which are currently being employed.
Because of both state and local regulations, emissions of SO and particulates from the large point
X
5-27
-------
TABLE 5-14a. INDUSTRIAL PROCESS COMBUSTION CRITERIA POLLUTANT
EMISSION FACTORS (g/kg PRODUCT)
Cement Kilns
Glass Melting Furnaces
Glass Annealing Lehrs
Coke Oven Underfire
Steel Sintering Lines
Open Hearth Furnaces
Brick & Ceramic Kilns
Catalytic Cracking
Refinery Flares
Iron & Steel Flares
N0x
1.30
3.68
0.69
0.07
0.52
0.62 oil
0.37 gas
C.23
0.203
b
S0x
5.09
2.12
NA
2.84
0.71
0.70
0.54
1.413
NIL
PART
122
1.0
NA
37.7
10-
6.
65.
0.69a
NIL
CO
NA
NA
NA
NA
22.
NA
0.1
39. la
NIL
HC
NA
NA
NA
NA
NA
NA
0.04
0.63
0.43C
ag/l Feed
Production is not quantifiable. Estimate of NO is made in fuel consumption section.
cg HC/1 capacity
TABLE 5-14b. REFINERY PROCESS HEATING CRITERIA POLLUTANT
EMISSION FACTORS (ng/J) (Reference 5-30)
Heater
Type
Natural
Draft
Forced
Draft
Fuel
Gas
Oil3
Gas
Oil3
NOX
70.1
154.8
110.5
184.5
S0x
860Sb
627SC
860Sb
627SC
PART
8.6
78.4
8.6
78.4
CO
NILd
NIL
NIL
NIL
HC
12.9
13.07
12.9
13.07
Assumed fuel oil nitrogen content of 0.2 percent and a fuel nitrogen
conversion to NO of 50 percent
Refinery gas sulfur content (lb/100 ft3)
(assumed 10 grain/100 ft3 based on Federal EPA regulations)
Fuel oil sulfur content (weight percent) (assumed 0.1 percent)
Negligible emissions
5-28
-------
sources have been extensively controlled. NOX-emissions have been less extensively regulated, how-
ever, so NOX controls applied to existing equipment are less commonplace. This section describes the
degree of control which now exists for participates, SO , and NO and applies these controls to
A X
applicable equipment to more accurately represent present mass emission totals. The emission inven-
tory presented in the following section gives particulate and S0v emissions for the controlled state;
X
only NO emissions are given for both uncontrolled and controlled uses for comparison.
5.3.1 Particulate Control
The most common types of particulate control equipment are centrifugal collectors and electro-
static precipitators. Coal- and oil-fired boilers contribute approximately 98 percent of utility
boiler particulate emissions; hence the controls on these boilers are most important. Gas-fired
boiler particulate emissions are insignificant and will not be considered further in this section.
Representative values for the percent of particulate controls in the utility and industrial sector
and the impacts of these controls on total particulate emissions are presented.
5.3.1.1 Utility Boilers
Information on the types of controls used on utility boilers of different sizes comes from
NEDS and two recent particulate studies of emissions (References 5-6, 5-59, and 5-66). According to
these studies, electrostatic precipitators and centrifugal collectors make up over 96 percent of the
particulate controls installed on utility boilers. Twelve percent of pulverized coal-fired boilers
have no collection devices. Table 5-15 displays the percent of particulate collected from utility
boilers. Approximately 35 percent of oil-fired boilers are not controlled. Assuming representative
efficiencies for control equipment types, it has been estimated that 75 percent of the particulate
generated in residual oil-fired boilers is not collected. More importantly, 35 percent of the flyash
formed in pulverized coal-fired boilers, 25 percent in cyclone boilers and 50 percent in stokers are
also not collected.
5.3.1.2 Industrial Boilers
A recent source assessment document for industrial boilers (Reference 5-67) has been used
to determine the distribution of controls for pulverized coal-fired boilers, stokers, and residual
and distillate oil-fired boilers. Approximately 75 percent of small industrial stokers (<29 MW) and
30 percent of the larger boilers are not controlled. It is assumed that controls for small pulverized
coal industrial boilers (<29 MW) are insignificant. As displayed in Table 5-15, about 50 percent
of the particulate emissions from large coal-fired industrial boilers are collected. However, for
5-29
-------
TABLE 5-15. AVERAGE PARTICULATE COLLECTION
Sector
Utility Boilers
Package Boilers
Industrial Pro-
cess Combustion
Equipment/Fuel
All/Pulv. Coal
Cyclone/Coal
Stoker/Coal
All/Residual Oil
29 to 73 MW
Wall-Fired/Pulv. Coal
Stoker/Coal
Wall -Fired/Residual Oil
Wall -Fired/Distill ate Oil
<29 MW
Stoker/Coal
Cement Kilns
Percent Collection
. 65
75
50
25
50
50
5
0
15
88
5-30
-------
smaller units, 95 percent of the particulates from residual oil-fired boilers and 15 percent of the
particulates from small coal stokers are released to the atmosphere.
5.3.1.3 Industrial Processes
In the industrial sector, the cement industry is controlled extensively by the use of cyclones
and electrostatic precipitators. Table 5-15 shows that approximately 12 percent of particulate
emissions are not separated from the effluent stream by collection devices (Reference 5-68).
In Section 5.4 the emissions inventory will be displayed as a function of controlled parti-
culates. Since the large majority of boilers do possess particulate controls, an uncontrolled
inventory would not represent the current impact of controls implementation.
5.3.2 SOX Control
To determine the extent of SOX control on stationary combustion sources, the two commercially
available means of SOX control -flue gas desulfurization and low-sulfur fuel -were examined both
for their extent of use and their effectiveness. Coal cleaning currently has seen insignificant
use nationwide. Two recent surveys of flue gas desulfurization (References 5-69, 5-70) indicated
that the total installed capacity of FGD equipment on utility-size boilers is about 5,000 MW. When
this is compared to the total electrical utility boiler installed capacity of about 350,000 MW
(Reference 5-10), the effect of FGD systems is clearly small.
The primary means of meeting local SO control regulations is through the use of low-sulfur
fuel either totally or in blends with high sulfur fuel. Since the sulfur concentration in these fuels is
strictly monitored at the utility level, the use of utility fuel consumption and sulfur concentra-
tion data will result in a controlled inventory. Since the utility sector is the most heavily regu-
lated and uses the large majority of sulfur containing coal and oil, the controlled utility inventory
combined with uncontrolled emissions of the remaining sectors will serve as the controlled S0x in-
ventory. The SO inventory presented in Section 5.4, therefore, will reflect the controlled state
X
for all stationary combustion sources.
5-3.3 NOX Control
To determine the extent of NOX control for stationary combustion sources, a different approach
was used than for particulates and SOX. In this approach, applicable state and local NOX regulations
(summarized in Section 4.1 of this report) were applied to combustion equipment within the region.
Examination of the regulations showed that utility boilers are the most extensively regulated, while
gas turbines and large packaged boilers are only regulated in some regions. Examination of data on
utility and gas turbine installations and fuel consumption showed that only controls for utility
5-31
-------
boilers would have greater than a 1 percent effect. Thus, only utility boilers are considered in
the following discussion of NO controls.
In calculating the effect of NO controls on utility boiler emissions, the uncontrolled emis-
sions of a specific boiler were reduced by the ratio of the controlled emission factor to the un-
controlled factor. For example, if the emission limitation for oil-fueled boilers is 129 ng/J and
the uncontrolled emission factor is 153 ng/J, then the reduction of N0x emission (assuming 100 per-
cent compliance) is (1 - 129/153) or 16 percent. A more detailed explanation of the methodology em-
ployed to arrive at specific control factors is given in Appendix A. A systematic compilation of
stationary source equipment and applicable NO regulations yielded the control factors listed in
X
Table 5-16.
TABLE 5-16. NOX CONTROL FACTORS
Tangential
Wall -Fired
Horiz. Opposed
Cycl one
Vert, and Stoker
Coal
0.000053
0.0014
0.0014
0.0166
0.00005
Oil
0.014
0.048
0.048
0.039
-
Nat. Gas
0.057
0.124
0.124
0.0
-
Note that the degree of current control of coal-fired utility boilers is small, while those
which burn oil or gas are significantly controlled. The control of coal-fired utility boilers is
increasing, however, as retrofit controls are being implemented in a number of areas and as new units
designed to meet the NSPS (300 ng/J) are being installed. One reason for lack of control of coal-
fired boilers is the prior lack of NOX regulations in states where coal is heavily used, and 'the
comparatively stringent regulations in states which use large amounts of oil and gas. Comparisons
of the controlled and uncontrolled NOX emission rates will be presented in Section 5.4.
5.4 EMISSIONS INVENTORY
This section presents an inventory of major combustion-related pollutants originating from
stationary fuel-burning sources of NOX- The inventory includes the criteria pollutants: NOX, SOX,
CO, HC, and particulates emitted from gaseous effluent streams. A more complete emissions inventory
is given in Appendix A by equipment type for 17 fuel categories and the following noncriteria
pollutants: sulfates, trace metallics, ROMs and trace elements in hopper and flyash.
5-32
-------
5.4.1 Stationary Source Sector Emissions
Tables 5-17 through 5-22 provide 1974 criteria pollutant emissions and totals for the fol-
lowing sectors:
t Utility boilers -Table 5-17
t Packaged boilers -Table 5-18
• Warm air furnaces —Table 5-19
• Gas turbines —Table 5-20
• Reciprocating 1C engines —Table 5-21
• Industrial process heating - Table 5-22 (Includes total criteria pollutant emissions for
oil- and gas-fired refinery process heaters)
The emission estimates are for 1974 since this is the most recent period for which comprehensive
fuel consumption data are availabe. All units are in 1000 Mg per year. Note that these tables give
uncontrolled emission figures for NOX and controlled emission figures for SOX and particulates.
Table 5-23 summarizes the total emissions from the above sectors.
5.4.2 Controlled NOX Emissions
Table 5-24 presents the controlled NOX emissions derived from control factors developed in
Section 5.3 for stationary sources. As discussed in that section, controlled NOV emissions are
+
given for utility boilers only, since gas turbines and packaged boiler NOX regulations were con-
cluded to have little effect on sector totals. This inventory applies existing 1976 state and
local NOX relations to the 1974 stationary source population. This hybrid inventory is not intended
to accurately represent actual NOX emissions for either year, but merely to indicate the current
effect of NOX emission regulations. The degree of utility boiler control is somewhat uncertain
since some units are not in compliance with regulations either through variances or lack of enforce-
ment. Some units, on the other hand, are controlled to levels below the current regulations. In
a few areas utilities have added NOX control, in the absence of regulations, as part of public
relation efforts or for energy conservation (low excess air firing). These units have been gen-
erally excluded from the controlled boiler inventory.
5-33
-------
TABLE 5-17. 1974 CRITERIA POLLUTANT EMISSIONS FOR THE UTILITY
BOILER SECTOR (UNCONTROLLED NOY) 1,000 Mg/yr
/\
Furnace Design
Tangential
Wall -Fired
Opposed Wall
Cyclone
Stoker. & Vertical
Totals
Fuel
Coal
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas
NO
X
1,409
208
146
946
481
738.3
270.8
177.7
378.7
863.5
16.6
14-7
90.9
—
—
5,741.2
SO
X
6,999.6
583.3
0.34
4,030.6
598.6
0.74
1,131.6
236
0.38
2,737.4
34.9
0.018
414.7
—
—
16,768.2
HC
4.8
1.36
0.98
2.61
2.15
2.11
0.88
0.55
1.07
10.4
0.46
0.37
1.63
—
—
29.5
CO
"58.3
11.9
8.2
64.4
20.3
28.2
7.55
6.9
13.4
30.0
1.18
0.44
18.4
—
—
269.2
PART
3,178
30.5
4.84
1,734
31.1
10.5
499
!12.9
5.36
193
1.74
0.26
263.8
—
—
5,965
5-34
-------
TABLE 5-18. 1974 CRITERIA POLLUTANT EMISSIONS FOR THE PACKAGE
BOILER SECTOR (UNCONTROLLED NO) 1,000 Mg/yr
/\
V
Equipment Design
Type
Watertube
29 MW to 73 MW
Watertube
<29 MW
Fi retube
<29 MW
Other3
Total
Fuel
Coal
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas
Coal
Oil
Gas
NOX
290
232.8
318.5
278.17
116.4
180
107
429.25
241.7
4.48
107.7
38.98
2,345
S0x
1,402
269
0.28
2,280
298
5.75
839
1,048
0.72
20.4
242
0.27
6,405
HC
3.10
2.17
3.62
27.66
0.57
2.87
10.1
2.14
4.09
8.24
4.62
2.95
72.13
CO
11.7
2.8
8.4
34.13
2.19
14.5
15.5
8.35
20.69
19.7
28.86
8.61
175.4
PART
935.8
24.3
1.6
2,787.8
24.1
2.8/
1,016
98.7
6.26
8.24
20.8
3.86
4,930.3
alncludes cast iron and residential steam and hot water units
-------
TABLE 5-19. 1974 CRITERIA POLLUTANT EMISSIONS FOR THE WARM AIR
FURNACE AND MISC-COMBUSTION SECTOR (UNCONTROLLED NO ) 1,000 Mg/yr
- • /\
Equipment
Warm Air Central Furnace
Warm Air Room Heater
Miscellaneous Commercial
and Residential Combustion
Total
Fuel
Oil
Gas
Oil
Gas
Gas
N0x
85.0
106.3
44.0
49.5
34.4
320.6
S0x
152
1.106
78.4
0.37
0.258
232
HC
6.59
10.5
3.41
4.95
4.3
29.7
CO
43.6
36.9
22.0
17.3
12
132.6
i
PART
10.8
13.2
5.58
6.24
3.4 .
39.3
-------
TABLE 5-20. 1974 CRITERIA POLLUTANT EMISSIONS FOR THE GAS
TURBINE SECTOR (UNCONTROLLED NO ) 1,000 Mg/yr
X
V
10
-J
Equipment Capacity
Range
Gas Turbine
>T5 MW
Gas Turbine
4 MW to 15 MW
Gas Turbine
<4 MW
Total
Fuel
Oil
Gas
Oil
Gas
Oil
Gas
NO
X
97.4
41.3
211
91.2
0.365
0.195
440
S0x
2.81
0.47
6.17
1.04
0.0135
0.0026
10.5
HC
2.25
1.81
5.73
3.84
0.012
0.0094
13.7
CO
12.4
10.34
27.2
23.1
0.047
0.049
73.4
PART
4.22
1.27
8.89
2.79
0.019
0.0070
17.3
-------
TABLE 5-21. 1974 CRITERIA POLLUTANT EMISSIONS FOR THE RECIPROCATING
I.C. ENGINE SECTOR (UNCONTROLLED NO ) 1,000 Mg/yr
A
Equipment Capacity
Range
I.C. Engines
>75 kW/cyl
I.C. Engines
75 kW to 75 kW/cyl
I.C. Engines
<75 kW
Total
Fuel
Oil
Gas
Dual
Oil
Gasoline
Gas
Gasoline
NOX
94.0
1,262
71.6
224.6
100.4
66.7
37.5
1,857.2
S0x
5.10
0.17
—
12.3
1.36
0.0091
0.80
19.6
HC
6.13
451
29.1
14.7
33.7
23.9
19.6
578.3
CO
16.6
143
9.6
40.0
1,014.8
7.6
591.9
1,824
PART
5.56
—
13.1
1.65
—
0.96
21.5
-------
TABLE 5-22. 1974 CRITERIA POLLUTANT EMISSIONS FOR THE INDUSTRIAL PROCESS HEATING SECTOR
(UNCONTROLLED NO ) 1,000 Mg/yr
£
\o
Industrial Equipment
Category
Refinery Heaters
Cement Kilns
Glass Melting Furnaces
Glass Annealing Lehrs
Coke Oven Underfire
Steel Sintering Lines
Open Hearth Furnaces
Brick & Ceramic Kilns
Catalytic Cracking
Refinery Flares
Iron & Steel Flares
Total
N0x
147.35
100.0
56.7
10.6
3.99
25.2
20.6
7.26
46.0
7.77
0.32
425.8
S0x
22.67
392.0
32.2
—
161.9
34.1
22.6
16.5
323.0
—
—
1,005.0
HC
20.5
—
—
—
—
—
—
1.26
144.5
—
—
166.3
CO
—
—
—
—
—
1,067.0
—
3.16
8,969.5
—
—
10,039.0
PART
37.2
1126.0
15.2
—
2,149
485
193.6
2,052.7
158
—
—
6,216.7
-------
TABLE 5-23. CRITERIA POLLUTANT EMISSIONS BY SECTOR
(UNCONTROLLED NO) 1,000 Mg/yr
y\
Equipment Sector
Utility Boilers
Packaged Boilers
Warm Air Furnaces and
Miscellaneous Combustion
Gas Turbines
Reciprocating I.C. Engines
Industrial Process Heating
Total
NOX
5,741
2,345
321
440
1,857
425.8
11,130
SOX
16,768
6,405
232
10.5
19.6
1,005
24,440
HC
29.5
72.1
29.7
13.7
578
166
889
CO
269.6
175.4
133
73.4
1,824
10,039
12,514
PART
5,965
4,930.3
39.3
17.3
21.5
£.216.7
17,190
-------
TABLE 5-24. COMPARISON OF CONTROLLED AND UNCONTROLLED STATIONARY SOURCE NOX EMISSIONS
Sector and Equipment Type
Utility Boilers
Tangential
Wall-Fired
Opposed Wall
Cyclone
Vertical and Stoker
TOTAL UTILITY
Package Boilers
Conmercial and Residential Furnaces
Gas Turbines
1C Engines
Process Heating
TOTAL
Fuel
Coal
Oil
Gas
Coal
Oil
Gas
Coal
on
Gas
Coal
Oil
Gas
Coal
All
All
All
All
All
All
All
1974
Controlled
N0xa
(1,000 Mg/yr)
1,408
205
138
945
458
649
271
169
352
849
16
15
91
5,566
2,345
321
440
1,857
425.8
10,954
1974
Uncontrolled
NOX
(1,000 Mg/yr)
1,409
208
146
946
481
738
271
178
379
863
17
15
91
5,741
2,345
321
440
1,857
425.8
11,12?
Percent
Reduction
(«)
0.1
1.4
5.5
0.1
4.8
12.3
0
5.1
6.7
1.6
6.0
0
0
3.3
-
—
-
-
1.7
in
o>
"Controlled by regulations existing December 1976
5-41
-------
5.5 SUMMARY AND CONCLUSIONS
This section presents a general summary of the NOX emissions from all sources and a more de-
tailed summary of the emissions from stationary fuel combustion sources. In addition, several com-
parisons of the data generated in this study are made with results of previous studies. A compre-
hensive emission inventory for all pollutants is given in Appendix A.
Conclusions, consisting of rankings of sources on a mass emissions basis and comments on data
quality and data gaps, are also presented.
5.5.1 Summary of NOx Emissions from all Sources
As discussed in Section 2 (Figure 2-1), NO emissions result from both natural and anthropo-
genic sources.
Natural NOX Emissions
Estimates of biologically-generated natural emissions of oxides of nitrogen range from 175 to
455 Tg (193 to 501 x 106 tons) annually on a global basis (References 5-71 through 5-73). Addition-
ally, lightning, the major nonbiological natural source of NO , has been estimated to produce about
10 Tg (11 x 106 tons) NO per year globally. By contrast, the estimated man-made oxides of nitrogen
were 48 Tg per year globally (Reference 5-73). Although man-made emissions are only about 10 percent
of total emissions, man-made sources are by far the most significant in air pollution due to their
concentration in population centers. This is illustrated by comparison of the ambient concentration
due to natural and man-made sources. The natural background ambient N0? concentration is estimated
at 0.0009 to 0.004 ppm (Reference 5-73). The NOp concentration in urban areas, however, is typically
between 0.01 to 0.5 ppm. In N02-critical areas where the ambient concentration approaches the ambient
air quality standard (0.05 ppm), the natural background level is less than 10 percent of the urban
ambient concentration.
Anthropogenic NOX Emissions
As shown in Table 5-25, U.S. man-made NO emissions for 1974 total about 21 million metric
X
tons (23 million short tons). The relative contributions of mobile and stationary sources are about
45 and 55 percent, respectively, as illustrated in Figure 5-1. These fractions are calculated using
controlled N0x emissions. If uncontrolled figures for N0x emissions are used, the respective por-
tions would be 48 percent for mobile and 52 percent for stationary NO emissions. Stationary emissions
include stationary fuel combustion, noncombustion processes, fugitive and incineration sources.
5-42
-------
TABLE 5-25. SUMMARY OF 1974 U.S. ANTHROPOGENIC NO EMISSIONS
y\
Fuel Combustion
(Section 5.4)
Incineration
Noncombustion
Nitric Acid
Explosives Mfr
Adi pic Acid
Fugitive Emissions
Controlled Burning
Forest Wildfires
Structural Fires
Other: Grain Silos,
Welding, etc.
Total Stationary
Highway Vehicles
Gasoline
Diesel
Nonhighway Vehicles
Ai rcraf t
Railroads
Vessels
Others: Dune Buggies
Trail Bikes, Con-
struction Equipment,
etc.
Total Mobile
Total NOX
1 ,000 Mg
10,954
40a
193ab
127
51
15
498C
273
90
90
45
11,685 (54%)
7,360C
6,310
1,050
2,270C
350
90
*
170
1,660
9,630
(46%)
21,315
1 ,000 Tons
12,070
44
212
138
56
17
548
300
99
99
50
12,874
8,100
6,940
1,160
2,500
380
100
190
1,830
10,600
23,474
Reference 5-74
'Reference 5-75
"Reference 5-76
5-43
-------
Noncombustion 0.9%
.Fugitive 2.3%
Incineration 0.2%
Stationary fuel combustion
51-4%
Mobile sources
45.2%
1974 Stationary Combustion Source NO Emissions
/\
Stationary Fuel Combustion
Fugitive Emissions
Noncombustion
Incineration
Mobile Sources
TOTAL
1,000 Mg
10,954
498
193
40
9,630
21,315
1,000 tons
12,070
548
212
44
10,600
23,474
Percent
Total
(51.4)
(2.3)
(0.9)
(0.2)
(45.2)
100
Figure 5-1. Distribution of anthropogenic NOX emissions for the year 1974
(stationary fuel combustion: controlled NO levels).
/\
5-44
-------
A detailed listing of stationary NOX sources Is given in Table 5-26 and shown graphically in
Figure 5-2. Table 5-26 also gives the contribution of each stationary sector. Note that combustion
in stationary sources, the primary emphasis of this program, accounts for about 94 percent of the
total emissions from stationary sources. Note also the relative contribution of each fuel. Natural
gas accounted for about one-third of the emissions in 1974, with coal accounting for about 40 percent.
Preliminary 1976 data show a strong trend away from natural gas fuel in the utility sector.
5.5.2 Summary of Air Pollutant Emissions
Table 5-27 gives emission totals for the criteria pollutants, sulfates, ROMs, and preliminary
solid and liquid ash stream production. Criteria pollutant data are taken from Section 5.4 and sul-
fate, POM,! and ash production data are from Appendix A. While totals for the criteria pollutants
are considered to be reliable, the totals for sulfate, POM, and ash are order-of-magnitude estimates
at best. Since the quality of available emission factor data for ROMs is poor, POM emissions are
given as a range. For the upper extreme of this range, POM emissions were derived from the largest
available emission factor, while at the lower extreme, the smallest emission factors were used. All
trace element emissions presented in Appendix A are also considered to be order-of-magnitude estimates.
Rankings of equipment type/fuel combinations on a mass emission basis for the criteria pol-
lutants and energy consumption are given in Tables 5-28 through 5-33. The rankings include only the
first 30 sources for each pollutant, which in each case includes the major portion of the emissions
for that pollutant. Finally, Table 5-33 ranks N0x emission control equipment, as well as the equipment
rank for S0x> HC, CO, particulates, and fuel consumption.
5.5.3 Comparison with Data
The comparison in Table 5-34 of uncontrolled NOX emissions developed in this study with es-
timates of NO emissions from other studies is generally favorable. Sector definition was compa-
rable In most cases, with the possible exception of packaged boilers and warm air furnaces. Previous
studies did not combine all packaged boilers but separated them by industrial, commercial, and res-
idential application. In addition, space heating was typically used as a sector title under which
were combined commercial and residential boilers and warm air furnaces. A further problem with the
package boiler sector is the difficulty in obtaining representative data from an essentially un-
monitored equipment sector. The lack of real sector data requires the use of broad estimates and
results in emission figures of similar quality when compared to the more recent inventories (NOX
Summary and GCA). The present estimates appear very good.
5-45
-------
TABLE 5-26. SUMMARY OF 1974 STATIONARY SOURCE NOX EMISSIONS
BY FUEL - 1,000 Mg (Percent of Total)
Sector
Utility Boilers
Packaged Boilers3
Warm Air Furnaces
Gas Turbines
Reciprocating 1C
Engines
Industrial Process
Heating
Noncombustion
Incineration
Fugitive
Total
Coal
3,564
(31.0)
679.7
(5.9)
—
—
—
—
—
4,243.7
(37.0)
Oil
848
(7.4)
886
(7.7)
129
(1.1)
309
(1.9)
456°
(3.9)
—
—
—
—
2,628
(22.1)
Gas
1156
(10.1)
779
(6.8)
190
(1.6)
133
(1.0)
1400
(12.2)
—
—
—
—
3,658
(31.7)
Total
5566
(47.6)
2344.7
(20.1)
320
(2.8)
442
(3.8)
1856
(16.2)
425.8
(3.64)
193
(1.7)
40
(0.34)
498
(4.3)
1 1 ,685
'includes steam and hot water commercial and residential heating units
'includes gasoline
5-46
-------
Industrial Process Combustion 3.652
Noncombustion 1.6X
Warm Air Furnaces 2.7%
Gas Turbines 3.76X
Fugitive 4.4%
Incineration 0.3X
Reciprocating
1C Engines
15.9%
1974 Stationary Combustion Source NOX Emissions
Utility Boilers
Packaged Boilers
Warm Air Furnaces
Gas Turbines
Reciprocating 1C Engines
Industrial Process Combustion
Noncombustion
Incineration
Fugitive
TOTAL
1 ,000 Mg
5,566
2,345
321
440
1,857
425.8
193
40
498
11,685
1,000 Tons
6.122
2,383
353
484
2,040
470
212
44
548
12,861
Percent
Total
47.6
20.1
2.7
3.76
15.9
3.65
1.6
0.3
4.4
100
Figure 5-2. Distribution of stationary anthropogenic NOX emissions for the year 1974
(stationary fuel combustion: controlled NOX levels).
5-47
-------
TABLE 5-27. 1974 SUMMARY OF AIR AND SOLID POLLUTANT EMISSION FROM STATIONARY FUEL
BURNING EQUIPMENT (1,000 Mg)
Utility Boilers
Packaged Boilers
Warm Air Furnaces
& Misc. Comb.
Gas Turbines
Reci p. 1C Engines
Process Heating
TOTAL
N0xb
5,566
2,345
321
440
1,857
425.8
10,954
SOX
16,768
6,405
232
10.5
19.6
1005
2^,440
HC
29.5
72.1
29.7
13.7
578
166
889
CO
270
175
132.6
73.4
1,824
10,039
12,511
Part Sul fates POM Dry .S1un1ced ,
cart 5ui rates KWI Ash Removai ASn Removal
5,965 231 0.01 - 1.2 6.18 24.78
4,930 146 0.2 - 67.8 4.41 1.07
39.3 6.4 0.06
17.3
21.5 a a
6,216.7 3
17,190 382 69
_a
o
i
a.
No emission factor available
Controlled NOV
X
°Based on 80 percent hopper and flyash removal by sluicing methods; 20 percent dry solid removal
-------
TABLE 5-28. FUEL CONSUMPTION RANKING OF STATIONARY COMBUSTION SOURCES
Source
Equipment Type
Fuel
Annual Fuel
Consumption
1 Utility Boilers
2 Warm A1r Furnaces
3 Utility Boilers
4 Package Boilers
5 Utility Boilers
6 Utility Boilers
7 Package Boilers
8 Utility Boilers
9 Warm Air Furnaces
10 Warm Air Furnaces
11 Package Boilers
12 Utility Boilers
13 Utility Boilers
14 Utility Boilers
15 Refinery Heaters
16 Package Boilers
17 Package Boilers
18 Warm Air Furnaces
19 Package Boilers
20 Package Boilers
21 Reciprocating 1C Engines
22 Package Boilers
23 utility Boilers
24 Package Boilers
25 Warm Air Furnaces
26 Package Boilers
27 Package Boilers
28 Package Boilers
29 Package Boilers
30 Gas Turbines
Tangential coal 5.130
Central gas 3.091
Wall-Firing coal 2.938
Watertube <29 MW gas 2.820
Wall-Firing gas 2.453
Cyclone Furnace coal 1.588
Watertube Stoker <29 MW coal 1.554
Wall-Firing oil 1.495
Space Heater gas 1.451
Central oil 1.405
Firetube Scotch oil 1.391
Tangential oil 1.360
Tangential gas 1.340
Horizontally Opposed gas 1.258
Natural and Forced Draft gas 1.247
Watertube >29 MW gas 1.058
Firetube Firebox oil 1.012
Misc Combustion gas 1.0
Firetube Scotch gas 0.991
Firetube Firebox gas 0.918
>75 kW/cyl gas 0.887
Res/Com Steam and Hot Water Units oil 0.880
Horizontally Opposed coal 0.839
Res/Com Steam and Hot Water Units gas 0.737
Space Heater oil 0.727
Watertube >29 MW oil 0.723
Watertube <29 MW oil 0.698
Firetube HRT oil 0.633
Firetube Stoker <29 MW coal 0.598
4.0 MW to 15 MW oil 0.579
5-49
-------
TABLE 5-29. SO MASS EMISSION RANKING OF STATIONARY COMBUSTION EQUIPMENT
Sector
Equipment Type
Fuel
Annual
SO Emissions
(Mg)
1 -Utility Boilers
2 Utility Boilers
3 Utility Boilers
4 Package Boilers
5 Utility Boilers
6 Package Boilers
7 Package Boilers
8 Package Boilers
9 Utility Boilers
10 Utility Boilers
11 Package Boilers
12 Utility Boilers
13 Industrial Process Combustion
14 Package Boilers
15 Industrial Process Combustion
16 Package Boilers
17 Package Boilers
18 Utility Boilers
19 Package Boilers
20 Industrial Process Combustion
21 Warm Air Furnaces
22 Package Boilers
23 Package Boilers
24 Warm Air Furnaces
25 Utility Boilers
26 Package Boilers
27 Industrial Process Combustion
28 Industrial Process Combustion
29 Industrial Process Combustion
30 Industrial Process Combustion
Tangential coal 7,000,000
Wall-Firing coal 4,031,000
Cyclone Furnace coal 2,740,000
Watertube Stoker <29 MW coal 2,293,410
Horizontally Opposed coal 1,130,000
Firetube Stoker <29 MW coal 876,000
Watertube Stoker >29 MW coal 775,700
Watertube Wall Firing >29 MW coal 627,200
Wall-Firing oil 600,000
Tangential oil 583,300
Firetube Scotch oil 504,000
Vertical and Stoker coal 415,000
Cement Kilns - 392,000
Firetube Firebox oil 337,300
Catalytic Cracking - 323,000
Watertube <29 MW oil 298,000
Watertube >29 MW oil 297,800
Horizontally Opposed oil 236,000
Firetube HRT oil 207,000
Coke Oven Underfire - 162,000
Central oil 152,000
Res/Com Steam and Hot Water Unit oil 128,700
Cast Iron oil 113,600
Space Heater oil 78,000
Cyclone Furnaces oil 35,000
Res/Com Steam and Hot Water Unit coal 34,450
Steel Sintering Machines - 34,000
Glass Melters - 32,000
Refinery Heaters oil 21,000
Brick Kilns - 16,500
5-50
-------
TABLE 5-30. CO MASS EMISSION RANKING OF STATIONARY COMBUSTION EQUIPMENT
Sector
Equipment Type
Fuel
Annual
CO Emissions
(Mg)
1 Industrial Process Combustion
2 Industrial Process Combustion
3 Reciprocating 1C Engines
4 Reciprocating 1C Engines
5 Reciprocating 1C Engines
6 Utility Boilers
7 Utility Boilers ?
8 Warm Air Furnaces
9 Reciprocating 1C Engines
10 Warm Air Furnaces
11 Package Boilers
12 Utility Boilers
13 Utility Boilers
14 Package Boilers
15 Gas Turbines
16 Gas Turbines
17 Warm Air Furnaces
18 Utility Boilers
19 Package Boilers
20 Utility Boilers
21 Warm Air Furnaces
22 Reciprocating 1C Engines
23 Package Boilers
24 Utility Boilers
25 Gas Turbine
26 Warm Air Furnaces
27 Utility Boilers
28 Package Boilers
29 Gas Turbine
30 Package Boilers
Catalytic Cracking - 8,969,000
Steel Sintering Machines - 1,067,000
75 kW to 75 kW/cyl gasoline 1,054,800
<75 kW gasoline 592,000
>75 kW/cyl gas 142,850
Wall-Firing coal 64,400
Tangential coal 58,300
Central oil 43,600
75 kW to 75 kW/cyl oil 40,000
Central gas 36,918
Watertube Stoker 29 MW coal 34,130
Cyclone Furnace coal 29,673
Wall-Firing gas 28,249
Res/Com Steam and Hot Water Unit oil 27,910
4 MW to 15 MW oil 27,156
4 MW to 15 MW gas 23,100
•«
Space Heater oil 22,000
Wall-Firing oil 20,300
Res/Com Steam and Hot Water Unit coal 19,670
Vertical and Stoker coal 18,400
Space Heater gas 17,325
>75 kW/cyl oil 16,642
Watertube <105 GJ/hr gas 14,530
Horizontally Opposed gas 13,461
>15 MW oil 12,400
Misc. Comb. & Resid. gas 12,000
Tangential oil 11,900
Watertube Stoker >29 MW coal 11,650
>15 MW gas 10,340
Watertube >29 MW gas 9,478
5-51
-------
TABLE 5-31. HC MASS EMISSION RANKING OF STATIONARY COMBUSTION EQUIPMENT
Sector
Equipment Type
Fuel
Annual
HC Emissions
(Mg)
1 Reciprocating 1C Engines
2 Industrial Process Combustion
3 Reciprocating 1C Engines
4 Package Boilers
5 Reciprocating 1C Engines
6 Reciprocating 1C Engines
7 Industrial Process Combustion
8 Warm Air Furnaces
9 Utility Boilers
10 Package Boilers
11 Package Boilers
12 Warm Air Furnaces
13 Reciprocating 1C Engines
14 Gas Turbines
15 Warm Air Furnaces
16 Utility Boilers
17 Package Boilers
18 Industrial Process Combustion
19 Package Boilers
20 Gas Turbines
21 Warm Air Furnaces
22 Package Boilers
23 Utility Boilers
24 Package Boilers
25 Gas Turbines
26 Package Boilers
27 Utility Boilers
28 Utility Boilers
29 Package Boilers
30 Gas Turbines
>75 kW/cyl gas. 483,000
Catalytic Cracking - 144,500
75 kW to 75 kW/cyl oil 48,461
Watertube Stoker <29 MW coal 27,660
75 kW to 75 kW/cyl gas 23,900
<75 kW gas 19,647
Refinery Heaters Forced gas 16,089
& Natural Draft
Central gas 10,548
Cyclone Furnace coal 10,393
Firetube Stoker coal 10,130
Res/Com Steam and Hot Water Unit coal 8,238
Central oil 6,593
>75 kW/cyl oil 6,127
4 MW to 15 MW oil 5,730
Space Heater gas 4,950
Tangential coal 4,800
Res/Com Steam and Hot Water Unit oil 4,542
Refinery Heaters Natural oil 4,426
& Forced Draft
Watertube >29 MW gas 4,126
4 MW to 15 MW gas 3,840
Space Heater oil 3,411
Watertube <29 MW gas 2,870
Wall-Firing coal 2,610
Res/Com Steam and Hot Water Unit gas 2,506
>15 MW oil 2,251
Watertube >29 MW oil 2,157
Wall-Firing oil 2,150
Wall-Firing gas 2,110
Watertube Stoker >29 MW coal 2,004
>15 MW gas 1,810
5-52
-------
TABLE 5-32. PARTICULATE MASS EMISSION RANKING OF STATIONARY COMBUSTION EQUIPMENT
Sector
Equipment Type
Fuel
Annual
Partlculate
Emissions (Mg)
1 Package Boilers
2 Utility Boilers
3 Industrial Process
4 Industrial Process
5 Utility Boilers
6 Package Boilers
7 Industrial Process
8 Utility Boilers
9 Package Boilers
10 Industrial Process
11 Package Boilers
12 Utility Boilers
13 Industrial Process
14 Utility Boilers
15 Industrial Process
16 Industrial Process
17 Package Boilers
18 Package Boilers
19 Utility Boilers
20 Utility Boilers
21 Package Boilers
22 Industrial Process
Combustion
Combustion
Combustion
Combustion
Combustion
Combustion
Combustion
Combustion
23 Package Boilers
24 Package Boilers
25 Industrial Process Combustion
26 Warm A1r Furnaces
27 Reciprocating 1C Engines
28 Utility Boilers
29 Package Boilers
30 Warm Air Furnaces
31 Industrial Process Combustion
Watertube Stoker <29 MW coal 3,252,000
Tangential C0al 3,178,000
Coke Cften Underflre - 2,149,000
Brick Kilns - 2,052,700
Wall-Fired coal 1,734,000
Flretube Stoker coal 1,202,000
Cement Kilns - 1,126,000
Horizontal Opposed Wall coal 499,000
Watertube Stoker >29 MW coal 488,600
Steel Sintering Machines - 485,000
Watertube, Wall Fired >29 MW coal 436,400
Vertical and Stoker coal 263,800
Open Hearth Furnace - 193,600
Cyclone Furnace coal 193,000
Catalytic Cracking - 158,000
Steel Sintering Machines - 48,500
Firetube Scotch oil 40,210
Firetube HRT oil 31,740
Wall-Firing oil 31,100
Tangential oil 31,100
Firetube Firebox oil 26,750
Forced & Natural Draft Refinery oil 26,429
Heaters
Watertube, Wall-Fired >29 MW oil 24,320
Watertube <29 MW oil 22,950
Glass Melters - 15,210
Central gas 13,185
75 kW to 75 kW/cyl oil 13,132
Horizontally Opposed oil 12,852
Res/Com Steam and Hot Water Unit oil 12,500
Central oil 10,789
Forced & Natural Draft Refinery gas 10,726
Heaters
5-53
-------
TABLE 5-33. NOX MASS EMISSION RANKING OF
STATIONARY COMBUSTION EQUIPMENT AND CRITERIA POLLUTANT AND FUEL USE CROSS RANKING
Sector
1 Utility Boilers
2 Reciprocating 1C
Engines
3 Utility Boilers
4 Utility Boilers
5 Utility Boilers
6 Utility Boilers
7 Utility Boilers
8 Reciprocating 1C
Engines
9 Packaged Boilers
10 Packaged Boilers
11 Utility Boilers
12 Packaged Boilers
13 Utility Boilers
14 Packaged Boilers
15 Packaged Boilers
16 Utility Boilers
17 Packaged Boilers
18 Industrial
Process Comb.
19 Utility Boilers
20 Packaged Boilers
Equipment Type
Tangential
>75 kW/cyl
Wall Firing
Cyclone Furnace
Wall Firing
Wall Firing
Horizontally Opposed
75 kW to 75 kW/cyl
Watertube >29 MW
Watertube Stoker <29 MW
Horizontally Opposed
Watertube >29 MW
Tangential
Firetube Scotch
Watertube <29 MW
Horizontally Opposed
Watertube <29 MW
Forced & Natural Draft
Refinery Heaters
Tangential
Firetube Firebox
Fuel
Coal
Gas
Coal
Coal
Gas
Oil
Gas
Oil
Gas
Coal
Coal
Oil
Oil
Oil
Gas
Oil
Coal
Oil
Gas
Oil
Annual NOX
Emissions
(Mg)
1,410,000
1,262,000
946,000
863,500
738,300
481 ,000
378,700
325,000
318,500
278,170
270,800
232,480
208,000
203,990
180,000
177,900
164,220
147,350
146,000
139,260
Cumulative
(Mg)
1,410,000
2,672,000
3,618,000
4,481,500
5,219,800
5,700,800
6,079,500
6,404,500
6,723,000
7,001,170
7,271,970
7,504,450
7,712,450
7,916,440
8,096,440
8,274,340
8,438,560
8,585,910
8,731,910
8.871,170
Cumulative
(Percent)
13.1
24.8
33.5
41.5
48.4
52.8
56.3
59.4
62.3
64.9
67.4
69.5
71.5
73.4
75.0
76.7
78.2
79.6
80.9
82.2
Fuel
Rank
1
21
3
6
4
8
14
>30
16
7
23
26
12
11
5
>30
>30
>30
13
17
SOX
Rank
1
>30
2
3
>30
9
>30
>30
>30
4
5
16
10
11
>30
17
8
29
>30
13
CO
Rank
7
4
6
12
13
17
24
3
29
11
>30
>30
27
>30
>30
>30
>30
>30
>30
>30
HC
Rank
16
1
23
9
28
27
>30
3
19
4
>30
26
>30
>30
22
>30
>30
18
>30
>30
Part
Rank
2
>30
5
13
>30
18
>30
26
>30
1
7
22
19
16
>30
27
9
21
>30
20
-------
TABLE 5-33. Concluded
Sector
21 Packaged Boilers
22 Gas Turbines
23 Packaged Boilers
24 Warm Air Furnaces
25 Packaged Boilers
26 Packaged Boilers
27 Gas Turbines
28 Reciprocating 1C
Engines
29 Industrial
Process Comb.
30 Utility Boilers
Equipment Type
Watertube Stoker
4 to 15 MW
Watertube <29 MW
Central
Firetube Stoker <29 MW
Firetube Scotch
>15 MW
>75 kW/cyl
Forced & Natural Draft
Refinery Heaters
Vertical and Stoker
Fuel
Coal
Oil
Oil
Gas
Coal
Gas
Oil
Oil
Gas
Coal
Annual NOX
Emissions
(Mg)
125,350
118,500
116,430
106,300
102,040
98,010
97,400
94,000
92,608
90,900
Cumulative
(Mg)
8,996,520
9,115,020
9,231,450
9,337,750
9,439,790
9,537,800
9,635,200
9,729,200
9,821,808
9,912,708
Cumulative
(Percent)
83.4
84.5
85.6
86.5
87.5
88.4
89.3
90.2
91.0
91.9
Fuel
Rank
>30
30
27
2
29
19
>30
>30
15
>30
SOX
Rank
7
>30
15
>30
6
>30
>30
>30
>30
12
CO
Rank
28
15
>30
10
>30
>30
>30
22
>30
>20
HC
Rank
29
14
>30
8
10
>30
30
13
7
>30
Part
Rank
8
>30
23
25
6
>30
>30
>30
30
>10
CM
CO
-------
TABLE 5-34. COMPARISON OF STATIONARY UNCONTROLLED NOV EMISSIONS (1,000 Mg)
A
Sector
Utility Boilers
Packaged Boilers
Warm Air Furnaces
Gas Turbines
Reciprocating 1C Engines
Process Heating
Noncombustion
Incineration
Other
Total
ESSOa
(1968)
3,490
3,463
909A
B
1,909C
B
218
B
D
9,989
AP-115b
(1970)
4,282
4,327
51 8A
E
E
182
—
73
D
9,382
OAQPSC
(1971)
4,891
4,078
533A
E
E
B
182
36
9,720
N0xd
Summary
(1972)
5,155
2,245
427A
264
1,990
355
135
36
D
10,607
GCAe OAQPSf
(1973) (1974)
5,909
2,009
291A
446
1,491
10,000
550F
15 91G
91
10,161 10,732
Current
(1974)
5,741
2,345
320.6
440
1,857.2
425.8
193
40
—
11,363
I
Ul
A —Also includes steam and hot water units
B — Included in packaged boilers
C - Pipeline and gas plants only
D — Not included in data
E — Included in utility and packaged boilers
depending on use
F - Includes all petroleum industry emissions
G — Includes all solid waste disposal
Reference 5-76
Reference 5-77
"Reference 5-74
Reference 5-78
"Reference 5-6
Reference 5-79
-------
Table 5-35 compares the energy consumption figures developed in this study to those of other
studies. Again the overall comparison is favorable, although direct comparisons cannot be made in
some cases because of differences in sector definition.
Table 5-36 compares criteria pollutant emissions developed in this study to those of OAQPS and
NEDS. In general, comparisons are favorable. The only significant difference is in the CO estimate.
Examination of the CO estimates in this report indicates that nearly 24 percent of these emissions
result from gasoline-fueled reciprocating 1C engines of less than <75 kW (15 hp), and about 41 per-
cent of the total are from medium capacity gasoline engines. Because of the nature of the 1C engine
population - especially units of this capacity range - comprehensive reporting of real data is diffi-
cult to achieve. This may explain the discrepancy between an inventory compiled partially through
estimates of fuel consumption and generation and an inventory relying essentially on reported data.
5.5.4 Conclusion
The current inventory of stationary combustion-related pollutants concentrated primarily on
the criteria air pollutants. Estimates of nationwide SO and particulate emissions reflected present
control implementation and regulations; NO emission estimates were given in both the uncontrolled
and controlled states. Mass emission rankings of stationary combustion equipment for the criteria
pollutants indicate the relative importance of NOV sources with respect to SO , CO, HC, and partic-
X A
ulate emissions. In general, the criteria pollutant inventory is considered to be of relatively high
quality in terms of emission totals. In terms of sector emissions, however, the quality ranges from
good for utility boilers; fair to good for the warm air furnace, gas turbine, and reciprocating 1C
engine sectors, to poor for the package boiler and industrial process heating sectors. Secondary
emphasis was placed on all other multimedia pollutants. The preliminary estimates of sulfates,
ROMs, and trace element emissions are poor in quality as a result of very sparse and inconsistent
data. Liquid and solid stream combustion-related pollutant (trace elements) emissions are also of
very poor quality, partly due to the unavailability of exact fuel composition monitoring. Several
comnents can be made about the quality of the inventory or pollutant data:
• The packaged boiler sector is the most difficult to quantify in terms of fuel consumption,
equipment emission factors and emissions. This is due to the large capacity range of the
equipment sector, the diversity of equipment design, and the extremely large population
of this sector.
t The industrial process combustion sector is also extremely difficult to quantify. The
difficulty arises from the lack of specific fuel and fuel consumption data combined with
5-57
-------
TABLE 5-35. COMPARISON OF STATIONARY SOURCE ANNUAL FUEL
CONSUMPTION ESTIMATES (1015kJ)
in
S
Sector
Utility Boilers
Packaged Boilers
Warm Air Furnaces
Gas Turbines
Reciprocating 1C Engines
Total
OAQPSa
(1971)
14.81
30.66A
—
, —
—
45.47
AP-115b
(1969)
12.81
29.20A
—
—
—
42.01
NOXC
Summary
(1972)
15.59
16.81
10.438
0.939
1.33
45.1
6CAd
(1973)
15.61
13.42
8.36B
1.42
2.12
40.93
Current
(1974)
19.22
15.573B
6.674
1.525
1.240
44.234
A - Includes 1C engines and warm air furnaces
B — Includes steam and hot water units
Reference 5-74
Reference 5-77
Reference 5-78
Reference 5-6
-------
TABLE 5-36. COMPARISON OF CURRENT STATIONARY EMISSION ESTIMATES
DATA WITH PREVIOUS STUDIES (1,000 Mg)
Pollutant
NOX
S0x
HC
CO
Parti culates
OAQPSa
(1974)
12.36A
22.918
1.55B
1.27B
8.00B
NEDSb
(1976)
11.79A
24.35B
0.46B
1.29B
6.47B
OAQPSC
(1974)
10.45A
21 . 36A
1.7B
0.9B
5.9
Current
(1974)
11.36AD
23.44C
0.72C
2.48C
10.97C
A - Total minus transportation
B — Stationary fuel combustion only
C — Fuel combustion minus process heating
D - Controlled NOX estimates
Reference 5-80
Reference 5-81
Reference 5-79
5-59
-------
the large number of process heating applications, the variation of equipment design and
the variation in combustion practices from industry to industry.
• POM emissions were treated as a single pollutant because few data were available for
specific POM compounds. Even the available POM data exhibited large scatter which
warranted reporting ranges of emission factors and emission rates. Extensive testing
is needed in all sectors.
• Transient or nonconventional operations and their effect on multimedia emission rate were
treated only superficially. Test data were essentially unavailable except in the space
heating applications where some testing has occurred. Test data are needed before further
quantification can proceed.
The compilation of this inventory indicated many areas where further data are necessary to improve
the quality of this and the subsequent projections which will result from this inventory:
• Utility Boilers
- An extensive geographic population distribution by equipment design and fuel
- Further data on noncriteria pollutant emission factors (sulfate, POM and POM sub-
categories, and trace elements)
- Comprehensive monitoring of the trace metal content of fuels
— More conclusive data on the speciation of trace element emissions
- Comprehensive testing of liquid and solid effluent streams to identify and quantify
combustion-related pollutants
- Test data on the effect of nonstandard operation on the composition of multimedia
effluent streams
• Package Boilers
- Extensive inventories of population by equipment design, fuel capabilities and con-
sumption, capacity, location, and application
- Extensive emission characteristics of the majority of equipment design presently
available
- Test data on the effect of nonstandard operation on multimedia effluent stream
composition
5-60
-------
• Warm Air Furnaces
- Data on noncrlterla pollutant formation characteristics
- More comprehensive emission factor data for the range of available designs
- Extensive data on the effect of cyclic operation on effluent stream composition
• Gas Turbines
- Extensive data on simple, regenerative, and combined cycle population as a function
of capacity, fuel, application, and location
- Test data on noncriteria pollutant formation characteristics
i Reciprocating 1C Engines
- Extensive data on equipment distribution by design, fuel, application, and location
- Data on noncriteria pollutant formation characteristics
• Industrial Process Combustion
- Comprehensive inventorying of process combustion sources in terms of function, capacity,
fuel, and equipment design
- Data on process fuel consumption for use with emission factors
- Data on emission characteristics with process gas fuels
- Data on noncriteria pollutant formation characteristics
Subsequent updates to the inventory will improve the estimates of noncriteria pollutants and
liquid and solid effluents pending new test results. This inventory will then act as a basis for a
comprehensive assessment of the pollution potential of stationary sources of N0x< This will be
accomplished by integrating two-intermediate tasks: (1) a fuel use and emission projection to the
year 2000 and (2) the development of regional and AQCR emission inventories. The assessment of pol-
lution potential will be used in assessing baseline and controlled environmental impacts of N0x con-
trols in Task B5.
5-61
-------
REFERENCES FOR SECTION 5
5-1. Dupree, W. G., and J. S. Corsentino, "Energy Through the Year 2000 (Revised)," U.S. Bureau
of Mines, December 1975.
5-2. Mezey, E. J., et al., "Fuel Contaminants, Volume I, Chemistry," EPA 600/2-76-177a,
NTIS-PB 256 020/AS, Battelle-Columbus Laboratories, July 1976.
5-3. FPC News, Vol. 8, No. 13, March 28, 1975.
5-4. Ctvrtnicek, T., "Evaluation of Low Sulfur Western Coal Characteristics, Utilization, and
Combustion Experience," EPA 650/2-75-046, NTIS-PB 243 911/AS, May 1975.
5-5. "Coal-Fired Power Plant Trace Element Study -A Three-Station Comparison," Radian Corpora-
tion, EPA Region VIII, September 1975.
5-6. Surprenant, Norman, et al., "Preliminary Emissions Assessment of Conventional Stationary
Combustion Systems, Volume II," EPA 600/2-76-046b, NTIS-PB 252 175/AS, March 1976.
5-7. Ruch, R. R., et al., "Occurrence and Distribution of Potentially Volatile Trace Elements in
Coal," EPA 650/2-74-054, NTIS-PB 238 091/AS.
5-8. Magee, E. M., et al., "Potential Pollutants in Fossil Fuels," EPA-R2-73-249, NTIS-PB 225 039/
7AS, June 1973.
5-9. Vitez, B., "Trace Elements in Flue Gases and Air Quality Criteria," Vol. 80, No. 1,
Power Engineering. January 1976.
5-10. FPC News, Vol. 8, No. 23, June 6, 1975.
5-11. "Applicability of NOX Combustion Modifications to Cyclone Boilers (Furnaces)," Monsanto
Research Corporation, (Draft) 1976.
5-12. "Standard Support and Environmental Impact Statement for Standards of Performance:
Lignite-Fired Steam Generators," (Draft), A. D. Little, Inc., Office of Air Quality Planning
and Standards, March 1975.
5-13. Smith, D. W., et al., "Electric Utilities and Equipment Manufacturers' Factors in Acceptance
of Advanced Energy," A.D. Little, Inc., ADL-77771, September 1975.
5-14. Putnam, A. A., et al., "Evaluation of National Boiler Inventory," Battelle-Columbus
Laboratories, EPA 600/2-75-067, NTIS-PB 248 100/AS, October 1975.
5-15. "Minerals Yearbook 1973-Metals, Minerals, and Fuels, Volume I," U.S. Bureau of Mines.
5-16. Power Magazine, Plant Design Issues, 1971 through 1976.
5-17. FPC News, Vol. 9, No. 3, January 16, 1976.
5-18. Locklin, D. W., et al., "Design Trends and Operating Problems in Combustion Modification of
Industrial Boilers," EPA 650/2-74-032, NTIS-PB 235 712/AS, Battelle-Columbus Laboratories,
April 1974.
5-19. "Current Industrial Reports, Steel Power Boilers," 1968 through 1975, U.S. Department of
Commerce, Bureau of the Census.
5-20. Hopper, T. G., et al., "Impact of New Source Performance Standards of 1985 National
Emissions from Stationary Sources," Volume I, Final Report, The Research Corporation of
New England, October 1975.
5-21. "Statistical Abstract of the United States 1975," (86th Annual Edition), U.S. Department
of Commerce, Bureau of the Census, 1975.
5-22. Durkee, K. R., et al., "Standards Support and Environmental Impact Statement -An Investiga-
tion of the Best Systems of Emission Reduction for Stationary Gas Turbines," EPA, July 1976.
5-62
-------
5-23. "Gas Turbine Electric Plant Construction Cost and Annual Production Expenses, First Annual
Publication - 1972," FPC S-240, Federal Power Commission, 1972.
5-24. "1975 Sawyer's Gas Turbine Catalog," Gas Turbine Publications, Incorporated, Stamford,
Connecticut, 1975.
5-25. "Gas Turbines in U.S. Electrical Utilities," Gas Turbine International. March through
June 1976.
5-26. Offen, G. R., et al., "Standard Support Document and Environmental Impact Statement -
Reciprocating Internal Combustion Engines," Aerotherm Project 7152, Acurex Corporation,
November 1975.
5-27. Goldish, J., et al., "Systems Study of Conventional Combustion Sources in the Iron and Steel
Industry," EPA-R2-73-192, NTIS-PB 226 294/AS, April 1973.
5-28. Ketels, P. A., et al., "A Survey of Emissions Control and Combustion Equipment Data in
Industrial Process Heating," Institute of Gas Technology, June 1976.
5-29. Klett, M. G., and J. B. Galeski, "Flare Systems Study," Lockheed Missiles and Space Co.,
Inc., EPA 600/2-76-079, NTIS-PB 251 664/AS, March 1976.
5-30. Personal communication with K. Hunter of KVB, Inc., principal contributor to American
Petroleum Institute Study scheduled for release in September 1977.
5-31. "Compilation of Air Pollutant Emission Factors (Second Edition)," U.S. Environmental Pro-
tection Agency, AP-42, April 1973.
5-32. "Supplement No. 6 for Compilation of Air Pollutant Emission Factors (Second Edition),"
U.S. Environmental Protection Agency, Office of Air and Waste Management, Office of Air
Quality Planning and Standards, April 1976.
5-33. "Supplement No. 3 for Compilation of Air Pollutant Emission Factors (Second Edition),"
U.S. Environmental Protection Agency, Office of Air and Waste Management, Office of Air
Quality Planning and Standards, July 1974.
5-34. "Proceedings of the Stationary Source Combustion Symposium, Volume III - Field Testing and
Surveys," EPA 600/2-76-152c, NTIS-PB 257 146/AS, June 1976.
5-35. "Proceedings of the Stationary Source Combustion Symposium, Volume II - Fuels and Process
Research and Development," EPA 600/2-76-152b, NTIS-PB 256 321/AS, June 1976.
5-36. Bartok, W., et al.,""Field Testing: Application of Combustion Modifications to Control NOX
Emissions for Utility Boilers," Exxon Research and Engineering Company, EPA 650/2-74-066,
NTIS-PB 237 344/AS, June 1974.
5-37. Bartok, W., et al., "Systematic Field Study of NOX Emission Control Methods for Utility
Boilers," 6RU.4GNOS.71, Esso Research and Engineering, Office of Air Programs, Environmental
Protection Agency, December 1971.
5-38. Selker, Ambrose P., "Program for Reduction of NOX from Tangential Coal-Fired Boilers,
Phase II," Combustion Engineering, Inc., EPA 650/2-73-005a, NTIS-PB 245 162/AS, June 1975.
5-39. Selker, Ambrose P., "Program for Reduction of NOX from Tangential Coal-Fired Boilers,
Phase Ha," Combustion Engineering, Inc., EPA 650/2-73-005b, NTIS-PB 246 889/AS, August 1975.
5-40. McCann, C., et al., "Combustion Control of Pollutants from Multiburner Coal-Fired Systems,"
U.S. Bureau of Mines, EPA 650/2-74-038, NTIS-PB 233 037/AS, May 1974.
5-41. "The Proceedings of the NOX Control Technology Seminar," San Francisco, California,
February 1976, Electric Power Research Institute, SR-39.
5-42. "Sources of Polynuclear Hydrocarbons in the Atmosphere," U.S. Department of Health,
Education and Welfare, AP-33.
5-63"
-------
5-43. Homolya, J. B., et al., "A Characterization of the Gaseous Sulfur Emissions from Coal and
Coal-Fired Boilers," presented at the Fourth National Conference on Energy and the Environ-
ment, October 1976, Cincinnati, Ohio.
5-44. Klein, David H. , et al., "Pathways of Thirty-Seven Trace Elements Through Coal-Fired Power
Plant," Environmental Science and Technology. Vol. 9, No. 10, pp. 973-979, October 1975.
5-45. "Trace Elements in a Combustion System," Battelle-Columbus Laboratories, EPRI Final Report
122-1, January 1975.
5-46. Lee, R. E., Jr.; "Concentration and Size of Trace Metal Emissions from a Power Plant, a
Steel Plant, and a Cotton Gin," Environmental Science and Technology, Vol. 9, No. 7,
pp. 643-647.
5-47. Davison, Richard L., et al., "Trace Elements in Fly Ash -Dependence of Concentration on
Particle Size," Environmental Science and Technology, Vol. 9, No. 13, pp. 1107-1113,
December 1974.
5-48. Kaakinen, J. W., et al., "Trace Element Behavior in Coal-Fired Power Plant," Environmental
Science and Technology, Vol. 9, No. 9, pp. 862-869, September 1975. :
5-49. Cato, G. A., et al . , "Field Testing: Application of Combustion Modifications to Control
Pollutant Emissions from Industrial Boilers -Phase I," KVB Engineering, Inc.,
EPA-650/2-74-078a, NTIS-PB 238 920/AS, October 1974.
5-50. Cato, G. A., et al., "Field Testing: Application of Combustion Modifications Control to
Pollutant Emissions from Industrial Boilers -Phase II," KVB Engineering, Inc.,
EPA-600/2-76-086a, NTIS-PB 253 500/AS, April 1976.
5-51. Cato, G. A., "Field Testing: Trace Element and Organic Emissions from Industrial Boilers,"
KVB Engineering, Inc., EPA-600/2-76-086b, NTIS-PB 261 263/AS, October 1976.
5-52. Barrett, R. E., et al., "Field Investigation of Emissions from Combustion Equipment for
Space Heating," Battelle-Columbus Laboratories, EPA-R2-73-084a, NTIS-PB 223 148, June 1973.
5-53. Levy, A., et al., "Research Report on a Field Investigation of Emissions from Fuel Oil
Combustion for Space Heating," Battelle-Columbus Laboratories, American Petroleum Institute,
November 1971.
5-54. Hall, Robert E. , "The Effect of Water/Distillate Oil Emulsions on Pollutants and Efficiency
of Residential and Commercial Heating Systems," APCA Paper No. 75-09.4, 68th Annual Meeting
of the Air Pollution Control Association, Boston, Massachusetts, June 1975.
5-55. Giammar, R. D. , et al., "The Effect of Additives in Reducing Particulate Emissions from
Residual Oil Combustion," ASME 75-wa/CD-7.
5-56. Giammar, R. D. , et al., "Particulate and POM Emissions from a Small Commercial Stoker-Fired
Boiler Firing Several Coals," Paper No. 76-4.2, 69th Annual Meeting of the Air Pollution
Control Association, Portland, Oregon, June 1976.
5"57' FD^ccn'/^;;; ™,a1;,4TrS£ud£ of Mr Pollutant Emissions from Residential Heating Systems,"
EPA-650/2-74-003, NTIS-PB 229 697/AS, January 1974.
5-58. Brown, R. A., et al . , "Feasibility of a Heat and Emission Loss Prevention System for Area
Source Furnaces," Acurex Corporation, EPA-600/2-76-097, NTIS-PB 253 945/AS, April 1976.
5-59. Of fen, G. R. , et al . , "Control of Particulate Matter from Oil Burners and Boilers,"
Acurex Corporation, EPA -450/3-76-005, April 1976.
5-60. Hare, Charles T. , et al., "Exhaust Emissions from Uncontrolled Vehicles and Related Equip-
ment Using Internal Combustion Engines, Part 6: Gas Turbine Electric Utility Power Plants,"
Southwest Research Institute, Environmental Protection Agency, February 1974.
5-61. "Supplement No. 4 for Compilation of Air Pollutant Emission Factors (Second Edition),"
u.b Environmental Protection Agency, Office of Air and Waste Management, Office of Air
Quality Planning and Standards, January 1975.
5-64
-------
5-62. Dietzmann, H. E., and K. J. Springer, "Exhaust Emissions from Piston and Gas Turbine
Engines Used 1n Natural Gas Transmission," Southwest Research Institute, AR-923, January
5-63. Hare, C. T., and K. J. Springer, "Exhaust Emissions from Uncontrolled Vehicles and Related
Equipment Using Internal Combustion Engines. Final Report, Part 5: Heavy-Duty Farm,
Construction, and Industrial Engines," Southwest Research Institute, October 1973.
5-64. Richards, J., and R. Gerstle, "Stationary Source Control Aspects of Ambient Sulfates:
A Data-Based Assessment," (unpublished draft report) EPA Contract No. 68-02-1321, PedCo
Environmental Specialists, Inc., February 1976.
5-65. "Hydrocarbon Pollutant Systems Study, Volume 1 -Stationary Sources, Effects, and Control,"
MSA Research Corporation, NTIS-PB 219 073, October 1972.
5-66. Information from National Emissions Data System (NEDS), August 28, 1973.
5-67. Information from National Emissions Data System (NEDS), May 15, 1974.
5-68. Personal communication with Robert D. Maclean, Portland Cement Manufacturer's Association,
January 1977.
5-69. "Flue Gas Desulfurization Survey July-August 1976," PedCo Environmental, Cincinnati, Ohio.
5-70. "The West Scrubber Newsletter," No. 2-28, The Mcllvaine Company, Northbrook, Illinois,
October 31, 1976.
5-71. Robinson, E., and R. C. Robbins, Journal of the Air Pollution Control Association, pp. 20
and 303, 1970.
5-72. Skinner, K. J., "Nitrogen Fixation," Chemical and Engineering News, October 1976.
5-73. "Air Quality and Stationary Source Emissions Control," A Report by the Commission on Natural
Resources, National Academy of Sciences, National Academy of Engineering, and National
Research Council, Serial 94-4, March 1975.
5-74. "OAQPS Data File of Nationwide Emissions, 1971," Office of Air Quality Planning and Standards,
EPA, May 1973.
5-75. "Annual Survey of Manufacturers 1974 - Fuels and Electric Energy Consumed," U.S. Department
of Commerce, Bureau of the Census.
5-76. Bartok, W., et al., "Systems Study of Nitrogen Oxide Control Methods for Stationary Sources,
Volume II," prepared for National Air Pollution Control Administration, NTIS-PB 192 789,
Esso Research and Engineering, 1969.
5-77. Cavender, J. H., et al., "Nationwide Air Pollutant Emission Trends 1940-1970," Publication
No. AP-115, EPA, January 1973.
5-78. Shimizu, A. B., et al., "NOX Combustion Control Methods and Costs for Stationary Sources;
Summary Study," EPA-600/2-75-046, NTIS-PB 246 750/AS, September 1975.
5-79. "Monitoring and Air Quality Trends Report, 1974," EPA-450/10-76-001 EPA Office of Air Quality
Planning and Standards, February 1976.
5-80. Personal communication with C. Masser, National Emissions Data System (NEDS), October 1976.
5-81. Information from National Emissions Data System (NEDS), October 26, 1976.
5-65
-------
SECTION 6
EVALUATION OF INCREMENTAL EMISSIONS DUE TO NOY CONTROLS
A
Modification of the combustion process for N0x control can also potentially change emissions
of other combustion-generated pollutants. If unchecked, these potential changes, referred to as in-
cremental emissions, may have an adverse effect on the environment, the unit thermal efficiency, or
the overall system performance. Since the incremental emissions are sensitive to the same combustion
conditions as NOX, they may, with proper engineering, be held to acceptable levels, or even reduced,
during control development so that the net environmental benefit is maximized. In fact, control of
incremental emissions of carbon monoxide, hydrocarbons and smoke has been a key part of all past NO
control development programs. Recent control development gives increased attention to other poten-
tial pollutants such as sulfates, organics, and trace metals. The NO E/A is quantifying incremental
emission rates and impacts to enable subsequent control development to constrain any adverse impacts
of NO controls to acceptable levels.
This section gives a preliminary evaluation of the demonstrated and potential effects of
combustion modification NO controls on incremental emissions. The results will serve to scope and
guide priorities for subsequent NO E/A efforts in incremental emission data compilation, impact
characterization, and control process studies. Attention is focused on flue gas emissions from the
major sources using near-term NO controls, since these situations are the most important in the
program and are the only ones for which any significant data exist. Subsequent effort will consider
liquid and solid effluents, minor sources and alternate or advanced N0x controls. Also, the dis-
cussion here is concerned only with estimating incremental emission rates without regard to poten-
tial impact. Ultimately, the significance of the incremental emission depends on the baseline un-
controlled pollutant emission rates (discussed in Section 5) and the maximum acceptable ambient pol-
lutant concentration (discussed in Section 3) as well as other factors such as pollutant transport
and transformation. Preliminary screening of potential incremental impacts due to N0x controls,
considering these factors, is addressed in Section 7.3.
The preliminary evaluation in this section first screens the.matrix of control techniques/
Pollutant pairs to identify potential incremental emission problems. The currently available data
6-1
-------
on the effects of NO controls on residual emissions are then summarized and discussed in terms of
X
verifying preliminary expectations. Areas of insufficient data are identified and the relative im-
portance of obtaining requisite data is assessed. Finally, the areas where future N0x E/A efforts
should be concentrated are identified and ranked in order of importance.
In the discussion that follows, Section 6.1 describes the preliminary control technique/
pollutant screening task. Here changes in the levels of incremental emissions are qualitatively
linked to the combustion conditions resulting from the use of specific N0x controls. Areas of poten-
tial concern, in which an emission increase can be expected, are also noted. Section 6.2 presents
and evaluates the available data documenting emission changes on a pollutant-by-pollutant basis.
Postulated areas of concern are substantiated, where possible, and areas of insufficient data are
noted. Where insufficient data exist, further discussions of appropriate pollutant formation mech-
anisms and their implications are presented.
Based on Sections 6.1 and 6.2, Section 6.3 groups control technique/pollutant pairs into
areas of:
• High potential emissions impact, where well-documented data indicate that a particular
control causes significant increases in emissions of a certain pollutant
• Intermediate potential emissions impact, where basic principles indicate that a particu-
lar control is expected to increase a given emission, but supporting data are missing
• Low potential emissions impact, where the data show that emissions are unaffected or
decreased when using a given control, or when basic formation mechanisms clearly indicate
the same conclusion
Areas of high and intermediate potential impact are prioritized for future E/A consideration and
elucidation. Areas of low potential impact will be accorded lower priority in subsequent E/A efforts.
6.1 PRELIMINARY SCREENING
To evaluate incremental emissions due to applying combustion modification NO controls, it
is helpful to first outline the areas where expected adverse effects on emission levels may occur.
Such an approach requires linking the N0x control-induced combustion conditions to the expected
changes in emission levels through pollutant formation mechanisms. This is accomplished in Sec-
tion 6.1.1 which addresses combustion modifications applied to boilers; in Section 6.1.2 which treats
combustion N0x controls applicable to stationary internal combustion (1C) engines and gas turbines;
and in Section 6.1.3 which reviews the data for warm air furnaces. The discussion is separated in
6-2
-------
this manner because the specific methods used to achieve low-NOx formation conditions differ sig-
nificantly between these equipment classes. This is true even though the desired low-NO combustion
conditions may be similar from equipment class to class.
Each of the following subsections:
i Lists the set of N0x combustion controls appropriate to the given equipment class
• Lists the altered combustion conditions resulting from imposing each control
• Postulates the effect of each combustion condition on the level and speciation of each
combustion-generated pollutant considered
• Evaluates the overall effect of each combustion modification on the level and speciation
of each pollutant by summing individual combustion condition contributions
• Identifies combustion control/pollutant pairs in which the emission level is likely to
increase with use of NO control
This preliminary screening represents informed speculation based on what is known about how combus-
tion NO controls act, and how combustion-generated pollutants are formed. The primary purpose is
A t,
to screen the matrix of control/pollutant pairs for expected adverse emission effects. Thus, some
guidance for future E/A study can be formulated even in the absence of supporting data.
6.1.1 Boilers
The commonly suggested near-term combustion modification N0x controls for boilers were sum-
marized in Section 4.2. Applying any one of these modifications will impose some number of altered
combustion conditions from the set summarized in Table 6-1. Table 6-1 also lists the postulated
effects each resulting combustion condition will have on incremental emissions of carbon monoxide,
vapor phase hydrocarbon, sulfate, particulates, other organic compounds, and trace metals.
In this discussion, vapor phase hydrocarbon (HC) emissions are defined as primary emissions
of aliphatic, oxygenated, and low molecular weight aromatic organic compounds which exist in the
vapor phase at flue gas temperatures. Organic emissions are defined as primary emissions of higher
molecular weight aromatic compounds which exist largely as a condensed (liquid or solid) phase at flue
gas temperatures. Thus, organic emissions will largely consist of polycyclic organic matter (POM) or
polycyclic aromatic hydrocarbons (PAH), including polychlorinated and polybrominated biphenyls
(PCB and PBB) if they exist. Vapor phase hydrocarbons include virtually all other emitted organic
compounds including alkanes, alkenes, aldehydes, carboxylic acids, and substituted benzenes (e.g.,
6-3
-------
TABLE 6-1. POSTULATED EFFECT OF COMBUSTION CONDITIONS ON FLUE GAS EMISSIONS FROM BOILERS
Combustion
Condition
Reduced local 0~
concentration
Reduced peak
flame temperature
Increased convec-
tion zone temper-
atures
Decreased gas
velocity
Increased gas
velocity
Increased
residence time
Decreased
residence time
Delayed fuel-
air mixing; off-
stoichiometric
combustion
More turbulent
flame
Increased
local H20
concentration
Increased local
NH3 concentration
CO
Increased
No effect
No effect
No effect
No effect
Possibly decreased
Possibly increased
Possibly increased
Probably no effect
No effect
No effect
Vapor Phase HC
Increased
No effect
No effect
No effect
No effect
Possibly decreased
Possibly increased
Possibly increased
Possibly decreased
No effect
No effect
Sul fate
Decreased
Possibly decreased because of decreased
catalyst metal volatilization and sub-
sequent internal condensation (despite
S03 being favored at low temperatures)
Possibly increased because of increased
convection zone catalyst deposition
Increased because of increased convec-
tion zone catalyst deposition
Decreased because of less catalyst
condensation and deposition in boiler
Possibly increased because of greater
chance for reaction
Possibly decreased
Possibly decreased because of less
potential for SOp oxidation
Possibly increased because of more
intimate SOg, 02, catalyst particle
contact
Possibly increased
Possibly increased through near plume
solution catalysis
Organics
Possibly increased because of poorer com-
bustion efficiency and increased carbona-
ceous particle formation
Possibly increased because of less pyrol-
ysis and subsequent oxidation
Probably no effect
Decreased because of decreased particle
emissions
Increased because of increased particle
emissions
Possibly decreased because of greater
chance for carbon burnout
Possibly increased
Possibly increased because of greater
carbonaceous particle formation
Possibly decreased because of less soot
particle formation
Possibly decreased because of decreased
particle emissions
Possibly decreased because of decreased
particle emissions
(Continued on page 6-5)
-------
TABLE 6-1. Continued
Combustion
Condition
Particulate
Size Distribution
Mass Emissions
Trace Metals
Segregating
Nonsegregating
Reduced local CL
concentration
Possible trend to larger
sizes because of less
carbon burnout
Unknown effect: possibly in-
creased soot emissions be-
cause of greater unburned
carbon particles. Possibly
reduced because of increased
bottom ash and hopper fall-
out, and greater particle
control efficiency for
larger particles.
Possibly increased because
metals remain vaporized
(don't form less volatile
oxides) longer, resulting
in greater concentration in
smaller particles
Possibly reduced because of
reduced overall particle
emissions (larger particles
formed)
Reduced peak
flame temperature
Probably no effect
Possibly increased because of
reduced slagging and bottom
ash fallout
Possibly reduced with parti-
cle controls because of de-
creased volatilization and
redistribution to small
particles
Possibly increased because
of reduced bottom ash
fallout
Increased
convection zone
temperatures
Probably no effect
Possibly reduced because of
increased convection zone
fouling
Possibly increased because
metals remain vaporized
longer and can segregate to
small particles
Possibly reduced because of
increased convection zone
fouling
Decreased gas
velocity
No effect
Decreased under normal opera-
tion because of greater
particle deposition and
hopper ash fallout
Decreased because of increased
convection zone deposition
Decreased because of in-
creased convection zone
deposition
Increased gas
velocity
No effect
Increased because of less
convection zone particle
deposition and hopper ash
fallout
Increased because of increased
particle emissions
Increased because of in-
creased particle emissions
Increased
residence time
Possible trend to smaller
particles because of poten-
tially increased carbon
burnout
Possibly decreased because
of potentially increased
carbon burnout
Probably no effect
Probably no effect
Decreased
residence time
Possible trend to larger
particles
Possibly increased because
of potentially decreased
carbon burnout
Probably no effect
Probably no effect
(Continued on page 6-6)
-------
TABLE 6-1. Concluded
Combustion
Condition
Delayed fuel-
air mixing; off-
stoichiometric
combustion
More turbulent
flame
Increased local
H20 concentra-
tion
Increased local
NH? concentra-
tion
Particulate
Size Distribution
Trend to larger particles
Trend to smaller particles
Probably no effect
Trend to smaller particles
(NH4HS04 aerosol)
Mass Emissions
Possibly increased because
of greater soot formation
Possibly decreased because
of decreased soot formation
Possibly decreased with
ESPs because of resistivity
conditioning
Possibly decreased with
ESPs because of NH, (NH4HS04)
conditioning effects
Trace Metals
Segregating
Possibly decreased because
of overall trend to larger
particles, more easily
controlled
Possibly increased because
of overall trend to smaller
particles
Possibly decreased because
of decreased particle
emissions
Unknown effect: greater
proportion of small
particles, but better ESP
efficiency possible
Nonsegrating
Possibly decreased because
larger particles more
easily controlled
Possibly increased because
of overall trend to smaller
particles
Possibly decreased due to
lowered particle emissions
Possible decreased due to
lowered particle emissions
-------
benzene, toluene, xylene, ethylbenzene, etc.). This breakdown corresponds to that adopted 1n
References 6-1 and 6-2.
Sulfate emissions are addressed 1n Table 6-1 instead of simple SO emissions because acid
sulfate aerosol emissions are far more sensitive to combustion conditions. About 98 percent of
the original fuel-bound sulfur introduced into a boiler typically appears in the flue gas (Ref-
erence 6-3) in some form. Combustion conditions are expected to have little effect on total SO
(S02, S03> H2S04 and metal sulfates) emissions. However, effects on the So!/S02 ratio and the
speciation of sulfate between HgSO^ and condensed metal sulfates can be quite significant.
In Table 6-1 comments on particulates address these emissions as a single pollutant class.
Effects on particle composition are considered as effects on sulfate, trace metal, and organic
emissions. Particulate comments are further subdivided into expected particle size distribution
effects and particulate mass emissions effects. This is done for several reasons. First, emitted
size distribution has a significant bearing on eventual adverse pollutant effects. Fine particulate
presents greater adverse health effects than coarse particulate because fine particles most easily
penetrate the body's pulmonary defenses, and remain in the lungs for longer times. Furthermore, fine
particulate remains suspended in the air for longer times. Secondly, combustion-produced particle
size distribution has great impact on the actual particle load emitted from boilers with particulate
controls. Fine particulate is less easily caught by these controls. Particle size distribution
also significantly affects the level of trace metal emissions in these boilers. As discussed in
Section 6.2.4, certain trace elements tend to concentrate in the small particles emitted from a
boiler. Thus, modifications which shift the emitted particle size distribution to smaller sizes
would tend to increase the emissions of this group of trace metals. Finally, as discussed in
Section 6.2.5, particle size distribution can have significant effects on S02 to S03, and ultimately
sulfate, conversion.
For analogous reasons, trace metal emissions are discussed in two subsets in the table:
segregating trace metals and nonsegregating trace metals. Segregating trace elements are those
which tend to concentrate in fine particulate. Nonsegregating trace elements are those that remain
essentially evenly distributed (on a fractional mass basis) in particles of all sizes. The emissions
characteristics of each croup are quite different. Nonsegregating trace metal emissions are larqelv
determined by total particulate mass emissions. Conversely, segregating trace metal emissions are
significantly affected by emitted particle size distribution and boiler temperature-time profile.
6-7
-------
The entries in Table 6-1 largely refer to a coal-fired utility boiler with a cold side electro-
static precipitator particulate control. This type of boiler represents the most general equipment
class for present considerations. It exhibits all the emissions listed in the table, and illustrates
the type of effects which can occur with changes in produced particle size distribution. As a re-
sult, not all entries in the table refer to all boilers. For example, natural gas-fired boilers
essentially emit only CO and small quantities of HC. Thus, all entries under trace metal, organics,
particulate, and sulfate do not strictly apply to gas-fired boilers. Similarly certain comments
under particulate, organics, and trace metal headings do not strictly apply to oil- or coal-fired
boilers without particulate controls. For example, many comments are based on the assumption that
modifications which tend to produce smaller particles would tend to increase particulate mass emis-
sions; this is because particulate controls are less efficient at collecting fine particulate.
Organic (particulate POM), and segregating trace metal emissions would show corresponding increases
in these instances. However, on boilers without particulate controls, a shift in particle size dis-
tribution, at constant mass production, would yield no change in emissions of particulate, organics,
or trace metals. Still, with suitable interpretation, the table comments essentially describe what
is expected to occur in any boiler, when the appropriate combustion condition is imposed.
As indicated in Table 6-1, CO and vapor phase hydrocarbon emissions are expected to be in-
fluenced only by excess boiler Op concentrations. Changes in furnace residence times or flame zone
mixing may also elicit slight changes in these emissions, though these are not expected to be
significant.
Sulfate emissions are influenced by local 0? concentrations, and by the presence of metal
oxidation catalysts such as vanadium and its oxides. Thus, changes in the temperature-time profile
in a boiler influence catalyst metal volatilization, oxidation, and condensation, and thereby in-
fluence S02 to S03 conversion. For example, reducing peak flame temperature would cause less trace
metal volatilization. Subsequently less metal vapor would be available to condense on gas stream
fine particle surfaces. Consequently the availability of oxidation catalyst is limited, and less
sulfate production is expected. Conversely lowered furnace gas velocities would allow increased
amounts of internal particulate deposition, and thus increased levels of SO, production.
O
6-8
-------
Particle size distribution is probably affected largely by the degree of combustion complete-
ness, and the degree of flame zone mixing. Incomplete combustion or mixing can yield large particles
with high carbon content. Particulate mass emissions will be affected by: the degree of combustion
completeness (level of carbonaceous soot formation); the produced particle size distribution (large
particles tend to fall out as bottom ash and are more easily collected in particulate control de-
vices); and the temperature profile in the boiler as it affects ash slagging. Special circumstances
exist in boilers equipped with ESPs. In these, increased flue gas water vapor, sulfate, or ammonia
(or more appropriately ammonium bisulfate, Reference 6-4) concentrations can act to condition the
flyash, thereby increasing ESP collection efficiency, and decreasing net particulate emissions.
Organic emissions, as we have defined them here (chiefly POM), are mainly influenced by the
level of particulate emissions and the carbon content of the particulate. Thus, conditions which
inhibit complete combustion, and conditions which increase particulate load will increase condensible
organic emissions.
Nonsegregating trace metal emission levels are essentially functions of total particulate
mass emissions. Segregating trace metal emissions, however, are influenced by the particle size
distribution, the boiler temperature-time profile, and local 02 concentrations. Lowered peak tem-
peratures will decrease the extent of initial metal volatization, so particle size redistribution
effects are less pronounced. Increased convection zone temperatures, however, allow volatile metals
to remain in the vapor phase for longer times. Thus, when nucleation/condensation eventually occurs,
condensation nuclei have less time to grow, and particle size redistribution effects are more pro-
nounced. Low local 0? levels also inhibit metal oxide formation. Since metal oxides are, in gen-
eral, less volatile than the base metal, low Op levels extend the time the metals exist as vapors.
Again, particle size redistribution effects will become more pronounced.
Table 6-1, as discussed above, outlined the postulated effects of individual, isolated com-
bustion conditions on the level of flue gas emissions. Table 6-2 summarizes the postulated overall
effects of implementing combustion modification NO controls, each of which, as shown, can effect
several combustion condition changes. Table 6-2 reflects the cumulative effects of each altered
combustion condition appropriate to a given combustion control technique.
Table 6-2 shows that:
• Increased CO and vapor phase hydrocarbon emissions are of major concern only when excess
air levels are lowered
• Sulfate emission levels are expected to decrease or remain unchanged with all controls
except combustion staging and ammonia injection
6-9
-------
TABLE 6-2. POSTULATED OVERALL EFFECT OF COMBUSTION NO. CONTROLS ON FLUE GAS EMISSIONS FROM BOILERS
Combustion
Modification
Low excess air
Staged combustion
Flue gas
recirculation
Reduced air
preheat
Reduced load
Water
injection
Ammonia
injection
Resulting Combustion
Conditions
Reduced local 02 concentra-
tion; decreased gas veloci-
ties; increased furnace
residence time
Reduced local 02 concentra-
tion; reduced peak flame
temperature; increased con-
vection zone temperature;
delayed flame zone mixing
Reduced local 02 concentra-
tion; reduced peak flame
temperature; reduced furnace
residence time; increased
gas velocities; more turbu-
lent flame; increased con-
vective zone temperature
Reduced peak flame tempera-
ture; decreased gas veloci-
ties; increased furnace
residence times; increased
local 0- concentration
Reduced flame temperature;
decreased gas velocities;
decreased furnace residence
times; increased local 0~
concentration
Reduced peak flame tempera-
ture; increased local H20
concentration
Increased local NH3
concentration
CO
Increased
Possibly increased
Possibly Increased
No effect
Decreased
No effect
No effect
Vapor Phase HC
Increased
Possibly increased
Possibly increased
No effect
Decreased
No effect
No effect
Sulfate
Decreased overall because of
lowered 02 availability
Possibly decreased because of
decreased convection zone
catalysis (less volatile metal
redistribution)
Possibly decreased
Possibly decreased
Unknown effect: Less
catalyst volatilization;
but greater local 02
concentrations
Possibly decreased
Possibly increased through
near plume solution
catalysis
Organics
Possibly increased
Possibly increased
Possibly increased
Possibly increased
Possibly decreased
Possibly increased
Decreased with
decreased particle
emissions; no
effect otherwise
-------
TABLE 6-2. Concluded
Combustion
Modification
Low excess air
Staged
combustion
Flue gas
recirculation
Reduced air
preheat
Reduced load
Water
injection
Arnmonla
injection
Particulate
Size Distribution
Possible trend to larger
sizes
Possible trend to larger
sizes
Probably no effect
Probably no effect
Probably no effect
Probably no effect
Trend to smaller particles
(NH4HS04 aerosol)
Mass Emissions
Possibly decreased because of
increased bottom and ash
fallout and internal deposi-
tion
Unknown effect: possible
increase due to soot forma-
tion; possible decrease due
to larger particles and con-
vection zone depositon and
slagging
Possibly increased due to
increased velocities and
possibility of soot formation
Possibly increased due to •<
less bottom slagging
Probably no net effect
Possibly decreased with ESPs
because of conditioning;
possibly increased otherwise
Possibly decreased with ESPs
because of conditioning;
increased otherwise
Trace Metals
Segregating
Unknown effect: possible in-
crease due to increased
volatility but possible de-
crease with internal deposi-
tion
Possibly decreased because of
decreased repartitioning to
small particles
Possibly decreased because of
decreased repartitioning to
small particles
Possibly reduced because of
less concentration in small
particles
Possibly reduced because of
less concentration in small
particles
Possibly reduced because of
less small particle concen-
tration and lowered particle
emissions
Possibly increased because
larger fraction of small
particles
Nonsegregating
Possibly reduced because of
reduced mineral particle
emissions and internal
particle deposition
Possibly reduced due to
larger particles (more car-
bon) and convection zone
slagging
Possibly increased with
increased particle emissions
Possibly increased with
increased particle emissions
Probably no effect
Possibly decreased with
ESPs, possibly increased
otherwise; follows particu-
late load
Decreased with decreased
particle emissions; no
effect otherwise
Ol
vo
-------
• Changes in emitted particle size distribution are expected only when imposing staged
combustion or lowered excess air modifications. In these instances the production of
larger particles is expected
• Increased particulate mass emissions are of potential concern when flue gas recirculation
is used
0 Condensible organic emissions are likely to increase with all combustion N0x controls
except ammonia injection
• Increased segregating trace metal emissions are possible when using staged combustion,
flue gas recirculation, and ammonia injection
• Nonsegregating trace metal emissions are only of potential concern when implementing flue
gas recirculation and reduced air preheat
6.1.2 Reciprocating 1C Engines and Gas Turbines
The commonly considered combustion modifications for NO control applicable to stationary 1C
X
engines and gas turbines were summarized in Section 4.2. The set of combustion conditions result-
ing from imposing these modifications, and the postulated effects of each altered combustion condi-
tion on the pollutants under consideration are listed in Table 6-3. The pollutant classes tabulated
in Table 6-3 are the same as those considered above for boilers. However, since 1C engines and gas
turbines burn natural gas or petroleum distillates (kerosene or diesel fuel) almost exclusively,
some of these pollutants are currently of minor importance. For example, trace metal emissions
would be of concern only for residual oil-fired gas turbines, or when fuel additives are used with
distillate oils.
In Table 6-3 the postulated effects of combustion condition on incremental air emissions
from stationary 1C engines and gas turbines are similar to those discussed above for boilers. Ex-
ceptions here stem from the absence of particulate control devices on 1C engine and gas turbine ex-
haust streams. In these exhaust streams particulate mass emissions and condensible organic emissions
are determined solely by the degree of combustion completeness. Particle size distribution effects
in the absence of particulate controls, do not influence these emissions. Similarly, emissions of
nonsegregating (i.e., nonvolatilizing) trace metals are not affected by all combustion conditions;
essentially everything introduced with the fuel leaves in the exhaust. Emissions of segregating
trace metals are affected only by the combustion gas temperature-time profile, and by local 02 con-
centrations. These affect the amount of trace metal (and which elements) that volatilize, and where
condensation or deposition occurs. Thus, because reduced peak temperatures cause a lesser degree
6-12
-------
TABLE 6-3. POSTULATED EFFECTS OF COMBUSTION CONDITIONS ON EMISSIONS FROM 1C ENGINES AND GAS TURBINES
Combustion
Condition
Reduced peak temperature
Reduced residence time
at temperature
Reduced local 0?
concentration
Increased local 0?
concentration
Increased local FUO
concentration
CO
Possibly increased
Possibly Increased due to
incomplete combustion
Possibly increased due to
Incomplete combustion
Reduced
No effect
HC
Possibly increased
Possibly increased due to
incomplete combustion
Possibly increased due to
incomplete combustion
Reduced
No effect
Sul fate
Unknown effect; potentially
increased because S03
favored at lower tempera-
tures; potentially decreased
because of decreased trace
metal volatilization and
deposition
Possibly decreased because
of decreased trace metal
volatilization and subse-
quent deposition
Decreased
Increased
Possibly increased
Organ ics
Possibly increased
Possibly increased due to
incomplete combustion
Possibly increased due to
incomplete combustion
Possibly reduced .
No effect
(Continued on page 6-14)
-------
TABLE 6-3. Concluded
Combustion
Condition
Reduced peak
temperature
Reduced
residence time
at temperature
Reduced local 02
concentration
Increased local
Op concentration
Increased local
H-0 concentration
Participate
Size Distribution
Probably no effect
Trend to larger sizes due to
incomplete vaporization and
combustion of fuel droplets
Trend to larger sizes due to
incomplete combustion of fuel
droplets
Trend to smaller sizes
Probably no effect
Mass Emissions
Possibly increased
Possibly increased due to
incomplete combustion
Possibly increased due to
incomplete combustion
Possibly reduced
Probably no effect
Trace Metals
Segregating
Possibly slightly increased
due to decreased volatiliza-
tion and internal deposition
Possible slight increase due
to decreased volatilization
and subsequent internal
deposition
Possible slight increase due
to decreased formation of
less volatile metal oxides,
resulting in less internal
deposition
Possible slight decrease due
to increased oxide formation
and subsequent internal
deposition
No effect
Nonsegrating
No effect
No effect
No effect
No effect
No effect
-------
of segregating metal volatilization and subsequent deposition on internal chamber surfaces, there
will be a slight increase in emissions. Similarly lowered local (L concentrations allow a lesser
degree of metal oxidation, thereby reducing nonvolatile metal oxide deposition, and slightly in-
creasing exhaust emissions.
Table 6-4 summarizes each N0x control considered, and its postulated overall effect on the
incremental emissions from 1C engines. Table 6-5 is the analogous summary for gas turbines.
6.1.3 Warm Air Furnaces
Over 90 percent of residential and commercial warm air furnaces fire either natural gas or
distillate oil. Emissions oT sulfates and trace metals from these units are thus of minor concern
compared to coal-fired boilers. About 3 percent of U.S. warm air furnaces still fire coal. For
these, sulfates, trace metals and especially ROMs could cause severe localized environmental prob-
lems. It is doubtful that NO controls, except for fuel switching, will be developed and implemented
for these sources, however, and they will not be considered further here.
An additional factor in evaluating incremental emissions from warm air furnaces is the cyclic
nature of operation. Warm air furnaces typically undergo 2 to 5 on/off cycles per hour. Studies
of emissions without NO controls show that the starting and stopping transients have a strong, some-
times dominant, effect on total emissions of CO, HC and particulate (smoke) (References 6-5, 6-6).
The effect of NO controls on transient emissions is presently unknown. Incremental steady state
emissions must eventually be weighed against the transient emissions however, for this significance
to be shown.
The range of combustion process modifications effective for N0x control in warm air furnaces
is more limited than was the case for the larger equipment types discussed above. This is due both
to the combustion design constraints specific to this application and to the low unit capital and
operating costs which make extensive modification unattractive. Minor process modifications, pri-
marily burner tuning, are ineffective for NO control in a given unit (References 6-5, 6-6). Un-
X
controlled NO emissions among units with different burner/firebox designs differ by a factor of
X
two or more, however (References 6-6, 6-7). Thus, the use of low N0x burner/firebox combinations,
for application to new units, is the prime candidate for NOX control in warm air furnaces.
The combustion conditions typical of low N0x operation in warm air furnaces are as follows:
• Lower excess air
• Reduced peak flame temperature
6-15
-------
TABLE 6-4. POSTULATED OVERALL EFFECT OF COMBUSTION NOX CONTROLS ON EMISSIONS FROM 1C ENGINES
Combustion
Modification
Retard ignition
Increase air/
fuel ratio
Decrease air/
fuel ratio
Exhaust gas
recirculation
Decrease
manifold air
temperature
Stratified
charge cylinder
design
Derate
Increase speed
Water
injection
Resulting Combustion
Condition
Reduced peak tempera-
ture; reduced time at
temperature
Reduced peak tempera-
ture; increased local
02 concentration
Reduced peak tempera-
ture; reduced local
02 concentration
Reduced peak tempera-
ture; reduced local
Og concentration
Reduced peak tempera-
ture
Reduced peak tempera-
ture; reduced residence
time at temperature;
reduced local 0^
concentration
Reduced peak tempera-
ture
Reduced residence time
at temperature
Reduced peak tempera-
ture; reduced local
02 concentration;
increased local ^0
concentration
CO
Possibly increased due
to incomplete combus-
tion
Decreased
Possibly increased
Possibly increased
Possible increase
Possibly increased
due to incomplete
combustion
Possible increase
Possible increase
due to incomplete
combustion
Possibly increased
due to incomplete
combustion
Vapor Phase HC
Possibly increased due
to incomplete combus-
tion
Decreased
Possibly increased
Possibly increased
Possible increase
Possibly increased
due to incomplete
combustion
Possible increase
Possible increase
due to incomplete
combustion
Possibly increased
due to incomplete
combustion
Sulfate
Potentially decreased
due to decreased metal
catalyst internal
depostion
Increased
Decreased
Decreased
Unknown effect: pos-
sible increase because
SOa favored at lower
temperatures; possible
decrease due to de-
creased catalytic oxi-
dation
Potentially decreased
Unknown effect
Possible decrease due
to decreased catalyst
deposition
Potentially decreased
Organics
Possibly increased
due to incomplete
combustion
Possibly decreased
Possibly increased
due to incomplete
combustion
Possibly increased
due to incomplete
combustion
Possible increase
Possibly increased
due to incomplete
combustion
Possible increase
Possible increase
due to incomplete
combustion
Possible increase
due to incomplete
combustion
91
I
Ol
(Continued on page 6-77)
-------
TABLE 6-4. Concluded
Combustion
Modification
Retard ignition
Increase air/
fuel ratio
Decrease air/
fuel ratio
Exhaust gas
recirculation
Decrease
manifold air
temperature
Stratified
change cylinder
desi gn
Derate
Increase speed
Water
Injection
Parti cul ate
Size Distribution
Possible trend to larger
sizes due to incomplete
combustion
Possible trend to smaller
sizes
Possible trend to larger
sizes due to incomplete
combustion
Possible trend to larger
sizes due to incomplete
combustion
Probably no effect
Possible trend to larger
sizes
Probably no effect
Possible trend to larger
sizes
Possible trend to larger
sizes
Mass Emissions
Possibly increased due to
incomplete combustion
Possibly decreased
Possibly increased due to
incomplete combustion
Possibly increased due to
incomplete combustion
Possible increase
Possibly increased due to
incomplete combustion
Possible increase
Possible increase due to
incomplete combustion
Possible increase due to
incomplete combustion
Trace Metals
Segregating
Possible slight decrease due
to reduced internal deposi-
tion
Possible slight decrease due
to reduced internal deposi-
tion
Possible slight increase
Possible slight increase
Possible slight increase due
to decreased internal deposi-
tion
Possible slight increase due
to decreased internal deposi-
tion
Possible slight increase
Possible slight increase
Possible slight increase
Nonsegregating
No effect
No effect
No effect
No effect
No effect
No effect
No effect
No effect
No effect
-------
TABLE 6-5.
POSTULATED OVERALL EFFECT OF COMBUSTION NOX CONTROLS ON EMISSIONS FROM GAS TURBINES
Combustion
Modification
Water or steam
injection
Lean primary
zone
Early quench
with secondary
air
Increase mass
flowrate
Exhaust gas
recirculation
Air blast or air
assist atomiza-
tion
Reduced air
preheat
Reduced load
Resulting Combustion
Condition
Reduced peak tempera-
ture; reduced residence
time at temperature;
reduced local 02 con-
centration; decreased
local H^O concentration
Reduced peak tempera-
ture; increased local
02 concentration; re-
duced residence time at
temperature
Reduced residence time
at temperature
Reduced residence time
at temperature
Reduced peak tempera-
ture; reduced local 0,
concentration
Reduced peak tempera-
ture; reduced local 0,
concentration
Reduced peak tempera-
ture
Reduced peak tempera-
ture; reduced local 02
concentration
CO
Possibly increased due
to incomplete combus-
tion
Decreased
No effect
Possibly increased due
to incomplete combus-
tion
Possibly increased due
to incomplete combus-
tion
Possibly increased due
to incomplete combus-
tion
Possibly increased
Increased
Vapor Phase HC
Possibly increased due
to incomplete combus-
tion
Decreased
No effect
Possibly increased due
to incomplete combus-
tion
Possibly increased due
to incomplete combus-
tion
Possibly increased due
to incomplete combus-
tion
Possibly increased
Increased
Sulfate
Potentially decreased
Possibly increased
Potentially decreased
Possibly increased due
to decreased catalyst
metal internal deposi-
tion
Potentially decreased
Potentially decreased
Unknown effect: pos-
sible increase because
S03 favored at lower
temperatures; possible
decrease due to de-
creased internal cata-
lyst deposition
Potentially decreased
Organ ics
Possibly increased
due to incomplete
combustion
Possibly decreased
Unknown effect
Possible increase
due to incomplete
combustion
Possibly increased
due to incomplete
combustion
Possibly increased
due to incomplete
combustion
Possibly increased
Possibly increased
(Continued on page 6-19)
-------
TABLE 6-5. Concluded
Combustion
Modification
Water or steam
injection
Lean primary
zone
Early quench
with secondary
air
Increase mass
flowrate
Exhaust gas
recirculation
Air blast or air
assist atomiza-
tion
Reduced air
preheat
Reduced load
Parti cul ate
Size Distribution
Possible trend to larger
sizes due to incomplete
combustion
Possible trend to smaller
sizes
Possible trend to larger
sizes
Possible trend to larger
sizes
Possible trend to larger
sizes
Possible trend to larger
sizes
Probably no effect
Possible trend to larger
sizes
Mass Emissions
Possibly increased due to
incomplete combustion
Possibly decreased
Possible slight increase
Possible increase due to
incomplete combustion
Possibly increased due to
incomplete combustion
Possibly increased due to
incomplete combustion
Possibly increased
Increased
Trace Metals
Segregating
Possible slight increase due
to decreased internal deposi-
tion
Possible slight increase due
to decreased internal deposi-
tion
Possible slight increase
Possible slight increase due
to decreased internal deposi-
tion
Possible slight increase due
to decreased internal deposi-
tion
Possible slight increase
Possible slight increase due
to decreased internal deposi-
tion
Possible slight increase
Nonsegregating
No effect
No effect
No effect
No effect
No effect
No effect
No effect
No effect
o»
VD
-------
• Delayed fuel air mixing and/or internal recirculation of combustion products
t Longer residence time
The general effects on combustion-generated pollutants are largely as summarized in Table 6-1 for
boilers. Taken individually, the general expectation is for the modified combustion condition to
increase incremental emissions. For example, Figure 6-1 shows the effect of lower excess air on
CO, HC and smoke emissions (Reference 6-8). However, through careful engineering during control
development, it has been possible to achieve 1ow-NOv combustion conditions without adverse incre-
A
mental emissions (Reference 6-9). Table 6-6 shows a comparison of typical uncontrolled units and a
prototype unit with an optimized burner/firebox. Incremental emissions were held constant or re-
duced at the low-NO , high-efficiency condition. Table 6-6 also shows incremental emissions with a
commercially available oil emulsifier burner. Again, low-NO operation was achieved with no adverse
effects on incremental emissions (Reference 6-10).
Data on warm air furnace POM emissions under low-NO operation are apparently nonexistent.
X
Data on both transient and steady operation with and without NO controls are needed to form a gen-
A
eral conclusion on the total incremental impact of NO controls. Additionally, it should be empha-
sized that the incremental emissions data shown in Table 6-6 are for well maintained laboratory
operation. Data are needed on long-term field operation with NO controls.
6.2 EMISSIONS DATA EVALUATION
The previous subsection described the expected incremental effects of NO combustion con- '
trols on the emission of pollutants other than NO from stationary combustion sources. This sub-
A
section supports that development by presenting and discussing the available incremental emissions
data obtained through several N0x control evaluation studies. The discussion is divided into seven
subsections, one for each pollutant considered in Section 6.1, plus an additional discussion of
nitrate emissions. It should be noted that data on the emissions of pollutants other than CO,
hydrocarbons, and particulate, as a function of NO control implementation, are spotty to nonexis-
X
tent. Consequently in these cases a more detailed analysis of postulated pollutant formation mech-
anisms is presented. In light of this, an assessment of the relative need to develop the requisite
information can be made.
6.2.1 Carbon Monoxide
The presence of CO in the exhaust gases of combustion systems results from incomplete fuel
combustion. Several conditions existing in a combustion source can give rise to incomplete combus-
tion. These include:
6-20
-------
2.00
Smoke
(10th
min.)
1.50-1-
0)
3
Dl
Dl
CJ
T3
(0
i.oo 4-
0.50
0.00
,4 I
/ \ -T—. ef1
/ \ : "--
Optimum setting for minimum |
emissions and maximum |
efficiency
I +
46
10
c
Ol
QJ
Q.
8 £
X
CD
O
O
40 60 80
Excess air, %
16 14 12
Figure 6-1.
10
8
co2,
Effect of excess air on emissions from
an oil-fired warm air furnace.
(Reference 6-8).
6-21
-------
TABLE 6-6. EFFECT OF LOW-NOX OPERATION ON INCREMENTAL EMISSIONS AND
SYSTEM PERFORMANCE FOR RESIDENTIAL WARM AIR FURNACES
Typical uncontrolled
field units
(References 6-5, 6,6)
Optimum low NOx unit
(Reference 6-9)
Water/distillate oil
emulsion burner: 32% H?0
(Reference 6-10)
Excess
Air
90%
15%
32%
Thermal
Efficiency
(Steady-State)
70%
80%
80%
NO
g/kg fuel
1.1 - 2.7
0.6
0.85
CO
g/kg fuel
1.05
1.0
0.3
HC
g/kg fuel
0.1
0.1
Smoke
Bacharach
3.2
1
~1
r>>
ro
-------
• Insufficient 02 availability
• Poor fuel/air mixing
t Cold wall flame impingement
• Reduced combustion temperature
• Decreased combustion gas residence time
As noted in Section 6.1, various combustion modifications for NO reduction can produce one or more
A ^
of the above conditions. Consequently, the possibility of increased CO emissions due to combustion
NO controls represents a justifiable concern.
A
Since field test programs investigating NO controls generally monitor combustion source CO
X
to provide an indication of combustion efficiency, sufficient data are available to assess the effect
these controls have on residual CO emissions. These data are presented and evaluated in the follow-
ing subsections for utility boilers (6.2.1.1), industrial boilers (6.2.1.2), internal combustion (1C)
engines (6.2.1.3), and gas turbines (6.2.1.4).
6.2.1.1 Utility Boilers
Since large quantities of CO in the flue gas of utility boilers mean decreased efficiency,
these boilers are operated to keep CO emissions at a minimum. Furthermore, if flue gas CO levels
reach concentrations in excess of 2,000 ppm, severe equipment damage can result because of explosions
in flue gas exit passages. Thus, the degree to which a NOX reduction technique is allowed to in-
crease CO is limited by other than environmental concerns. In general, a NO control method is ap-
plied until flue gas CO reaches about 200 ppm. Further application is then curtailed.
NO control effects on CO emissions are highly dependent on the equipment type and the fuel
fired. In utility boilers of newer design, it is generally possible to achieve good NOX reduction
without causing significant CO production. This is possible because newer burner and furnace designs
allow for better combustion air control and longer combustion gas residence time. In addition, oil-
and coal-fired boilers usually emit very low CO levels during low-NOx combustion because smoke and
soot production generally occur with these fuels before significant CO levels are attained. Since
boiler operators strive to keep combustible losses to a minimum, conditions which result in soot
formation are avoided, resulting in correspondingly low CO levels.
The combustion modifications commonly applied to utility boilers were discussed in Section 4.2.
A sumnary of the field data on the effects of the more extensively implemented modifications on
CO emissions is shown in Table 6-7. These data are discussed below for each combustion N0x control.
6-23
-------
TABLE 6-7. REPRESENTATIVE EFFECTS OF NOX CONTROLS ON CO
EMISSIONS FROM UTILITY BOILERS
(References 6-11, 6-12, 6-13)
NOV Control
A
Low Excess Air
Off-Stoichiometric
Combustion
Fuel
Natural Gas
Oil
Coal
Natural Gas
Oil
Coal
CO Emissions (ppm)a
Baseline
14
86
12
8
14
19
85
15
19
42
20
24
27
27
14
86
12
14
19
85
15
28
24
- 27
17
31
NO Control
y\
68
74
61
8
34
42
53
20
19
93
60
283
81
225
16
67
13
14
21
85
21
37
23
26
40
45
13% 02, dry basis.
6-24
-------
TABLE 6-7. Concluded
NO Control
A
Flue Gas Recirculation
Load Reduction
Fuel
Natural Gas
Oil
Natural Gas
Oil
Coal
CO Emissions (ppm)a
Baseline
175
21
14
52
12
14
19
30
15
19
20
25
31
24
NOV Control
X
65
9
13
52
15
21
14
5
19
22
41
19
8
12
3% 02, dry basis.
6-25
-------
Low Excess Air
As the data in Table 6-7 illustrate, lower excess air levels in utility boilers can have
profound effects on CO emissions. In virtually all instances, CO emissions increased significantly
when excess 0? levels were reduced 30 to 60 percent. Gas-fired boilers showed emission increases
up to 400 percent when excess 02 was lowered over this range, while oil-fired boilers were less
sensitive, and showed CO emission increases from 0 to 120 percent. However, coal-fired boilers
were the most sensitive to excess air reductions. Reducing excess 02 by 40 to 60 percent gave 100
to 1,000 percent increases in CO emissions.
Off-Stoichiometric Combustion
Off-stoichiometric, or staged, combustion has proven to be a very effective N0x reduction
technique for large steam generators. As discussed in Section 4.2, it can be implemented in a
variety of ways including burners out of service, overfire air ports, and biased firing. In all
cases, the effectiveness of off-stoichiometric combustion (OSC) in reducing N0x emissions depends in
large part on the fraction of total combustion air that can be introduced into the second combustion
stage. It is in this second stage that complete combustion of the fuel is achieved. CO emissions
arise when this second stage combustion does not go to completion prior to quenching in the convec-
tive section. This is caused by a combination of the first stage being too fuel rich and the mixing
of second stage air being too slow for the residence time provided. During development of retrofit
or new design controls, these parameters are usually selected so that CO emissions are acceptable.
The effectiveness of OSC in reducing NO formation while keeping CO emissions low is highly
X
dependent on specific equipment type. New utility boilers with multiburner furnaces are especially
amenable to this technique because it is generally not difficult to adequately distribute secondary
air and assure complete combustion in these sources. Consequently, implementing OSC in utility
boilers is expected to elicit little effect on incremental CO emissions. This conclusion is cer-
tainly borne out by the representative data presented in Table 6-7.
Flue Gas Recirculation
The use of flue gas recirculation (FGR) for NO control has, in practice, been restricted
X
to gas- and oil-fired units. Tests have shown FGR to be impractical for use in coal-fired equipment
(Reference 6-14). This is so because, as discussed in Section 4.2, the technique is ineffective in
reducing fuel NO^ production, the predominant source of NO in coal firing. When FGR is implemented,
10 to 30 percent of the total burner gas flow is recycled flue gas from the boiler exhaust. Further
FGR increases can cause flame instability due to reduced flame temperatures and oxygen availability.
6-26
-------
Theoretically, FGR can lead to Increased CO emissions, but unacceptable flame instabilities usually
occur before the onset of CO or smoke production. Thus, as Table 6-7 shows, the use of FGR has not
caused increased CO emissions. On the contrary, CO emissions have generally decreased.
Load Reduction
Since load reduction in steam generators necessitates increased excess air levels to maintain
good furnace air/fuel mixing and steam temperature control, increased CO emissions using this NO
reduction technique are not expected. In addition, the increased combustion gas residence time
afforded under reduced load would tend to facilitate complete CO burnout. As Table 6-7 illustrates,
CO emissions remain relatively unchanged with reduced load.
6.2.1.2 Industrial Boilers
The bulk of the data on incremental CO emissions due to NO controls applied to industrial
X
boilers was obtained in a recently completed field test program (References 6-15 and 6-16). In this
study, CO emissions were reported for both baseline and for low-NO firing. Baseline emissions were
recorded with the boiler operating at 80 percent of rated capacity under normal (or as-found) con-
ditions. Low-NO testing was implemented until CO emission levels reached 100 to 200 ppm, then it
was curtailed.
The data obtained during this study are summarized in Table 6-8. As indicated in the table,
baseline CO emissions for industrial boilers are generally insignificant. However, the application
of NO combustion controls in most cases adversely affected CO levels because each control was im-
plemented until CO levels became unacceptable.
Low Excess Air
As noted for utility boilers above, CO emissions from industrial boilers are also adversely
affected by excess air levels. As observed in the field study (References 6-15, 6-16). Table 6-8
illustrates that CO emissions from gas- and oil-fired boilers can be significantly increased when
excess oxygen is reduced 20 to 50 percent. Coal-fired boilers showed lower incremental CO emission
increases.
Off-Stoichiometric Combustion
Two methods were used in the industrial boiler study to effect OSC: overfire air and burners
out of service. In these tests baseline CO emissions were always low. Combustion staging by both
methods generally resulted in unchanged to slightly increased CO emissions.
6-27
-------
TABLE 6-8. EFFECTS OF NOX CONTROLS ON CO
EMISSIONS FROM INDUSTRIAL BOILERS
(References 6-15, 6-16)
NO Control
rt
Low Excess Air
Off-Stoichiometric
Combustion
• Overfire Air
Fuel
Natural Gas
Distillate Oil
Residual Oil
Coal
Natural Gas
Distillate Oil
Residual Oil
Coal
CO Emissions (ppm)a
Baseline
10
0
0
0
50
47
90
0
0
0
0
0
0
25
70
0
0
25
10
10
0
0
0
0
0
N0¥ Control
A
10
0
11
900
129
485
150
17
45
100
9
28
205
20
60
0
22
25
10
20
0
0
30
80
49
3X 02, dry basis.
6-28
-------
TABLE 6-8. Concluded
N0y Control
A
Of f-Stoi chi ometri c
Combustion (Concluded)
• Burners Out of
Service
Flue Gas Recirculation
Variable Air Preheat
Load Reduction
Fuel
Natural Gas
Residual Oil
Natural Gas
Residual Oil
Natural Gas
Residual Oil
Coal
Natural Gas
Distillate Oil
Residual Oil
Coal
CO Emissions (ppm)a
Baseline
10
0
0
10
0
0
10
10
0
0
10
0
322
0
0
0
0
0
50
0
0
0
0
0
NO Control
A
10
0
43
20
0
10
0
75
0
0
0
30
320
0
0
10
0
0
30
0
9
0
0
0
,, dry basis.
6-29
-------
Flue Gas Recirculation
The data in Table 6-8 show that FGR has little effect on CO emissions. This conclusion sub-
stantiates what was noted in the utility boiler testing discussed previously (Section 6.2.1.1).
Variable Air Preheat
As for FGR, the data in Table 6-8 illustrate that varying combustion air temperature has
almost no effect on CO emissions. This suggests that effects of peak flame temperature on CO emis-
sions were also insignificant.
Load Reduction
During the cited industrial boiler field test program, load reduction experiments were
performed with the boiler controls on automatic. Therefore, excess air levels increased when boiler
load was reduced. As a consequence, CO emissions remained unchanged, or decreased slightly as load
was reduced.
6.2.1.3 Internal Combustion Engines
As discussed in Section 4.2, the most common NO reduction techniques applied to 1C engines
include derating, ignition retard, altering air/fuel (A/F) ratios, reducing manifold air temperatures
(MAT), and water injection. The effects of each of these NO controls on engine CO emission levels
X
are summarized in Table 6-9 (Reference 6-17).
As indicated, baseline CO emissions from two-cycle engines are generally lower than those
from four-cycle engines. However, derating two-cycle engines increased CO emissions 50 to 100 per-
cent, while derating four-cycle engines actually gave a 60 to 100 percent decrease in CO levels.
Retarding ignition generally caused increased CO output for all engines. This is somewhat
expected since retarding ignition decreased both peak combustion temperature and combustion gas res-
idence time. Both increasing A/F ratios and reducing MAT had little effect on CO levels. However,
decreasing A/F caused 50 to 100 percent increases in CO emissions. Water injection did not affect
CO emissions from gas and dual fuel engines, but increased diesel engine CO emissions by 60 to
130 percent.
6.2.1.4 Gas Turbines
The effects of the commonly implemented NO control techniques on CO emissions from gas tur-
bines are summarized in Table 6-10. From the table, it is apparent that reducing turbine load
6-30
-------
TABLE 6-9. REPRESENTATIVE EFFECTS OF NOX CONTROLS ON CO EMISSIONS FROM 1C ENGINES
(Reference 6-17)
Fuel
Natural Gas
Diesel
Dual Fuel
Engine Type
2-cycle
4-cycle
2-cycle
4-cycle
2-cycle
4-cycle
Baseline
Emissions
(ng/J)
15 - 40
75 - 3350
72 - 325
114 - 546
165
200 - 670
NO Control CO Emissions (ng/J)
Derate
40 - 94
54 - 150
89
100 - 180
244
289
Retard
Ignition
36 - 45
80 - 1000
140 - 628
260 - 654
244 - 267
679 - 1070
Increase
A/F
29 - 31
a
439
288
Decrease
A/F
117
675
244
296
Reduce
MAT
29 - 45
131
71
142 - 550
67
632
Water
Injection
194
464
460 - 606
503 - 507
denotes no data reported.
-------
TABLE 6-10. REPRESENTATIVE EFFECTS OF NOX CONTROLS ON CO
EMISSIONS FROM GAS TURBINES
(Reference 6-18)
NO Control
X
Load Reduction
Lean Primary Zone
Air Blast/
Piloted Air Blast
Water Injection
Fuel
Natural Gas
Kerosene
Diesel
Natural Gas
Kerosene
Diesel
Kerosene
Diesel
Natural Gas
Diesel
CO Emissions (ppm)a
Baseline
21
102
981
90
63
53
162
102
102
53
195
969
53
147
252
99
135
93
NO Control
A
357
708
1359
285
441
744
900
51
96
99
59
no
36
1134
1512
144
162
30
3% 02, dry basis. Baseline emissions at full load. NOX control emissions
at idle for load reduction; at full load for other NOX controls.
6-32
-------
causes dramatic increases in CO production. This results because gas turbines are typically designed
to operate at optimum efficiency at full load. Under full load, combustion efficiencies in excess
of 99 percent are common. However, combustion efficiency drops to 90 or 95 percent under idle
or low power conditions, because firing temperature and fuel/air ratios are reduced at the lower
load. The partially combusted gases are generated by the incoming dilution air and CO emissions in-
crease significantly.
The other dry N0x control techniques for gas turbines, notably leaning the primary zone and
air blast (or air-assist atomization), generally reduce CO levels. The additional air introduced
into the combustor when applying these techniques allows more complete fuel combustion. Thus,
as shown in Table 6-10, CO emissions decrease.
Wet control techniques such as water injection tend to quench combustion and give lower com-
bustor temperatures. This can lead to incomplete combustion and increased CO levels. Table 6-10
shows that, indeed, CO emissions increase when water injection is implemented.
6.2.1.5 Summary
In summary, except for lowering excess air levels, the available data indicate that NO
combustion modifications have little effect on CO emissions from boilers. Low excess air causes CO
emissions increases in boilers. Most NO controls increase CO emissions from 1C engines 50 to 100
X
percent. In contrast, only load reduction and water injection cause CO increases in gas turbines.
Dry controls actually decrease CO levels from these sources.
It is clear, therefore, that certain NO combustion controls can exacerbate CO emission
problems from stationary combustion sources. However, this should cause only minor environmental
concern. Since stationary combustion produces only about 1 percent of the total nationwide CO bur-
den, slight increases in CO emissions due to NOV controls in these sources should have negligible
X
impact.
6-2.2 Hydrocarbon Emissions
Hydrocarbon (HC) emissions from combustion sources are of environmental concern because of
their role in the atmospheric reactions leading to photochemical smog. The terms reactive hydro-
carbons, and nonmethane hydrocarbons have been applied to this pollutant class, which includes es-
sentially all vapor phase organic compounds emitted from a combustion source.
Stationary combustion sources are only minor contributors to ambient HC levels, accounting
for only about 1 percent of the total nationwide HC emissions (Reference 6-19). Nevertheless, the
6-33
-------
possibility of increased stationary source HC emissions due to N0x combustion controls is of defi-
nite concern. Like CO emissions, as discussed in the previous subsection, HC emissions arise in
combustion source exhaust gases because of incomplete combustion. The imposition of certain N0x com-
bustion modification controls can result in decreased combustion efficiency and thereby increase HC
levels.
Three general equipment classes are considered in the following discussion: boilers, inter-
nal combustion engines, and gas turbines.
6.2.2.1 Boilers
Field test programs studying the effectiveness of NO controls often monitor flue gas HC
X
emissions as a supplementary measure of boiler efficiency. Therefore, some data on the effect of
these controls on HC emissions are available.
Two recent test programs on utility boilers routinely measured flue gas HC (References 6-11,
6-12). However, in virtually all tests, both baseline and low-NO emissions were less than 1 ppm
(or below the detection limit of the available monitoring instrument). Thus, it was concluded that
HC emissions are relatively unaffected by imposing preferred NO combustion controls on large
X
utility boilers.
A recent field test program investigating NO controls applied to industrial boilers reported
more comprehensive data (References 6-15, 6-16). These data are summarized in Table 6-11, and show
that the use of NO combustion controls generally does not affect flue gas HC levels. Some tests show
a slight increase in HC emissions, yet others indicate slight reductions. Based on these data, it
seems fair to conclude that HC emissions from boilers are virtually unaffected when implementing NO
combustion controls. However, this conclusion is not altogether unexpected. The presence of unburned
HC in flue gases implies poor boiler operating efficiency; NO controls which significantly decrease
X
efficiency have found little acceptance.
6.2.2.2 Internal Combustion Engines
In contrast to boiler behavior, the use of NO combustion controls on 1C engines can have
X
significant effects on HC emissions. Different NO reduction techniques elicit different effects.
As shown in Figure 6-2, derating causes HC emissions to increase. This increase becomes
more pronounced as load is reduced. Derating, in general, causes a 20 to 130 percent increase in
HC emissions.
6-34
-------
TABLE 6-11. REPRESENTATIVE EFFECTS OF NOX CONTROLS ON VAPOR
PHASE HYDROCARBON EMISSIONS FROM INDUSTRIAL
BOILERS (References 6-15, 6-16)
N0¥ Control
A
Low Excess Air
Load Reduction
Of f-Stoi chi ometri c
Combustion
• Overfire Air
• Burners Out of Service
Flue Gas Recirculation
Variable Air Preheat
Fuel
Natural Gas
Distillate Oil
Residual Oil
Coal
Natural Gas
Residual Oil
Natural Gas
Distillate Oil
Residual Oil
Natural Gas
Residual Oil
Residual Oil
Natural Gas
Residual Oil
HC Emissions (ppm)a
Baseline
42
10
17
7
. 3
8
35
11
21
42
17
7
8
5
0
0
0
12
35
0
10
15
35
N0¥ Control
A
34
0
13
8
9
13
25
18
7
45
18
5
8
0
0
0
0
14
15
0
0
13
25
3% 02> dry basis.
6-35
-------
20
O 2 cycle, blower scavenged
Q 2 cycle, turbocharged
& 4 cycle, naturally aspirated
^4 cycle, turbocharged
G Natural gas
DF Dual fuel
D Diesel
40
50
60
Figure 6-2.
30
% Derated
Effect of derating on 1C engine HC emissions (Reference 6-17),
1000 T
20
Degree of retard
Figure 6-3. Effect of retarding ignition on 1C engine
HC emissions (Reference 6-17).
6-36
-------
Figure 6-3 shows the effect of Ignition retard on residual HC emissions. In contrast to the
effects of engine derating, ignition retard tends to decrease slightly or not affect emissions of
HC. However, in cases where retarding Ignition initially reduces HC emissions, increasing the degree
of ignition retard seems to have little further effect. The data 1n the figure Indicate that HC
emissions decrease on the average of 30 percent when Ignition 1s retarded 3 to 8 degrees.
Changing the air-to-fuel (A/F) ratio, decreasing manifold air temperature (MAT) and water
injection result in increased HC emissions. As shown in Figure 6-4, both increasing and decreasing
the A/F ratio by 10 percent increases HC levels 20 to 65 percent. The larger percentage increases
occur in engines with high baseline emissions. Figure 6-5 shows analogous effects when MAT is de-
creased. Decreasing MAT 10 to 20K (20 to 40F) increases HC emissions 5 to 50 percent. HC levels
increase as MAT is further reduced. Turbocharged engines exhibit the largest percentage emissions
increase. Water injection also increases HC emissions from 1C engines regardless of the baseline
HC level, as shown in Figure 6-6. Average increases of 16 to 25 percent have been experienced for
water/fuel (W/F) ratios of 0.1 to 0.25.
In summary, derating, changing the A/F ratio, decreasing MAT, and water injection tend to sig-
nificantly increase HC emissions from 1C engines. Retarding ignition has little effect. Derating,
decreasing MAT, increasing the A/F ratio, and water injection all lower combustion temperatures.
Decreasing the A/F ratio reduces combustion Op availability. Both of these effects tend to lead to
incomplete combustion, which would increase HC emissions. The unchanged or slightly decreased HC
emissions with ignition retard is a somewhat unexpected result. The combustion conditions resulting
from retarded ignition (decreased combustion temperatures and residence times) would be expected
to give rise to increased HC levels. The reason this does not occur is unclear at this time.
6.2.2.3 Gas Turbines
Data on incremental HC emissions from NO combustion controls applied to stationary gas tur-
X
bines are quite limited. However, sufficient data are available to allow tentative conclusions to be
formed. HC emissions, like CO emissions, increase significantly with load reduction in gas turbines.
As shown in Table 6-12, measured HC emissions at full load fall in the 3 to 50 ppm range. Idle fir-
ing, with attendant reduced combustion efficiency, increases these levels to the 30 to 230 ppm range.
The effects of other dry NO controls applied to gas turbines are mixed. As Table 6-12 shows,
staged fuel injection and air assist atomization, or air blast, increase HC emissions. In contrast,
leaning the primary zone tends to decrease HC levels. Increased combustion efficiency due to higher
combustion temperatures tends to support this latter observation.
6-37
-------
Q 2 cycle, blower scavenged
£T] 2 cycle, turbocharged
A 4 cycle, naturally aspirated
^ 4 cycle, turbocharged
G Natural gas
DF Dual fuel
D Diesel
20
-30
-20
-10 0 10
Percentage change in A/F ratio
Figure 6-4. Effect of air-to-fuel ratio on 1C engine
HC emissions (Reference 6-17).
6-38
-------
O 2 cycle, blower scavenged
Q 2 cycle, turbocharged
A 4 cycle, naturally aspirated
^ 4 cycle, turbocharged
G Natural gas
DF Dual fuel
D Diesel
20 30 40
Decrease in MAT (°F)
60
Figure 6-5. Effect of decreased manifold air temperature on
1C engine HC emissions (Reference 6-17).
1000
DF
-3
-^
CD
£ 100
DF
0.2
Figure 6-6. Effect of water injection on 1C engine
HC emissions (Reference 6-17).
6-39
-------
TABLE 6-12. SUMMARY OF THE EFFECTS OF NOX CONTROLS ON VAPOR PHASE
HYDROCARBON EMISSIONS FROM GAS TURBINES
(Reference 6-18)
NOX Control
Load Reduction
(
Air Blast
Staged Fuel Injection
Lean Primary Zone
Water Injection
Fuel
Natural Gas
Diesel Fuel
Kerosene
Jet-A
Jet-A
Natural Gas
Diesel Fuel
Kerosene
Natural Gas
Diesel Fuel
HC Emissions (ppm)a
Baseline
13
13
53
3
36
30
18
27
18
9
18
9
33
30
3
27
234
141
36
24
NOX Control
74
230
107
30
126
93
96
111
41
11
1215
24
9-12
12
7
12
372
246
27
12
Comment
Baseline at full
load; NOX
control at idle
Idle
Full load
Idle
Full load
Full load
W/F = 0.5
a3% 02, dry basis.
6-40
-------
The effects of applying wet N0x controls on HC emissions are also mixed. As indicated in
Table 6-12, with water injection at a water-to-fuel (W/F) weight ratio of 0.5, HC emissions increased
for turbines having high baseline HC emissions, but decreased for turbines which emitted low base-
line HC levels.
6.2.2.4 Summary
In summary, it can be concluded that incremental hydrocarbon emissions are of little concern
when applying N0x combustion modification controls to boilers. In these instances HC emissions are
either unaffected, or actually decrease, when N0x controls are implemented. Incremental HC emissions
from stationary 1C engines and gas turbines could be of some concern. However, these should have
little environmental impact because the HC emissions from these equipment classes are far less than
from, for example, mobile sources, and contribute minimally to the overall atmospheric burden.
6.2.3 Particulate Emissions
Although gas-fired units produce negligible amounts of particulates, oil- and coal-fired
stationary sources currently emit approximately 28 percent of the nationwide particulate and smoke
(Reference 6-19). Potential adverse effects on these particulate emissions from NO combustion con-
trols could therefore have significant environmental impact.
The physical characteristics of particulates from oil- and coal-fired boilers can vary sig-
nificantly. Particulate emissions from oil combustion can be composed of soot (condensed organic
matter), cenospheres (hollow char particles), and ash (incombustible mineral matter). Coal particu-
late emissions are largely ash, occasionally containing some unburned carbonaceous residue. Although
the distinctions between oil and coal particulate are rarely made in published data, they can be im-
portant for several reasons. For one thing, the composition of emitted particulate can have a large
bearing on its size distribution. And, because most particulate controls collect large particles
much more efficiently than fine particles, size is a key factor in determining how much particulate
can be collected. In addition, as discussed in Section 6.2.4, emissions of certain trace metals are
highly dependent on particle size distribution. Also, as discussed in Section 6.2.5, sulfate pro-
duction can be significantly affected by particle size distribution and the availability of catalytic
surfaces. Finally, as discussed in Section 6.2.6, polycyclic organic matter (POM) emissions from
combustion sources occur largely as solid phase carbonaceous residue. Thus, the presence of high
soot emissions or emissions of flyash with high carbon content would indicate the possibility of
high POM emissions.
6-41
-------
The formation of participates in a combustion source is intimately related to combustion
aerodynamics, the mechanisms of fuel/air mixing, and the effects of these factors on combustion gas
temperature-time history. Of course, these are also the parameters which control N0x formation.
For example, the effects of burner swirl on N0x production were briefly discussed in Section 4.2.
However, swirl is also an important factor in determining particulate emission levels from a com-
bustor. As Figure 6-7 illustrates, there is generally an optimum value of swirl for a given com-
bustion system (Reference 6-20). Burner swirl can also influence emitted particle size distribu-
tions. Low swirl values tend to produce soot in the 10 to 40 ym range. Increasing swirl decreases
formation of these large particles, but overswirling increases the production of submicron soot par-
ticles and reduces the extent of burnout of the largest particles.
Unfortunately the optimum conditions for reducing particulate formation (intense, high tem-
perature flames as produced by high turbulence and rapid fuel/air mixing), are not the conditions
for suppressing NO formation. Therefore, most attempts to produce low-NO combustion designs have
been compromised by the need to limit formation of particulates. This compromise has generally
produced designs which maintain a well controlled, cool flame, while still providing sufficient gas
residence time to completely burn carbon containing particles.
The NO combustion controls currently receiving the most widespread application in boilers
X
are low excess air, off-stoichiometric combustion (OSC), flue gas recirculation (for gas and oil), and
load reduction or enlarged firebox. As briefly discussed in Section 6.1, the altered combustion
conditions resulting from these modifications can be expected to influence emitted particulate load
and size distribution.
Since smoke and particulate emissions tend to increase as available oxygen is reduced
(soot emissions increase and ash particles contain more carbon), the degree to which excess air
can be lowered to control NO is usually limited by the appearance of smoke in oil- and coal-fired
A
units. Of course, the extent to which excess air can be limited depends on equipment type and de-
sign. Many modern burners can operate on as little as 3 to 5 percent excess air.
Similarly, the degree to which OSC can be employed is frequently limited by the degree to
which the primary flame zone can be stably operated fuel rich, how well the second stage air mixes
with primary stage combustion products, and the residence time for combustion in the second stage.
Soot and carbon particles formed in the fuel-rich primary stage tend to resist complete combustion
downstream of that stage.
6-42
-------
1.0
0.8
Solids
Burden
0.6
I by wt
of fuel
0.4
0.2
0
4% 0
_L
J_
0.6 0.7 0.8 0.9
Tangent of Median Air Angle
1.0
Figure 6-7. Effect of combustion air swirl on solid emissions
with oil combustion (Reference 6-20).
6-43
-------
Flue gas recirculafion on oil-fired units can decrease participate emissions by providing more
intimate mixing. Kamo, et al., (Reference 6-21) have demonstrated that recirculation rates of 40 to
50 percent on a heater-sized, oil-fired furnace reduced the smoke number significantly.
Load reduction on existing units and use of enlarged fireboxes on new units cause reduced
flame temperatures through lowered volumetric heat release rates. Although this could cause in-
creased production of particulates, the longer furnace residence times accompanying reduced load
offset this effect by providing more time for complete combustion.
»
Few data from actual field tests exist on the effect of NO combustion controls on particulate
emissions. Even less data exist on particle size distribution effects. This is unfortunate be-
cause of the importance of size distribution in determining actual particulate emissions from sources
with particle controls. However, the data which have been reported are presented and discussed
below for utility boilers, industrial boilers, 1C engines, and gas turbines.
6.2.3.1 Utility Boilers
Published data on the effects of NO reduction techniques on particulate emissions from util-
X
ity boilers are scattered and insufficient for in-depth analysis. Table 6-13 summarizes the par-
ticulate emissions data obtained during two recent field test programs which studied coal-fired
utility boilers (References 6-11 and 6-12). During these studies, particulate measurements were
recorded under baseline and low-NO conditions. Since these NO conditions were generally produced
by a combination of low excess air and staged combustion, the individual effect of each technique
on particulate emissions cannot be determined. Nevertheless, the data do show that particulate
emissions are relatively unaffected by "low-NO " firing in front wall and horizontally opposed fired
X
boilers. Tangentially-fired boilers, on the other hand, exhibit slightly increased particulate
emissions under "low-NO " conditions.
X
The effects of low-NO firing on carbon (or combustible) content of the particulate are also
shown in Table 6-13. Although the data are quite scattered, it appears that carbon losses increase
for front wall and horizontally opposed firing under low-NO conditions, but decrease slightly for
tangential firing. However, the changes are small and may not be significant.
The effects of "low-NO " conditions on particle size distribution have also been investigated
to a limited extent (Reference 6-11). The data from a study of particle size distribution in three
boilers are summarized in Table 6-14. As the table shows, no significant changes were noted in two
of the boilers, both of which were tangentially fired. In the third, a horizontally opposed boiler,
6-44
-------
TABLE 6-13. EFFECTS OF NOx CONTROLS ON PARTICULATE EMISSIONS FROM
COAL-FIRED UTILITY BOILERS (References 6-11, 6-12)
I
Ul
Firing Mode
Front Wall
Horizontally
Opposed
Tangential
Part icul ate Emissions (yg/J)
Baseline
2.00 - 3.39
1.30 - 1.65
3.29 - 3.83
0.86 - 2.21
1.08 - 1.84
Low NOV
A
1.65 - 2.42
1.34 - 1.78
2.40 - 3.60
2.36 - 2.40
1.23 - 2.95
% Carbon on Parti cul ate
Baseline
5.90 - 6.29
2.8 - 5.5
0.53 - 0.69
24.2 - 25.8
0.92 - 1.98
Low NOX
8.46 - 12.4
6.73 - 11.82
0.18 - 0.46
14.8 - 18.8
0.8 - 1.53
-------
TABLE 6-14. EFFECTS OF NOX CONTROLS ON EMITTED PARTICLE SIZE DISTRIBUTION
FROM COAL-FIRED UTILITY BOILERS
(Reference 6-11)
Equipment Type:
Firing Mode
Tangential
Tangential
Horizontally
Opposed
Firing Condition
Baseline
Low NOX
Baseline
Low NOX
Baseline
Low NOX
Average Weight Percent Particles of Size:
>2.5 pm
81.78
80.74
92.75
93.94
92.56
59.37
2.0 ym
9.12
8.91
2.97
1.89
2.59
10.77
1 .5 ym
2.01
2.28
0.70
0.59
0.62
4.08
1.0 ym
2.64
2.92
0.97
0.86
0.96
5.89
0.5 ym
2.92
3.25
1.21
1.10
1.45
9.55
<0.5 ym
1.55
1.88
1.38
1.61
1.84
10.36
CT1
I
-------
a distinct shift to smaller particles was noted. However, the author reported problems with the
sampling and particle sizing equipment in this test, so the data may not be significant.
6.2.3.2 Industrial Boilers
The recently completed industrial boiler field test program, previously cited in Sec-
tions 6.2.1.2 and 6.2.2.1 (Reference 6-16), also collected some particulate emissions and size
distribution data that show the effects of several NO combustion controls. These particulate emis-
sions data from several oil- and coal-fired boilers are summarized in Figure 6-8. The figure shows
changes in particulate emissions versus changes in NO emissions from baseline conditions as a
function of the applied NOX control.
As Figure 6-8 shows, the effects of N0x controls on particulate emissions are mixed. For
example, both forms of off-stoichiometric combustion tested increased particulate emissions by 15
to 90 percent, while flue gas recirculation increased emissions by 10 percent. In contrast, reducing
boiler load and air preheat decreased particulate emissions 45 and 65 percent, respectively. Fur-
thermore, low excess air firing generally lowered particle emissions 25 to 60 percent.
This last observation suggests that the effects of furnace gas velocity on flue gas particle
emissions were quite significant in these tests. Low excess air firing decreases boiler volumetric
gas flowrate, which in turn decreases combustion gas velocities. With lowered gas velocity, more
particulate would be collected as bottom ash, and more ash would deposit on internal boiler sur-
faces. Therefore, flue gas particulate load should decrease. Figure 6-7 suggests that this phenom-
enon is important and offsets the effects of decreased combustion completeness expected with lowered
excess air levels.
The above observations are in general agreement with those of Heap, et a!., (Reference 6-22)
who studied FGR and staged combustion applied to two oil-fired packaged boilers. They found that
smoke emissions increased slightly when both FGR and staged combustion were applied.
Cato, et al., (Reference 6-16) also reported some very limited particle size distribution
data, shown in Figure 6-9. This figure shows that, in a distillate oil-fired boiler,.as excess
air levels are lowered, the emitted particle size distribution shifts slightly to larger sizes. A
more pronounced shift to larger particle sizes was observed with reduced load in a residual oil-
fired boiler. However, these data are much too limited to allow any definite conclusions to be
made regarding the effects of combustion modifications on flue gas particle size distribution.
6-47
-------
Combustion Modification Method
O Air temp, reduction" O Staged air
Q Reduced firing rate O Burner tuneup
^ Flue gas recirc. <£> Burner-out-of-service
Reduced excess air
t
TD
•r-
X
O
QJ
0)
O
•r—
ns
O
c
tu
01
C
O
O
Q •
J.......-.......-.....-.-.........-...-.I...-.....-.-.-.-....
lil»^^^^^^^^^^^^^^^
Best quadrant x:x:x:::x:x|
- +40
- +30
• +20
. +10
0
- -10
A O
•0 C
O
- -30
- -40
0
Worst quadrant
1 Q
+100
- «- Change in particulates, % -> +
Figure 6-8. Effect of NOX controls on solid
particulate emissions from in-
dustrial boilers (Reference 6-16)
6-48
-------
TOO
<7I
10
-a
o>
t- v>
B l^
o •"
IJ .10 r~
-------
6.2.3.3 Internal Combustion Engines
Because it is quite difficult, time consuming, and expensive to measure particulate emissions
from 1C engines directly, virtually no data are available on particulate emission rates from this
equipment class. Instead, exhaust gas opacity readings have been used as a measure of the particu-
late emissions. These readings effectively measure the particulate since a relationship between
visible smoke and particulate mass emissions has been established for medium power diesel engines
(References 6-23 and 6-24). Therefore, 1C engine smoke emissions are generally reported as per-
cent plume opacity, or as Bosch or Bacharach smoke spot numbers.
The plumes from most larger bore engines are nearly invisible when the engine is operating
at steady-state. However, applying NO combustion controls can significantly affect smoke emissions.
Figure 6-10 shows the relationship between smoke emissions and NO reduction as a function of NO
X X
control for those engines where data were reported on both pollutants. As the figure shows, NO
controls (other than derating) generally increase smoke emissions, while derating decreases smoke
levels. Ignition retard and exhaust gas recirculation (EGR) cause the most significant increases
in smoke level.
Since NO controls which caused smoke levels to exceed 10 percent opacity were considered
X
unacceptable in the tests summarized in Figure 6-10, none of the data points for controlled engines
are above this value. However, the effect of progressively applying ignition retard and EGR on
smoke emissions is best demonstrated by data which include higher smoke levels. Such data are
presented in Table 6-15 for two-cycle diesel engines, and clearly show that smoke emissions in-
crease progressively as percentage EGR or degree of retard is increased.
6.2.3.4 Gas Turbines
The data on particulate emissions from gas turbines resulting from applied NO controls are
X
also very limited. However, the available data indicate that incremental particulate emissions from
N0x controls follow trends similar to those for incremental CO and hydrocarbon emissions.
Figure 6-11 shows the effect of turbine load on particle emissions. Like CO and HC emissions
(as discussed in Sections 6.2.1 and 6.2.2), particle emissions increase as turbine load is reduced.
As the figure shows, particulate emission increases average 40 percent when turbine load is de-
creased .to 30 percent of rated capacity.
6-50
-------
en
i
en
01
_Q
o
CL
-C
u
-------
TABLE 6-15. RELATIONSHIP BETWEEN SMOKE,
EGR, AND RETARD
(Reference 6-17)
Engine Type
2-cycle, Blower
Scavenged Diesel
2-cycle,
Turbocharged Diesel
Control3
None
10% EGR
20% EGR
39% EGR
4° advance
None
4° retard
None
4.9% EGR
8.4% EGR
12.1% EGR
Opacity, %
4.7
12
27.5
59
2.7
4.6
10
7.5
10.0
11.5
14.8
All EGR data based on hot EGR.
"'injection advance is not a control; data
included to show trend.
6-52
-------
30
25
CD
t/1
o
•r—
in
C/)
QJ
O)
•(->
10
3
O
20
15
(O
o.
10
T
X Oil-kerosene mixture
Q Kerosene
ANo. 2 oil
ONo. 2 oil
4
i
*
i i i i i i i i i
0 10 20 30 40 50 60 70 80 90 100
% of gas turbine peak load
Figure 6-11. Gas turbine particulate emissions as a
function of load (Reference 6-25).
6-53
-------
The effect of water injection on particle emissions seems to be related to the specific in-
jection method used (Reference 6-18). Some tests show smoke level reduction of 1.5 to 1.75 smoke
spot numbers when water injection is used. Other tests, however, indicate increased participate
emissions with water injection at peak load.
6.2.3.5 Summary
In summary, the effects of NO combustion controls on particulate emissions from stationary
A
sources have been insufficiently studied. The available data are, in general, too limited to form
firm conclusions. However, some tentative observations are possible:
• Only off-stoichiometric combustion seems to adversely affect parti oil ate emissions from
boilers
• All NO controls except derating cause increased smoke levels from 1C engines
• Load reduction increases gas turbine particulate emissions
More substantial data — particularly on particle size distribution —are needed to fully assess the
effects that NO controls have on particulate emissions.
6.2.4 Trace Metals
Emissions of trace metals are a concern for combustion sources firing coal and residual oil.
They are a lesser problem in sources firing distillate fuels since trace metal concentrations in
distillate oils are generally much lower than those in residual oils. Trace metals from stationary
sources are emitted to the atmosphere with the flue gas either as a vapor or condensed on particu-
late. The quantity of any given metal emitted, in general, depends on:
• Its concentration in the fuel
• The combustion conditions in the boiler
• The type of particulate control device used, and its collection efficiency as a function
of particle size
t The physical and chemical properties of the element itself
For present purposes, the trace metal composition of the fuel is considered a given quantity,
not subject to manipulation. Therefore although composition has a controlling effect on the abso-
lute trace metal emissions from a combustion source, it is not considered as a factor to explain
the effects N0x controls have on incremental trace metal emissions.
6-54
-------
It has become widely recognized that some trace metals tend to concentrate In certain waste
particle streams from a boiler (bottom ash, collector ash, flue gas participate), while others do
not (References 6-26 through 6-32). Based on this phenomenon, three classes of partitioning metals
have been defined (Reference 6-26).
• Class I: 20 metals (Al, Ba, Ca, Ce, Co, Eu, Fe, Hf, K, La, Mg, Mn, Rb, Sc, Si, Sm, Sr,
Ta, Th, and Ti). These are found in the bottom ash or slag, the particle collector in-
let flyash, and the collector outlet flyash in approximately the same mass concentrations.
• Class II: 9 metals (As, Cd, Cu, Ga, Pb, Sb, Se, Sn, and Zn). These are not usually found
in bottom ash or slag, but are found in flyash. Mass concentrations in particle collector
inlet flyash are generally less than in collector outlet flyash.
• Class III: Hg, and possibly Se. These are usually emitted as vapors in the flue gas.
Another set of elements (Cr, Cs, Na, Ni, U, and V) exhibits properties intermediate between Classes I
and II.
Other work has shown that the Class II metals, As, Cd, Pb, Sb, Se, and Zn, along with Ni,
Cr, and V become increasingly more concentrated in flyash particles as particle size decreases
(Reference 6-27). Cd, Pb, Ni, Sb, Se, Sn, V and Zn all appear to have a mass mean diameter (MMD)
of less than 1 ym in the atmosphere. The more common Class I metals, Fe, Al, and Si, have MMDs
of 2.5 to 7.0 urn (Reference 6-33).
The most logical explanation for this segregation behavior involves a volatilization-
condensation mechanism (Reference 6-26). In its simplest form, the argument says that Class I
metals have boiling points sufficiently high that they are not volatilized in the combustion zone.
Instead, they form a melt of relatively uniform concentration, which becomes both bottom ash or slag,
and flyash. Thus, Class I elements remain in a condensed phase throughout the boiler and show little
partitioning with particle size. By contrast, Class II metals have boiling points below peak com-
bustion temperatures, so they are volatilized in the combustion zone and do not become incorporated
in the slag. As combustion gases cool by traveling through the boiler, these elements either form
condensation nuclei or condense onto other available solid surfaces (predominantly Class I mineral
particles). Since the available surface area to mass ratio increases as particle size decreases,
the Class II elements concentrate in small particles. This partitioning mechanism is further sub-
stantiated by observations that certain Class II metals exhibit higher surface concentrations than
bulk concentrations in fine particles (Reference 6-34).
6-55
-------
This simple mechanism described above does not fully account for all experimental observa-
tions. For example, Ca and Cu behave as high boiling point metals, whereas Rb, Cs, and Mg behave
as volatile elements. Therefore, the volatilization-condensation mechanism has been extended as
follows (Reference 6-24):
• Trace elements in coal are present as aluminosilicates, sulfides, and organometallics
• On combustion, the aluminosilicates melt to form slag or bottom ash, and flyash
• In the reducing atmosphere during initial stages of combustion, metal sulfides are re-
duced to vapor phase metal; at the same time the organic matrix of organometallics
oxidizes, leaving volatilized metal
• Volatilized metals may themselves become oxidized to less volatile oxides
• As the combustion gas cools, these volatile species condense onto available solid sur-
faces, and concentrate in small particles
• Since slag and flue gas are in contact for only a short time, little volatile condensa-
tion in slag occurs
This extended mechanism is indirectly supported by the fact that Class I metals are largely geo-
chemical lithophiles (readily associated with aluminosilicate minerals), while Class II metals are
largely chalcophiles (readily incorporated into sulfide minerals).
In all mechanisms the Class III metals, Hg and to some extent Se, remain vaporized through
the stack and are emitted as flue gas vapor components. Some 90 percent of Hg emissions (Ref-
erence 6-35) and about 20 percent of Se emissions (Reference 6-26) are emitted as vapors.
Regardless of the exact mechanism for the trace metal partitioning phenomenon, the partition-
ing significantly influences trace metal emissions from combustion sources with particulate control
devices. All particle collection devices are more efficient at collecting large particles than
small particles. Since Class II metals in flyash occur in smaller particles than Class I metals,
a larger fraction of the Class II elements introduced into a boiler will be emitted'from sources
equipped with particulate control units.
This behavior is illustrated by recent trace metal emissions data from industrial boilers
(Reference 6-36). Figure 6-12 shows the concentration of several Class I metals measured in
particle samples from different points in a coal-fired industrial boiler. Figure 6-13 shows the
same profile for several Class II elements. As the partitioning theory predicts, the concentration
of Class I metals remains fairly constant throughout the boiler. On the other hand, flyash
6-56
-------
en
01
en
en
in
c.
o
c
OJ
o
c
o
u
c
0)
E
-------
10
5 -- Arsenic
o
c
o
(J
0
10
0
200
100
200
100
0
20
0
200
0
1,000
• Cadmium
- Copper
• Lead
2.5 -.Tin
100 --Zinc
500
Coal
X X Xx
10 • • Selenium
Vanadium
X X X X
Furnace
bottom
/ / / / s
Upstream
of
collector
In
collector
Downstream
of
col lector
^/ / /
y
Figure 6-13. Partitioning of Class II elements (Reference 6-36).
6-58
-------
concentrations of Class II elements increase toward the flue gas exit. The expected increase in
concentrations in the collector effluent ash over collector inlet ash and collected ash is quite
significant.
By understanding trace metal partitioning and concentration in fine particulate, it is pos-
sible to postulate the effects N0x combustion controls will have on incremental trace metal emissions.
Several NOX controls for boilers result in lowered peak flame temperatures (off-stoichiometric com-
bustion, flue gas recirculation, reduced air preheat, load reduction, and water injection). The
volatilization-condensation theory predicts that if the combustion temperature is reduced, less
Class II metal will initially volatilize, hence less will be available for subsequent condensation.
Under these conditions (lowered flame temperature), it is expected that less Class II metal (the
segregating trace metals discussed in Section 6.1) will be redistributed to small particulate.
Therefore, in boilers with-particulate controls, lowered volatile metal emissions should result.
Class I metal (the nonsegregating trace metals discussed in Section 6.1) emissions should remain
relatively unchanged.
Lowered local CL concentrations are also expected to affect segregating metal emissions from
boilers with particle controls. Lowered 02 availability decreases the possibility of volatile metal
oxidation to less volatile oxides. Under these conditions Class II metals should remain in the vapor
phase into the cooler sections of the boiler. More redistribution to small particles should occur
and emissions should increase. Again, nonsegregating metal emissions should be unaffected. This
behavior is expected when low excess air is implemented. Other combustion NO controls which de-
crease local Op concentrations (OSC and flue gas recirculation) also reduce peak flame temperature.
For these, the effect of lowered combustion temperature is expected to predominate.
The effect of NO combustion controls on segregating metal emissions from combustion sources
without particle collection devices should be marginal at best. Particle redistribution will not
affect mass emissions because all particulate produced is emitted from these sources. However, since
trace metal condensation on internal boiler surfaces undoubtedly occurs, conditions which decrease
the extent of Class II metal volatilization (lowered peak flame temperature) should cause a slight
increase in segregating metal emissions. Conversely, conditions which increase metal volatility
(low local Q2 concentrations) should cause slight decreases in volatile metal emissions.
No data currently exist to document the above speculations. However, such data should be
easy to obtain in forthcoming emissions assessment programs, if the effects of N0x controls are
studied in test matrices. Obtaining such data should be given relatively high priority since 8 of
the 20 most toxic elements in air are Class II metals (Reference 6-37). Changes in the emission
levels for these metals can have significant environmental impact.
6-59
-------
6.2.5 Sulfates
Ambient sulfate levels are a matter of increasing concern in regions with large numbers of
combustion sources firing sulfur-bearing coal and oil (notably, the northeast region of the U.S.).
Although the direct health effects of high ambient sulfate levels are currently unclear (Refer-
ences 6-38 and 6-39), high sulfate aerosol concentrations are known to decrease visibility and
aggravate acid precipitation phenomena.
Ambient sulfates are comprised of directly emitted sulfates (primary sulfates) and those de-
rived from the atmospheric oxidation of S02 (secondary sulfates). However, the relative contribu-
tion of each of these to ambient levels is presently unclear. Recent estimates indicate that pri-
mary sulfates comprise about 5 to 20 percent of the ambient sulfate on a regional basis (Refer-
ence 6-39). However, regional transport processes are extremely important in determining local
ambient levels, especially in the Northeast. Consequently, it is difficult to separate the effect
of secondary sulfate production from the effect of transported primary sulfate on a region's ambient
sulfate level.
Although the plume chemistry of secondary sulfate formation has not yet been fully described,
it is generally recognized that SCL can be oxidized to sulfate through the five mechanisms summarized
in Table 6-16. Of these, it is generally concluded that the first mechanism is of minor importance
(Reference 6-39). Similarly, the importance of mechanism 3 is thought to be minor when compared to
mechanisms 4 and 5.
The relative effects of mechanisms 2, 4, and 5 are currently unknown. Ambient vanadium
appears to be strongly related to ambient sulfate, even though vanadium is a high temperature SO-
oxidation catalyst and is ineffective at room temperature (Reference 6-41). Weaker correlations
exist between ambient sulfate and ambient iron and manganese. However, ambient sulfate does not
correlate with ambient N02 at all (Reference 6-39). These facts would seem to indicate that the
catalytic mechanisms are the more significant in producing secondary sulfates.
On the other hand, recent power plant plume measurements show that the conversion of SO- to
sulfate aerosol is essentially zero for the first two hours of plume residence time, but increases
quite rapidly thereafter (Reference 6-42). This could be due to solution pH limitations. It is
interesting, however, that this time compares quite favorably to the 20 to 90 minute residence
time required for the NO/NO ratio in a plume to reach an "equilibrium" value of about 0.5, as re-
X
ported by Gordon et al., (Reference 6-43). It is known that NO inhibits S0? oxidation (Reference
6-44) presumably by scavenging oxidizing agents (notably ozone). However work by Davis et al.,
(Reference 6-45) has attempted to suggest an even more intimate relationship between ML, NO, and
6-60
-------
TABLE 6-16. MECHANISMS THAT CONVERT SULFUR DIOXIDE TO SULFATES (Reference 6-40)
Mechanism
Overall Reaction
Factors on Which Sulfate
Formation Primarily Depends
1. Direct photo-
oxidation
Indirect photo-
oxidation
Air oxidation in
liquid droplets
4. Catalyzed oxidation
in liquid droplets
5. Catalyzed oxidation
on dry surfaces
SO,
SO
SO,
NH
light, oxygen
water
smog, water, NO
H2S04
2 organic oxidants,
hydroxyl radical (OH«)
M cr\
"2OU4
liquid water
3 "23
so:
en oxygen, liquid water ^ SQ=
2 heavy metal ions 4
en oxygen, particulate „ ^.n
S02 carbon, water ^ H2bU4
Sulfur dioxide concentration,
sunlight intensity
Sulfur dioxide concentration,
organic oxidant concentration,
OH, M)
Ammonia concentration, pH
Concentration of heavy metal
(V, Fe, Mn) ions, pH
Carbon particle concentration
(surface area)
-------
SOp oxidation. Existence of this relationship is coupled with in-plume production of ozone and the
appearance of an "ozone bulge" within the plume. In support, Levy and Spicer (Reference 6-46) con-
clude that, although Davis1 postulated reaction sequence is questionable, the possiblity of inter-
actions between NO photochemistry and sulfate production does exist and certainly deserves further
elucidation.
Regardless of the possible impact of secondary sulfate production on ambient sulfate levels,
it is clear that keeping primary sulfate emissions to a minimum is highly desirable. Since some
98 percent of the sulfur introduced into a combustion source generally appears in the flue gas, the
present discussion will assume that one has no control over total sulfur oxide emissions (the exis-
tence of fuel desulfurization and flue gas desulfurization techniques is ancillary). Therefore,
the focus here will be on ways to keep the SCL/SCU ratio at a minimum.
In the present discussion, primary sulfate emissions will be defined as all sulfate emitted
from the stack plus the amount produced in about the first half mile of plume travel. These sul-
fates may exist as either sulfuric acid (H^SO.) or as metal or ammonium sulfates (denoted here as
S07). The fraction of HpSO, (measured as SO,) in the sulfur oxides emitted from boilers ranges from
1 to 3 percent from coal-fired sources to 5 to 9 percent for oil-fired boilers (Reference 6-47).
SOT emission levels have not yet been clearly established, though it is thought that these at least
equal H2SO. emissions (Reference 6-48).
The precise mechanisms for the formation of sulfates in combustion systems are not completely
understood. However, it seems clear that two processes contribute to final flue gas sulfate levels.
The first is homogeneous S02 oxidation in the flame through the reaction:
S02 + 0 + M = S03 + M (6-1)
Although SO- is the thermodynamically favored product at high temperatures, it is currently thought
that some S03 is formed through Equation (6-1). Subsequent rapid gas quenching then freezes the sys-
tem into a nonequilibrium state. In any event, any SO, formed through this reaction will, under
flue gas conditions, combine with available water vapor to form vapor phase sulfuric acid. This
sulfuric acid will then either absorb or condense onto available particulate and be emitted as an
aerosol or, in the absence of sufficient particulate, as a vapor which condenses to acid mist as
soon as plume temperature drops below its acid dew point.
The second important sulfate formation mechanism is catalyzed heterogeneous S0? oxidation in
post-combustion regions by flue gas particulates and internal boiler deposits. Several potential
6-62
-------
oxidation catalysts exist in suspended and deposited flue gas particulate, including vanadium,
nickel, iron, manganese oxides, and carbon (soot). Vanadium pentoxlde (VgOg) is a well known
and quite effective oxidation catalyst in the 400 to 700°C temperature range. It is, in fact, used
in the contact process for the manufacture of sulfuric acid. However, Fe20, also catalyzes S0?
oxidation at 450 to 850C (Reference 6-49), and Mn02 is an effective catalyst from room temperature
to at least 340C (References 6-41, 6-50). Finally, Novakov (Reference 6-51) has recently shown
that even freshly generated soot and graphite particles convert S02 to SO,.
A third mechanism, usually considered to be of importance only in secondary sulfate formation,
deserves some comment here. This is mechanism 4 in Table 6-16, catalytic oxidation in solution.
Under normal conditions, the pH of near plume liquid droplets is low, approximately 3. At this pH,
SOy solubility is quite low, so solution chemistry normally contributes negligibly to primary sul-
fate levels in the near plume. However, if sufficient quantities of a basic specie, such as ammonia,
were present to neutralize these droplets, S02 solubility would increase dramatically, leading to
significant amounts of sulfate production through solution catalysis in the near plume. Consequently,
the use of post-combustion ammonia injection for NO control could possibly lead to significantly
increased primary sulfate emissions. Of course, much further work is needed in this area before any
conclusions can be substantiated.
It is important to note that each of the above mechanisms operates in a different region of
a boiler, because each has different temperature requirements. This fact is illustrated in Fig-
ure 6-14, which shows the relative importance of each mechanism as a function of temperature regime
and corresponding boiler region- In the flame zone, temperatures are high and sulfate is expected
to be formed by rapid homogeneous gas phase oxidation. This corresponds to curve A in the figure.
However, at somewhat lower temperatures, in the boiler's convective passes, homogeneous reaction
rates are too slow to contribute significantly to sulfate formation. At these temperatures, cataly-
tic mechanisms should be most important, as illustrated by curves B and B'. Curve C represents
solution chemistry and curve D represents indirect photo-oxidation (mechanism 2 of Table 6-16).
Both of these are normally of importance only in secondary sulfate production.
The relative importance of each mechanism in determining final sulfate levels is not presently
known. Thus, two curves, B and B', are shown in Figure 6-14. (The two curves also indicate that the
temperature range of importance is also uncertain.) However, it is currently thought that flyash/
soot catalysis is at least as important a mechanism in forming sulfate as the high temperature homoge-
neous mechanism. This view is indirectly supported by the fact that H2SO./S02 ratios from oil-fired
6-63
-------
en
i
en
O>
03
O
ro
-P
-Q
S-
fO
OJ
o
G
fO
4-J
.i.
O
CL
c
(D
o
OJ
0
I
Residence time (sec)
10
I
3600
I
Flame
Convection
name i lonvection i i I Far plume.
zone ""[ section *| stack*| Immediate plume *T ambient
Primary
sulfates
air
Secondary
k sulfates
High T, homogeneous
B1
Intermediate T,
dry gas-solid
heterogeneous
Photochemical
1900
175
Temperature, °C
Solution
chemistry
Figure 6-14. Sulfate formation regimes of importance (Reference 6-48).
-------
sources are higher than those from coal-fired sources. Residual oils generally contain more
vanadium and nickel than coal.
Based on the above, it is possible to speculate on the effects NO controls might have on
primary sulfate production. Since primary sulfate emissions are largely dependent on combustion gas
oxygen availability, boiler temperature-time history, and internal catalyst availability, combustion
modifications which alter these parameters should affect the amount of SCL converted to sulfate.
Reduced oxygen availability should definitely tend to decrease primary sulfate emissions.
Thus, N0x controls which result in decreased local oxygen availability (e.g., low excess air firing
and off-stoichiometric combustion) should result in lowered sulfate emission levels. In fact,
Archer, et al., (Reference 6-52) have shown, in pilot scale work on two-stage combustion, that SO,
levels leaving the first combustion stage can be reduced to essentially zero when this stage is
fired fuel rich.
The effects of boiler temperature time history on sulfate production are significantly more
difficult to sort out because of the lack of knowledge about in situ catalytic mechanisms and their
relative importance with respect to homogeneous SO,, oxidation. However, the effects of NO con-
C, X
trols on boiler temperature profile and the effect of temperature on oxidation catalyst availability
follow from the trace metal discussion presented in Section 6.2.4. Vanadium, nickel and their oxides,
which are active S02 oxidation catalysts, are also metals which partition to fine particulate, as dis-
cussed in Section 6.2.4. -Therefore, conditions which promote the redistribution of these metals to
accessible surfaces (e.g., boiler tubes and other internal boiler surfaces in addition to flue gas
particle surfaces) should promote increased sulfate production. Thus, as discussed in Section 6.2.4,
combustion conditions which facilitate volatilization-condensation and partitioning, such as high peak
flame temperatures, should promote S02 oxidation. Conversely, combustion controls which, for example,
lower peak flame temperatures, should decrease sulfate productions.
Based on the above, it is expected that combustion modifications which lower local 02 levels
(such as low excess air firing), which lower peak flame temperature (such as flue gas recirculation,
reduced air preheat, and water injection), or which do both (such as OSC), will decrease the amount
of S02 oxidized to sulfate. Of course, care must be taken when implementing any of these controls
not to stimulate excess particulate production. The catalytic effects of internally deposited soot
or flyash could overcome the beneficial effects of lower 02 concentration and reduced catalyst
repartitioning.
6-65
-------
Data confirming these conclusions, though sparse, do exist. Recent measurements have demon-
strated the expected dependence of sulfate emissions on boiler excess air levels. Bennett and Knapp
(Reference 6-53) have shown that particulate sulfate emissions increase with increasing boiler excess
02 in oil-fired power plants. Homolya, et al., (Reference 6-47) report a similar increase in sulfate
emissions as a percentage of total sulfur emissions with increasing excess 02 in coal-fired boilers.
Their data, shown in Figure 6-15, show a linear relationship between the sulfate fraction of emitted
sulfur and boiler excess CU-
Other data (Reference 6-54), shown in Table 6-17 also show that S03 emissions decrease when
OSC is used to control NO .
The situation in coal-fired boilers equipped with electrostatic precipitators (ESPs) for
particulate control deserves some further comment. It is well known that SO., (or more appropriately
sulfuric acid) serves to condition low resistivity flyash and improve ESP performance in collecting
these particles. Therefore, it is conceptually possible that a decrease in primary sulfate produc-
tion could give rise to increased particulate sulfate emissions. Though the phenomenon seems some-
what unlikely, further work on this question is definitely needed.
The problem of acid smut emissions, which is also related to sulfate formation, also deserves
some discussion here. Emissions of acid smut (large "globs" of highly acidic carbonaceous particu-
late) have been experienced recently in several residual oil-fired utility boilers in the U.S.
Acid smuts are extremely corrosive and their large size (up to lOOy) leads to fallout in the vicin-
ity of the power plant. They are thus of concern both for potential impact on both human health and
welfare. Acid smut emissions have been experienced for many years in Europe due to their practice
of firing heavy oil units at lower levels of excess air than was common in the U.S. (References 6-8
and 6-55 through 6-58).
Recently the problem has occurred when certain NO controls, notably off stoichiometric com-
bustion combined with low excess air, are implemented on residual oil-fired units. It also invar-
iably occurs in boilers which were originally designed to fire natural gas, but have been converted
to oil firing because of fuel availability problems.
The exact reasons for the appearance of acid smut emissions are not clearly understood.
However, it is clear that they are related to air heater design and the resulting final flue gas
temperature. Since natural gas contains very little1 sulfur, acid mist condensation in and down-
stream of the air heaters has never been a concern. Therefore, air heaters in gas-fired boilers
have been designed to give lower flue gas temperatures than corresponding air heaters in oil-fired
6-66
-------
-------
TABLE 6-17. S0¥ SUMMARY (Reference 6-54)
n
Baseline
LEA
OSC
02 (X)
Boiler
Exit
2.9
1.55
1.5
3.1
3.4
Stack
6.8
5.7
7.72
7.1
so2
S03
ppm Corrected to 3%
°2
944
948
1,000
Avg 974
1,010
968
Avg 989
28
13.5
35.9
Avg 25
14.0
13.9
Avg 14
6-68
-------
units. However, when these same gas-fired units are switched to oil firing, it is possible for
flue gas temperatures downstream of the air heater to approach the acid dew point. In the absence
of parti oil ate emissions, flue gas sulfuHc acid would then condense and reevaporate through the
ductwork and stack until ultimately emitted as a finely dispersed mist.
The appearance of acid smut emissions when implementing NO controls which enhance the pro-
duction of soot particles suggests the possible next step in the smut formation mechanism. In the
presence of sufficient particulate, flue gas sulfuric acid condenses onto particle surfaces in suf-
ficient amounts to cause particle agglomeration. Agglomerated particles then deposit onto ductwork
walls. These deposits continue to grow through further agglomeration until they become large enough
to spall off the wall. Thus, emissions of wet acidic "globs" or acid smut occur.
In light of the above, acid smut emissions have been viewed as a combined sulfate production
problem and particulate production problem. Attacks on the problem have included both reduction of
acid formation and/or condensation and suppression of carbon formation or agglomeration. Table 6-18
summarizes process modifications used or proposed in Europe and the U.S. (References 6-55 through
6-58). It appears that incremental emissions of acid smut can be suppressed if addressed during
control development. The potential for acid smut emissions should be considered when implementing
NO controls on heavy oil-fired boilers with preheaters and without particle collection devices.
In summary, the postulated, and in some cases demonstrated, effects of most NO combustion
X
controls on primary sulfates are to decrease emissions or leave them unchanged. However, since
there are insufficient data to fully substantiate any real conclusion, it seems appropriate to con-
sider incremental sulfate emissions due to NO combustion modifications of questionable concern,
A
except in the case of acid smuts and use of post-combustion ammonia injection. Because ammonia injec-
tion may significantly increase near plume sulfate production through solution chemistry, its effects
on residual sulfate should be considered of definite concern.
6.2.6 Organics
In the true sense, the class of organic compounds includes virtually all carbon-containing
compounds except carbon monoxide and carbon dioxide. In the present discussion, however, "organics"
will be used to describe only those species not included in the class of compounds referred to as
the criteria pollutant, "hydrocarbons". Therefore, with few exceptions, hydrocarbon emissions,
discussed in Section 6.2.2, will include essentially all organic compounds emitted in the vapor
phase at flue gas temperature. The remaining organic emissions, discussed here, are composed
6-69
-------
TABLE 6-18. SUMMARY OF PROCESS MODIFICATIONS TO REDUCE ACID SMUT FALLOUT
(References 6-55 through 6-58)
en
t
Principle
1. Suppress buildup
of acid smut
2. Prevent acid
condensation
3. Neutralize acid
smut
4. Suppress SO,
formation
5. Reduce carbon
emissions
6. Particle
collection
Candidate Techniques
Frequent or continuous
soot blow
Reduced air preheat
Additives: dolomite,
limestone, MgO, NH,
Reduced excess air
Reduced load
Reduced catalytic
activity of superheater
Reduced sulfur in fuel;
mixed distillate/resid.
firing
Increased excess air
Better firebox mixing
Fuel pretreatment to
remove heavy carbon
compounds
Cyclone, ESP or baghouse
Size Range Affected
Large particles
Large particles
Large and small
particles
Large and small
particles
Large and small
particles
Large and small
particles
Large and small
particles
Large and small
particles
Large and small
particles
Large and small
particles
Large and small
particles
Comments
Acid smuts emitted in smaller, dispers-
able, size range; successfully tested at
Eastern Utility; promising option
Reduced efficiency; possible smut buildup
in stack at reduced size range
Reduces (50%) but doesn't eliminate acid
emissions; additives increase particle
loading
Increased efficiency; increased carbon
and CO emissions; limited by NO control
techniques
Not cost effective
Additive coating is partially effective;
operational problems
Distillate availability uncertain
Reduced efficiency; increased S03
Limited by NOX controls
Effective but costly
-------
largely of compounds emitted from combustion sources 1n a condensed phase. These compounds can
almost exclusively be classed Into a group known variously as polycycllc organic matter (POM) or
polynuclear aromatic hydrocarbons (PNA or PAH). The following discussion, then, treats POM emis-
sions from stationary combustion sources and the effects of NOX controls on these emissions. In
addition, a discussion of nitrosamines is included 1n this subsection, since this class of com-
pounds is quite important from an environmental health standpoint and is not discussed elsewhere.
Although polycyclic organic matter can conceivably be formed in the combustion of any hydro-
carbon fuel, it is considered more of a problem when associated with soot (carbonaceous particulate)
emissions from coal and oil-fired combustion equipment. POM is especially prevalent in the emissions
from coal burning, because a large fraction of the volatile matter in coal (coal tar) is preexisting
POM.
Although the precise mechanism of POM formation in flames is complex and variable, it is pos-
sible to form a relatively clear picture of the overall reaction. In a reducing atmosphere, at tem-
peratures around 2.000K (conditions common in the center of flames) radical species of the form,
• • •
HC=CH and RCH=CH, can rapidly combine and form large polynuclear aromatic molecules through radical
chain propagation (References 6-2, 6-59). As combustion gas cools and chain propagation is quenched,
a variety of POM species can remain when combustion is incomplete. Upon further cooling, these
species condense and are emitted largely as soot or high carbon content particulate.
POM emissions have significant environmental impact because several species are highly car-
cinogenic (Reference 6-2). The fact that they generally exist as fine particulate (for reasons
similar to those presented in Section 6.2.4 to explain trace metal partitioning to fine particles)
makes them an even more serious health hazard.
It is important to again note that although POM formation is possible during methane combus-
tion, the formation of these large aromatic molecules is facilitated by the presence of higher
molecular weight radicals and C-hL. Thus, POM production is of only minor concern in gas-fired
systems, of some concern in oil-fired sources, and of greatest concern in coal-fired equipment.
Whatever the combustion source, it is clear that POM emissions should increase under conditions of
poor combustion efficiency. Since NO combustion controls can lead to inefficient combustion and
soot formation, if not carefully applied (especially low excess air and staged combustion), implemen-
tation of these controls can most certainly lead to increased POM formation.
Data to support this contention, however, are essentially nonexistent, largely because of the
difficulty of sampling flue gas streams for POM containing particles and of accurately assaying sam-
ples for individual POM species. A recent field test program on oil-fired industrial boilers
6-71
-------
was to include sampling for POM emissions (Reference 6-36), but sampling train and analytical
problems prevented useful data from being obtained. Thompson et al., recently reported the effects
of off-stoichiometric combustion and flue gas recirculation on POM emissions from a coal-fired
utility boiler (Reference 6-14). Their data, shown in Table 6-19, seem to indicate that POM emis-
sions do increase with two-stage combustion. However, they state that the sampling and laboratory
analysis procedures used in obtaining the data varied over the sample set. Thus, they conclude that
POM emissions are not significantly affected by firing mode. In a third study, Bennett and Knapp
(Reference 6-53) attempted to investigate the effects of boiler excess Q£ on POM emissions from an
oil-fired utility boiler. They found that particulate carbon content increased with decreasing
excess 02- However, because POM assay data varied widely, even for baseline condition analyses, no
conclusion regarding POM emissions was possible.
A few comments are in order here concerning an extremely toxic subclass of polynuclear aro-
matic hydrocarbons, the polychlorinated and polybrominated biphenyls (PCBs and PBBs). A theoreti-
cal assessment of the possibility of PCB formation in combustion sources has been recently completed
(Reference 6-60). This study was prompted by a tentative identification (later proved false) of PCBs
in stack emissions from a coal-fired utility boiler (Reference 6-61). The theoretical study con-
cluded that, although PCB formation is thermodynamically possible during coal and residual oil (fuels
which contain some chlorine) combustion, it is unlikely due to short reaction residence times and
low chlorine concentrations. However, if PCBs are formed, they would be expected to occur under
conditions which promote POM emissions. Still, other than the aforementioned tentative identifica-
tion, PCBs have never been observed in combustion source emissions.
The second general compound category considered as an organic emission in the present dis-
cussion is the nitrosamines group. Nitrosamines (characterized by the N-nitroso group, N-N=0) are
formed by the reaction of secondary or tertiary amines with nitrous acid. These N-nitroso compounds
are of environmental concern because nearly 70 percent of these compounds have been found to be
carcinogenic in all species of laboratory animals (Reference 6-62).
Primary nitrosamine emissions from various industrial sources may affect ambient levels.
Three recent environmental assessments of these compounds (References 6-62, 6-63, and 6-64) have
concluded that primary nitrosamine emissions from stationary combustion sources are nonexistent.
There are at present, however, no data to support this contention.
Combustion sources do, however, emit the NO precursors to nitrous acid, one requisite in-
gredient in nitrosamine formation. Since nitrate formation from ambient NO is known to occur, it
is theoretically possible for nitrosamines to be formed in polluted atmospheres containing secondary
6-72
-------
TABLE 6-19. SUMMARY OF POM EMISSION TESTS
(Reference 6-14)
Anthracene/Phenanthrene
Methyl Anthracenes
Fl uoranthene
Pyrene
Chrysene/Benz (A)
Anthracene
Total POM
(Percent of Baseline)
Baseline
(yg/m3)a
178.4
53.4
51.5
15.1
0.3
298.7
(100)
2-Stage Combustion
(yg/m3)a
179.3
48.5
110.3
52.1
—
390.2
(131)
15% Gas
Recirculation
(yg/m3)a
145.3
89.4
24.7
23.3
—
282.7
(95)
2-Stage + 15%
Recirculation
(yg/m3)a
230.4
98.3
43.7
46.9
—
419.3
(140)
•-4
OJ
13% 02, dry basis.
-------
and tertiary amines. From such considerations, it is clear that implementing NO controls in sta-
tionary combustion sources can only serve to decrease ambient nitrosamine levels. Thus, the incre-
mental impact of NO controls on nitrosamines is beneficial.
6.2.7 Nitrates
Atmospheric nitrate exists in both organic and inorganic forms. Organic nitrate consists of
alkyl nitrates and peroxyacylnitrates, of which the most important is peroxyacetylnitrate (PAN).
PAN -which is by far the most abundant organic nitrate and is even the most abundant of all ambient
nitrates (Reference 6-65) - is an eye irritant and causes damage to vegetation. Inorganic nitrates
include nitric acid and the nitrate salts of various metals and ammonium ion, of which ammonium
nitrate appears to be the most abundant (Reference 6-66). Inorganic nitrates exist in the atmos-
phere as nitrate aerosol. Although the direct health effects of ambient nitrate aerosols are largely
unknown, atmospheric inorganic nitrate has become a matter of major concern as a contributor to acid
precipitation.
Although the data are largely lacking, it appears at present that primary nitrate emissions
from stationary or mobile combustion sources are insignificant. Ambient nitrate seems, instead,
to be a direct result of secondary nitrate production from ambient NO precursors. Although the
formation of inorganic nitrate in the atmosphere is not clearly understood, the reactions shown in
Table 6-20 are believed to be important (Reference 6-46). These reactions are believed to be het-
erogeneous and therefore catalyzed by ambient particulate. The nitric acid produced through these
reactions seems to be immediately neutralized. Ambient ammonia is the major neutralizing agent,
giving rise to ammonium nitrate aerosol. The mechanism for PAN formation is more clearly under-
stood, and is also shown in Table 6-20.
Since there are apparently no primary nitrate emissions from stationary combustion sources,
the possible effects of combustion NO controls on these emissions are unimportant. Indeed, the
use of NO controls should decrease ambient secondary nitrate levels by decreasing precursor com-
A
pound emissions. This is, in fact, one important reason for controlling NO emissions.
One possible point of concern in the area of nitrate emission is the proposed use of ammonia
injection for NO control. Recent evidence suggests that ambient ammonia levels may be a determining
factor in nitrate aerosol formation (Reference 6-66). If this is the case, implementation of ammo-
nia injection could possibly cause increased atmospheric nitrate aerosol production.
6-74
-------
TABLE 6-20. NITRATE FORMATION MECHANISMS
(References 6-46, 6-66)
A. Inorganic Nitrate
6N02 + 3H20 $ 3HN03 + 3HN02 (la)
3HN02 J HN03 + 2ND
HO + N02 * HN03 (2)
N02 + 03 j N03 + 02 (3a)
N03 + N02 t N2°5
N2°5 + H2° £ 2HN03
B. PAN
R + CH3CHO J Product + CH3CO (4a)
CH3CO + 02 + M t CH3C002 + M (4b)
CH3C002 + N02 t CH3C002N02 (PAN) (4c)
6-75
-------
6.3 EVALUATION AND SUMMARY
Based on the discussions in Sections 6.1 and 6.2, N0x control techniques and pollutants can
be classified into one of the following three groups according to potential for increased emissions:
• High potential emissions impact, where the data presented in Section 6.2 unambiguously
show that applying the NO control results in significantly increased emissions of a
specific pollutant
* Intermediate potential emissions impact, where the preliminary screening exercise in
Section 6.1 indicates that the N0x control could conceivably cause increased pollutant
emissions, but confirming data are lacking, contradictory, or inconclusive
• Low potential emissions impact, where the data presented in Section 6.2 clearly show that
specific pollutant emission levels decrease when the NO control is applied, or where the
discussion in Section 6.1 definitely indicates a similar conclusion, even though data are
lacking
These groupings appear in Tables 6-21, 6-22, and 6-23 for NOX combustion controls applicable to
boilers, 1C engines, and gas turbines, respectively. These tables are arranged in matrix form,
like Tables 6-2, 6-4, and 6-5 of Section 6.1, and note the level of potential environmental concern
for each NO control technique/pollutant combination.
As Table 6-19 illustrates, applying preferred NO combustion controls to boilers should have
few adverse effects on incremental emissions of CO, vapor phase hydrocarbons or particulates. It is
true that indiscriminantly lowering excess air can have drastic effects on boiler CO emissions, and
that particulate emissions can increase with off-stoichiometric combustion and flue gas recircula-
tion. However, with suitable engineering during development and implementation of these modifications,
adverse incremental emissions problems can be minimized. In contrast, residual emissions of sulfate,
organics, and trace metals have intermediate to high potential impact associated with applying almost
every combustion control. For trace metal and organic emissions, substantiating data are largely
lacking, but fundamental formation mechanisms give cause for justifiable concern. In the case of
sulfate emissions, fundamental formation mechanisms suggest that these emissions should remain un-
changed or decrease with all controls except ammonia injection. However, complex interactive effects
are difficult to elucidate, and this pollutant class is sufficiently hazardous to justify expressing
some concern in the present absence of conclusive data. The potential effects of post-combustion
ammonia injection on plume sulfate formation deserve special attention.
6-76
-------
TABLE 6-21. EVALUATION OF INCREMENTAL EMISSIONS DUE TO NOX CONTROLS APPLIED
TO BOILERS
NOV Control
/\
Low Excess Air
Staged
Combustion
Flue Gas
Recirculation
Reduced Air
Preheat
Reduced Load
Water
Injection
Ammonia
Injection
Incremental Emission
CO
++
0
0
0
0
0
0
Vapor Phase
HC
0
0
0
0
0
0
0
Sulfate
+
+
+
+
+
+
++
Parti cul ate
0
+
+
0
0
+
+
Organ ics
++
++
+
+
+
+
0
Segregating
Trace Metals
+
+
+
0
0
0
+
Nonsegregating
Trace Metals
0
0
+
+
0
0
0
?
-J
Key: ++ denotes having high potential emissions impact
+ denotes having intermediate potential emissions impact, data needed
0 denotes having low potential emissions impact
-------
TABLE 6-22. EVALUATION OF INCREMENTAL EMISSIONS DUE TO NOX CONTROLS APPLIED
TO 1C ENGINES
NO Control
/S
Retard
Ignition
Increase A/F
Ratio
Decrease A/F
Ratio
Exhaust Gas
Recirculation
Decrease
Manifold Air
Temperature
Stratified
Charge
Cylinder
Design
Derate
Increase Speed
Water Injection
Incremental Emission
CO
++
0
++
+
0
+
++
+
+
Vapor Phase
HC
+
++
++
+
++
+
++
+
++
Sulfate
0
++
0
0
+
0
+
0
0
Particulate
++
0
+
++
0
+
0
+
+
Organ ics
+
0
+
+
0
+
0
+
+
Segregating
Trace Metals
0
0
+
+
+
+
+
+
+
Nonsegregating
Trace Metals
0
0
0
0
0
0
0
0
0
Ot
3
Key: -H- denotes having high potential emissions impact
+ denotes having intermediate potential emission impact, data needed
0 denotes having low potential emissions impact
-------
TABLE 6-23. EVALUATION OF INCREMENTAL EMISSIONS DUE TO NOX CONTROLS APPLIED
TO GAS TURBINES
NO Control
X
Water or Steam
Injection
Lean Primary
Zone
Early Quench
with Secondary
Air
Increase Mass
Fl owrate
Exhaust Gas
Recirculation
Air Blast/Air
Assist
Atomization
Reduced Air
Preheat
Reduced Load
Incremental Emission
CO
++
0
0
+
+
'o
0
•H-
Vapor Phase
HC
+
0
0
' +
+
+
0
-H-
Sul fate
0
+
0
0
0
0
+
+
Parti cul ate
+
0
+
+
+
+
0
+*
Organics
+
0
+
+
+
+
0
+
Segregating
Trace Metals
+
+
+
+
+
+
+
+
Nonsegregating
Trace Metals
0
0
0
0
0
0
0
0
o>
(O
Key: ++ denotes having high potential emissions impact
+ denotes having intermediate potential emissions impact, data needed
0 denotes having low potential emissions impact
-------
Table 6-22 shows that the incremental emissions of all pollutant classes except nonsegre-
gating trace metals have either intermediate or high potential impact when applying N0x controls to
1C engines. Of primary concern are increased CO, vapor phase hydrocarbons (HC), and participate
(smoke) emissions. Of lesser concern are sulfates, orgam'cs, and segregating trace metals from
engines burning high sulfur diesel fuels.
Similarly, NO controls applied to gas turbines can be expected to adversely affect all in-
X
cremental emissions except nonsegregating trace metals, as Table 6-23 indicates. Again, increased
sulfate, particulate, organic, and segregating trace metals are of some concern in those sources
firing high sulfur diesel fuels. If residual oil firing in gas turbines increases, these concerns
could become more serious. Presently, this appears unlikely due to materials problems, e.g., sul-
fidation with residual oils.
The incremental emission evaluations of Tables 6-21 through 6-23 are not intended to signify
any potential for adverse environmental impact. Rather, the evaluation notes source/control/
pollutant combinations for which emissions may increase due to the use of NO controls. Evaluation
X
of potential adverse impact requires comparison of the source generated ambient pollutant concentra-
tion with an upper limit threshold concentration of the pollutant based on health or ecological
effects. A preliminary attempt at such a comparison is made in Section 7. Prior to that, some
conclusions may be drawn on the results in this section.
In general, the data on incremental multimedia emissions due to NO controls are very sparse.
More data are available for flue gas emissions than for liquid or solid effluent streams. Even so,
the only data which allow quantified conclusions are for emissions of criteria pollutants with the
major source/control combinations. Data on sulfates, trace metals and orgam'cs (POM) are sparse,
experimentally uncertain and highly dependent on fuel properties. Incremental emissions from liquid
and solid effluent streams and during transient or nonstandard operation are almost nonexistent.
Because of this, they have generally been excluded in the present evaluation. Test data from on-
going related programs and from the NO E/A test programs will be needed before the incremental
X
emissions and impacts can be evaluated for other than flue gas emissions during standard operation.
Emissions of CO, HC, particulate (smoke) and SO, with or without NO controls have been con-
Oi X
strained in the past for operational reasons rather than environmental impact. CO, HC and smoke
emissions reduce efficiency and may present a safety hazard. S03 leads to acid condensation and
corrosion. All of these emissions are sensitive to combustion process modifications for NO con-
X
trol. With the exception of SO,, incremental emissions tend to increase with NO controls, par-
«3 X
ticularly low excess air and off-stoichiometric combustion. Development experience has shown,
6-80
-------
however, that with proper engineering these emissions can generally be constrained under low-NO
conditions. This 1s particularly true for factory-Installed controls on new equipment. In this
case, the flexibility for applying NOX controls with minimal adverse impact is greater than for
retrofit on existing equipment. In light of this situation, incremental emissions are seen more as
a constraining criteria to be addressed during control development than as an immutable consequence
of low-NOx firing. Moreover, the constraint on emissions for satisfactory operational performance
is generally more stringent than the constraint for acceptable environmental impact. The environ-
mental constraints will be carried through the N0x E/A impact assessments for all potentially sig-
nificant pollutants, but they will need to be supplemented by operational constraints in some cases.
The situation for other flue gas pollutants is more uncertain. There is concern that conven-
tional combustion process modifications - low excess air, off-stoichiometric combustion, flue gas
recirculation -will increase emissions of sulfates, organics and segregating trace metals from
sources firing coal or reiidual oil. It should be noted, however, that this conclusion is based on
sparse data or, lacking that, on fundamental speculation. Clearly, more data are needed. Little is
known on whether these emissions can be suitably constrained to acceptable levels during control
development.
With the firing of clean fuels - natural gas and distillate oil - the main noncriteria pol-
lutant class of concern is organics. This fact will make the testing and assessments of clean fuel
sources -warm air furnaces, gas turbines, 1C engines - simpler than for boilers and process fur-
naces firing residual oil or coal. Additionally, the clean fuel sources have no liquid or solid
effluent streams. These considerations do not imply a priori that gas or distillate oil-fired
equipment are more environmentally sound. Rather, the clean fuel sources can be assessed to the same
level of detail as other sources for less effort.
In conclusion, there is reasonable concern that NOX controls will increase incremental emis-
sions of some pollutants. More data are needed to determine if incremental emissions have a sig-
nificant environmental impact and to suggest corrective action if needed. In the next section,
a preliminary screening of pollutants on the basis of impact is given and test priorities are
discussed.
6-81
-------
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-------
6-20. Gillis, B. G., "Production and Emissions of Solids, SOX and NOX from Liquid Fuel Flames,"
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Paper 76-27.8, 69th Annual APCA Meeting, June 1976.
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6-31. Gladney, E. S., et al., "Composition and Size Distributions of Atmospheric Particulate
Matter in Boston Area," Environmental Science and Technology, Vol. 8, No. 6, p. 551,
June 1974.
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Paper 75-33.7, 68th Annual APCA Meeting, June 1975.
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Vol. 6, No. 12, pp. 1025-1030, November 1972.
6-34. Bolton, N. E., et al., "Trace Element Measurements at the Coal-Fired Allen Steam Plant,"
Progress Report, February 1973 through July 1973, ORNL-NSF-EP-62, 1974.
6-35. Billings, C. E., et al., "Mercury Balance on a Large Pulverized Coal-Fired Furnace,"
J. APCA. Vol. 23, No. 9, pp. 773-777, September 1973.
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EPA-600/2-76-086b, NTIS-PB 261 263/AS, October 1976.
6-37. Vitez, B., "Trace Elements in Flue Gases and Air Quality Criteria," Power Engineering
pp. 56-60, January 1976.
6-38. Hegg, D. A,, et al., "Reactions of Nitrogen Oxides, Ozone, and Sulfur in Power Plant Plumes,"
EPRI EA-270, September 1976.
6-39. Richards, J., and R. Gerstle, "Stationary Source Control Aspects of Ambient Sulfates: A
Data Base Assessment," PedCo Final Report, EPA Contract No. 68-02-1321, Task 34, PedCo
Environmental, Cincinnati, OH, February 1976.
6-40. "Position Paper on Regulation of Atmospheric Sulfates," EPA-450/2-75-007, September 1975.
6-83
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6-41. Corn, M., and R. T. Cheng, J. APCA. Vol. 22, p. 870, 1972.
6-42. Husai, R. B., et al., "Paniculate Sulfur Formation in Power Plant, Urban and Regional
Plumes," Paper 13d, AIChE 82nd National Meeting, September 1976.
6-43. Gordon, 6. E., "Study of the Emissions from Major Air Pollution Sources and Their Atmospheric
Interactions," NSF-RA-E-74-059, NTIS-PB 242 581, October 1974.
6-44. Bradstreet, J. W., "Effects of Nitric Oxide'on the Photochemical Oxidation of Sulfur Dioxide
in Dilute Gas-Air Mixtures," Paper 73-113, 66th Annual APCA Meeting, 1973.
6-45. Davis, D. D., et al., Science, Vol. 186, p. 733, 1974.
6-46. Levy, A., and C. W. Spicer, "The Atmospheric Chemistry of NOX," presented at the 69th
National AIChE Meeting, November 1976.
6-47. Homolya, J. B., et al., "A Characterization of the Gaseous Sulfur Emissions from Coal and
Coal-Fired Boilers," presented at the 4th National Conference on Energy and the Environment,
Cincinnati, OH, October 1976.
6-48. Wendt, J. 0. L., University of Arizona, Tucson, AZ, personal communication, January 1977.
6-49. Wichert, K., "Chemical Reactions in the Combustion Chamber of a Slag Tap Boiler,"
Brennstoff-klarme-Kraft, Vol. 9, pp. 104-118, March 1957.
6-50. Vogel, R. F., et al., "Reactivity of S02 with Supported Metal Oxide -Aluminum Sorbents,"
Environmental Science and Technology, Vol. 8, No. 5, pp. 432-436, May 1974.
6-51. Novakov, T., et al., "Sulfates as Pollution Particulates: Catalytic Formation on Carbon
(Soot) Particles," Science. Vol. 186, pp. 259-261, October 18, 1974.
6-52. Archer, J. S., et al., "Multiphase Combustion of Residual Fuel Oil," J. Inst. Fuel, Vol. 43,
pp. 397-404 and 451-460, 1970.
6-53. Bennett, R. L., and K. T. Knapp, "Chemical Characterization of Particulate Emissions from
Oil-Fired Power Plants," presented at the 4th National Conference on Energy and the Environ-
ment, Cincinnati, OH, October 1976.
6-54. Hall, R. E., CRB, IERL, U.S. EPA, personal communication.
6-55. Remeysen, J., "Operations of Large Boilers at Very Low Excess-Air Levels," Paper 1 in
Current Development in Fuel Utilization, the Institute of Fuel, 1964.
6-56. Niepenberg, H., "Combustion Control of Oil-Firing Systems Operated at Low Excess Air Levels,"
Paper 5 in Third Liquid Fuels Conference: Applications of Liquid Fuels, The Institute of
Fuel, 1966.
6-57. Jackson, P. J., "Generating Stations Efficiencies," Paper 8 in Third Liquid Fuels Conference:
Applications of Liquid Fuels, The Institute of Fuel, 1966.
6-58. "Chemistry and Metallurgy," Vol. 5 in Modern Power Station Practice, Central Electricity
Generating Board, Pergamon Press, New York, 1971.
6-59. Bittner, J. D., et al., "The Formation of Soot and Polycyclic Aromatic Hydrocarbons in
Combustion Systems," in Proceedings of the Stationary Source Combustion Symposium. Vol. I,
EPA-600/2-76-152a, NTIS-PB 256 320/AS, June 1976.
6-60. Knierien, H., Jr., "A Theoretical Study of PCB Emissions from Stationary Sources," Monsanto
Research Corporation, Dayton, OH, Report MRC-DA-577, September 1976.
6-61. Cowherd, C., Jr., et al., "Hazardous Emission Characterization of Utility Boilers,"
EPA-650/2-75-066.
6-62. "Scientific and Technical Assessment Report on Nitrosamines," EPA-600/6-77-001, November 1976.
6-84
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6-63. Walker, P., et al., "Environmental Assessment of Atmospheric Nitrosamines," Mitre Corp.,
McLean, VA, MTR-7152, February 1976.
6-64. "Assessment of Scientific Information on Nitrosamines," Report of the ad hoc Study Group,
U.S. EPA, Science Advisory Board, August 1976.
6-65. Stevens, E. R., et al., "Recent Developments in the Study of the Organic Chemistry of the
Atmosphere," J. APCA. Vol. 6, p. 159, 1969.
6-66. Grosjean, D., et al., "The Concentration, Size Distribution, and Modes of Formation of
Particulate Nitrate, Sulfate, and Ammonium Compounds in the Eastern Part of the Los Angeles
Basin," Paper 76-20.3, 69th Annual APCA Meeting, June 1976.
6-85
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SECTION 7
ENVIRONMENTAL ASSESSMENT PRIORITIES
The NOX E/A program priorities summarized in this section relate directly to the needs and
approach discussed in the Preface and Introduction of this report. The needs to be addressed by the
\NOX E/A are:
• Assess current and impending combustion modification applications to quantify environ-
mental, economic and operational impacts
t Assess emerging advanced technology to guide control development
- Identify potential adverse impacts which should be addressed in the control develop-
ment program
— Estimate which controls will be needed and are most effective to attain air quality
goals to the year 2000
The approach used in the NO E/A to address these needs gives primary emphasis early in the program
X
to assessing current and impending control applications. Assessment of advanced technology applica-
tions will proceed at a lower level of effort early in the program but will be emphasized toward the
end of the program. During the program, separate process engineering/environmental assessment re-
ports will be generated for each major equipment category. These reports will focus mainly on cur-
rent technology since it is more timely from an environmental standpoint and since it has been more
extensively tested. The final report will document the assessment of far-term applications and will
update the earlier assessments of near-term applications.
To support this approach, preliminary priorities are needed for:
• The sequence in which the major source categories are to be assessed and the level of
effort devoted to each
• The near-term source/control applications to be assessed
t The source/control combinations to be addressed in the assessment of far-term applications,
e.g., those likely to see application in this century
7-1
-------
• The effluent stream/pollutant combinations to be emphasized in the test programs and
assessments
In this report the preliminary source/control screening is conducted independently of the
pollutant screening. Initially the source/control combinations are screened on the basis of signifi-
cant near-term or far-term application. Pollutants for the resultant source/control combinations
are then screened for potential adverse impacts. The results are then combined to set program
priorities.
The earlier sections of this report summarized most of the information required to deter-
mine these four priorities. This section consolidates that information and adds estimates of near-
and far-term source/control requirements to attain and maintain air quality. The priorities were
then set in the sequence of the above list. The criteria used are listed below; supporting sections
are indicated in parentheses.
Source Priorities
• Current and projected use of specific equipment design/fuel combinations within a source
category (Section 2)
• Extent of current or impending NOX regulations for the source category (Section 4)
• Ranking of source NO emissions on a national basis (Section 5)
t Relative potential for adverse environmental impacts (Section 6)
• Current and projected effectiveness of the source in urban NOX abatement (Section 7-1)
Near-Term Source/Control Priorities
• Extent of use and effectiveness of controls for the source category (Section 4)
• Near-term need for and effectiveness of specific source/control combinations in urban
NOV abatement (Section 7.1)
X
Far-Term Source/Control Priorities
• Trends in source use (Section 2)
• Developmental status and effectiveness of emerging technology (Section 4)
• Far-term need for specific source/control combinations in urban areas for various con-
trol strategy options (Section 7.1)
7-2
-------
Effluent Stream/Pollutant/Impact Priorities
• Baseline uncontrolled emissions (Section 5)
• Incremental emissions due to NO controls (Section 6)
X
• Estimated limits on ambient pollutant concentrations (Section 3)
Where possible, these criteria were quantified. It was not attempted at this stage, however, to
carry a rigorous quantification through to numerical weighting of priorities. This is because the
combined effects of the general lack of data, the early stage of the program, and the general uncer-
tainty in the national NOX abatement strategy would make such an approach unproductive. The quali-
tative priorities that are set will be updated and reevaluated as new data become available and re-
sults of supporting program tasks are completed.
Section 7.1 screens current and advanced combustion modification NOV controls for effective-
X
ness in attaining and maintaining the ambient NCL standard. This evaluation relates to the priori-
tization criteria listed above. These results, together with the results of previous sections are
evaluated in Section 7.2 to arrive at preliminary source/control priorities for the near-term and
far-term effort. Evaluation of potential pollutant/impacts for the near-term source/control combina-
tions is given in Section 7.3. Section 7.4 summarizes the conclusions of the preliminary assesement.
7.1 EVALUATION OF N0x CONTROL REQUIREMENTS
This section presents the methodology and results of a preliminary analysis to evaluate NO
control requirements for the attainment and maintenance of the ambient N02 standard. The results
of this analysis on two AQCRs will be used to identify the type and level of NOX emission control
necessary to meet the N02 ambient air goals. The main goal of this preliminary analysis is to set
priorities for the NO E/A program. Therefore, only ambient N02 concentrations were considered
under the assumption that their reductions are directly dependent on NOX emission reductions. There
is no attempt to consider either NO -HC or N02-oxidant interaction effects on the N02 concentration.
These effects are considered to be beyond the scope of a preliminary analysis. Moreover, neglecting
these effects is not expected to significantly alter the priorities based on this analysis.
A preliminary screening model forms the basis of the analysis. As described in Section 7.1.1,
it processes the input data on emissions, ambient concentrations, and NOX control to identify the
most cost effective control strategy to attain and maintain the N02 ambient standard. The principal
components of this systems model are the ranking of control methods and the air quality model, which
7-3
-------
for this preliminary analysis is a modified form of rollback. In Section 7.1.2 the procedure for
selecting the two AQCRs is described. Los Angeles and Chicago were selected from a group of NOy
critical AQCRs because they are already in violation of the N02 standard and they represent two
contrasting NOX problems -mobile source dominated and stationary source dominated. The input data
for those two AQCRs are described in Section 7.1.3, and the results of the analysis are presented
in Section 7.1.4. That section shows that maximum stationary source controls will be required if
there is to be a reasonable chance of achieving the N02 standard in these two AQCRs.
7.1.1 Preliminary Screening Model
The preliminary screening model serves to coordinate the various elements that together form
a cost effective control strategy for achieving the NCL ambient standard. The requirement of the
model is that it provide a useful tool for relating emissions to ambient concentrations and for as-
sessing the cost and effectiveness of controls for meeting the NOp standard. In this case the utility
of the model is judged on the basis of:
• Simplicity of input
• Cost per solution '
t Flexibility
• Relevance of results
The basic elements that must be incorporated into the model are:
• Calculation of emissions
• Calculation of fuel use
• Calculation of cost of control
• Ranking of controls for order of application to reduce source emissions
• Relationship of controlled emissions to ambient concentration
The first three elements listed above are solely of a "bookkeeping" nature, whereas the last two can
range from very simple to very sophisticated models. This is especially true of the air quality
model -the relationship between emissions and ambient concentration. A general discussion of air
quality models and the choice of the model for use in the preliminary phases of the NO E/A program
are presented in the following paragraphs. The other elements (auxiliary models) of the screening
model are then briefly described in the remainder of this subsection.
7-4
-------
7.1.1-1 Air Quality Models
An air quality model is any methodology for relating atmospheric contaminant concentration
to pollutant source emissions. Models differ not only in their degree of sophistication but also in
their resolution and versatility. Usually the sophisticated models require considerably more elaborate
input data than the simpler models. Furthermore, since even they are based on approximate modeling of
physical phenomena, such as atmospheric turbulence and chemical kinetics, they still require a sig-
nificant calibration effort and considerable experience to use them intelligently. On the other
hand, the lower-order models, .which try to model the atmospheric processes in an integral manner,
are based on certain correlations of the available data and lack the resolution of the sophisticated
models.
The air quality model is the key element of the preliminary screening model. Therefore,
careful attention has been given to the choice of the model. The following factors have been con-
sidered:
• The precision required for forecasting air quality impacts
• The time and resources appropriate to this effort
• The availability of the required meteorological and air quality data for the area of
interest
• The availability of a suitable spatially distributed emissions inventory
• The physical size of the area under consideration and the time scale of interest
Since some degree of uncertainty is involved in utilizing any available model, disagreement exists
over which approach is best.
Table 7-1 provides a summary of the basic model types currently available.* The key features
of each class of models, their input data requirements, and comparative costs for a similar set of
calculations are given. The diversity exhibited by these models lies not only in the basic assump-
tions of the formulation but also in the refinements, the expense to run, the applicable geographi-
cal and time scales, and the effort required to calibrate the models. For the purposes of the pre-
liminary screening analysis the single most restrictive feature is the input data requirement.
The modified rollback model is a simple and inexpensive model to use and can be readily ap-
plied to assess different control technologies and strategies. This model does not effectively
Table 7-1 was constructed from information provided by References 7-1, 7-2, and 7-3.
7-5
-------
TABLE 7-1. SUMMARY OF AVAILABLE AIR QUALITY MODELS
Model
Rollback
Statistical
Trajectory
Markov Chain
Nonreactlve Dis-
persion (COM)
Photochemical
Box
Lagrangian Traject.
Eulerian Photochem/
Diffusion
Multibox Eulerian
Averaging
Type3 Time Accuracy
E Variable Generally
fair to
poor
E 1 hr 300%
E 1 hr - 1 yr 2Q%
for
of exceedance
D/E Variable Fair to good
D 1 hr 200%
D Up to 1 hr 302! - 40%
D 1 hr 20% 03
40% NOz
D 1 hr 30% 03
50£ N02
Method
Simple data
correlation
Stat. fit
to chem.
Trace his-
tory of air
mass prior
to arrival
Statistical
Gaussian
plume non-
reacting
• Fully
mixed
• Chem
kinetics
• Allows
advection
• Track air
parcel
• Chem ki-
netics
• Vertical
diffusion
t Difference
equations
» Chem ki-
netics
• See above
• Integrate
vert.
direct.
Input
Requirements
Source emissions,
base year con-
centration and
emissions
Surface wind
vectors through-
out area, grid-
ded inventory
H1nd fields,
gridded sources,
cal air quality
data
Gridded sources,
stack heights,
joint frequency
dist. for meteo-
rology
Precursor cone. ,
mix depth, temp.
aggregate source
inventory, HC
inventory by class
Gridded inventory,
RHC/NRHC, initial
and boundary condi-
tions, wind speed
Same as above
Same as above
Output
Concentration
Concentration
at 1 receptor
station
Probability of
exceeding some
Concentration
contours for
primary pol-
lutant
Basin wide
concentration
Cone, history
of 1 receptor,
or cone, his-
tory of 1 air
mass
Air basin cone.
Air basin cone.
Secondary
Pollutants
Appendix J,
smog chamber
results, his-
torical cor-
relation
Chemical cor-
relation
Historical
correlation
Correlation, Ap-
pendix J, smog
chamber
Direct, cal-
culation
Direct, cal-
culation
Direct, cal-
culation
Direct, cal-
culation
Costb
Not Including
Inventory
Preparation
$2K
$10K - $15K
$25K - $35K
$10K - $15K
$25K - $50K
$35K - $50K
per
receptor
$150K - $200K
$60K - $80K
Comments
(1) No meteorology; (2) No con-
sideration of source distribution;
(3) No consideration of chemistry;
(4) Not extendable to rural areas;
(5)Secondary pollutant calculations
compound errors in primary; (6)
Very simple, flexible, cheap;
(7) Minimal input data require-
ments
(1) No vertical mixing; (2) May
be useful for rural areas;
(3) No consideration if elevated
sources; (4) Empirical chemical
correlations
(1) Reduced sensitivity to specific
sources via consideration of many,
runs are necessary; (3) Rural
extensions questionable since no
data base
(1) Must relate empirical cor-
relation of NO? precursor — may
offset geographical advantages;
(2) Can treat elevated sources;
(3) Questionable on rural exten-
sion
(1) No geographical differentiation;
(2) Hay possibly be useful for rural;
(3) Must have detailed HC inventory
(1) Can be applied to rural areas;
(2) Can handle elevated sources;
(3) Includes meteorology; (4) Must
nave detailed HC inventory; (5) Eulerian
in vertical direction
(1) See above 1-5
(1) See above 1-4; (2) Integral treatment
of vertical profiles
CTl
E - empirical; D - deterministic
^Costs — assumes that a suitable inventory is available. The cost of preparing this is quite variable and depends on what has already been done.
-------
account for changes in distribution of emissions over time and space. Therefore, the accuracy of •
air quality estimates will suffer if the emission patterns are significantly altered. Moreover, the
rollback model assumes that meteorology and the NOX-HC and N02-oxidant interaction effects for the
study area will be similar for the :base year and future years.
The more complex models are designed to explicitly include the physical processes that re-
late emissions to ambient pollutant concentrations. As such, they are most applicable to signifi-
cantly altering emission patterns and can be used to assess the impact on an air basin of selected
control strategies. A wide variety of models with differing degrees of sophistication and applica-
bility falls into this category. These models can be divided into two classes: nonreacting disper-
sion (Gaussian plume) and photochemical diffusion models. The former approximates the dispersion
process by simple, experimentally based formulations, whereas the latter starts from the basic prin-
ciples of conservation of mass and species and develops numerical solution procedures to account for
transport, turbulent mixing and chemical reactions, especially photochemistry. These models require
considerably more extensive input data, including spatial distribution of sources and meteorological
variables, than does the rollback model.
Since the main purpose of the preliminary systems analysis is to assist in setting priorities
for conducting detailed process engineering and environmental assessments of the possible source/
control combinations, the model need only provide qualitative results on the cost effectiveness of
the various control options. Furthermore, it should serve this function without excessive cost or
undue effort in input preparation. Thus, the modified rollback model was selected rather than one
of the more complex, and supposedly more accurate, models described in Table 7-1. The degree to
which the well known shortcomings of rollback affect the results is variable, and in some cases
rollback yields results that are in good agreement with even the most complex models. Furthermore,
the impact of these shortcomings, or assumptions, on the results can be assessed by way of a sensi-
tivity analysis, and this will be done in Sections 7.1.3.2 and 7.1.3.6. Although rollback was
selected for use in the preliminary analysis, more complex models, especially ones that include the
relationships between NO emissions and ozone, as well as other secondary pollutants, will be con-
sidered in later phases of the program.
The form of the rollback model used here is given by
AC = k >,(1 - RJ E,W, + BG (7-1)
7-7
-------
where AC = ambient concentration
E. = uncontrolled emissions from source i
R. = reduction by control of source i
W. = weighting factor for source i
BG = background concentration (the background concentration has been assumed to be
10 ng/m3 for all cases)
The calibration constant, k, is determined by evaluation of the equation at some "base year" for
which the ambient concentration, emissions, etc., are known. Although parameters such as stack
height and relative position of source and receptor are not explicitly reflected in the model, they
are implicitly included because the model is essentially a correlation between existing emission
patterns and the resulting ambient air conditions. Moreover, these two factors can be introduced
by assigning proper values to the source weighting factors.
7.1.1.2 Auxiliary Models
Preparation of the input to the air quality model and processing of the output are the func-
tions of the various auxiliary models. Figure 7-1 shows the flow of information through the prelimi-
nary screening model. The functions of the various auxiliary models are described in the following
paragraphs.
Emissions
The purpose of this portion of the model is to combine the effects of source growth, control,
and weighting (relative impact of the source on the ambient concentration) to compute the net emis-
sions from each source category for use in the air quality model. Uncontrolled emissions for the
base year and each future year of interest are input for each source category. Controls to reduce
the emissions are either input or prescribed by the model as necessary to achieve a preset ambient
concentration. They are input, for example, when it is known that an emission standard will come
into effect for a specific source at some future date. When the systems model* chooses the control,
it selects from a table of options according to the algorithm (described below) used to set control
priorities. In addition, provision has been made to weight the emissions from each source in a pre-
determined manner (see Section 7.1.3.6).
*
Preliminary screening model and systems model are used interchangeably.
7-8
-------
INPUT BASE YEAR:
EMISSIONS
AMBIENT CONCENTRATION
CONTROLS
FUEL COSTS
CALCULATE CONTROLLED EMISSIONS
(USE EXISTING CONTROLS)
CALCULATE AMBIENT
CONCENTRATION
ADD:
NEW SOURCES
NEW CONTROLS
UPDATE: SOURCE EMISSIONS
FUEL COSTS
IS THIS THE
BASE YEAR?
CALIBRATE THE AIR
QUALITY MODEL
JL
ORDER THE CONTROLS
1
APPLY CONTROLS UNTIL
STANDARD IS ACHIEVED
OR
UNTIL ALL CONTROLS USED
CALCULATE FUEL USAGE
CALCULATE COST OF CONTROL
OUTPUT
IS THIS THE LAST YEAR?
I END I
Figure 7-1. Flow chart for the preliminary screening model
7-9
-------
Prioritization of Controls
In general, the goal of a regional air pollution control strategy is to achieve a specified
ambient concentration at the minimum cost to the entire region. Under this condition, the most cost-
effective method of applying controls is in the order of increasing cost per unit reduction in ambi-
ent concentration.* This means one should first compute the ambient N02 reduction that could be
obtained by applying each potential control to its respective sources within the region and then
relate these results to the cost associated with the control. This procedure yields a $/unit ambi-
ent NO- reduction figure for each source/control combination, and permits the combinations to be
ranked and applied on this basis. That is, the source/control combination which has the lowest cost
per unit reduction in NO,, is applied first and the resulting ambient concentration calculated. If
the desired level has not been reached, the next most cost-effective combination is used, and so on.
Since this approach is based on a regional optimization of control cost effectiveness, it does not
consider the total reduction potential for every control method; the most cost-effective approaches
are not necessarily the same ones that cause the greatest emission reductions. Moreover, for sim-
plicity the cost of implementing or enforcing any set of emission or equipment standards has not
been included in the model. Nothing, however, prevents a model user from adding these costs, if
known, to the control costs and allowing the model to proceed as described here.
The cost per unit reduction in ambient concentration for each control method (CUR.) is com-
J
puted from
CUR, = CURE../AAC, (7-2)
J 1 J 1
where CURE., is the cost per unit reduction in emissions from source i as a result of control j and
i J
AAC^ is the change in ambient concentration per unit change in emissions from source i. In this
terminology, then, the program is structured to apply controls in order of increasing CUR. until the
J
specified ambient standard is achieved. It is also within the capability of the program for the
user to override the selection process and force certain controls to be applied. For example, legis-
lative action might dictate that certain sources be controlled independent of other considerations.
This result follows from application of the method of Lagrange multipliers to find the minimum
cost of control subject to the constraints that the standard be met and that the number of any
particular control not exceed the number of sources to which it can be applied.
7-10
-------
Fuel Use
• This component of the systems model calculates the net fuel used (GJ/yr) for each fuel type. The
base year fuel use, by fuel type, is input for each source. Fuel use is then assumed to grow at the
same rate as uncontrolled emissions. Changes in fuel consumption can occur either from fuel switch-
ing or by a change in fuel consumption as a result of a control application. The net fuel use and
net change in fuel use (for each fuel type) from the uncontrolled case are required in the cost-of-
control calculation.
Cost of Control
The cost of each control method is composed of two parts - the incremental cost of fuel as a
result of the application of the control and all other costs. These basic costs are input by the
model user and include the annualized capital cost, maintenance and other operational costs. The
incremental cost of fuel is treated separately to facilitate changes in projected fuel prices. This
cost is calculated from the price of fuel and the changes in fuel consumption caused by the control
method. Once a control strategy which achieves the desired ambient level has been identified, the
two components of cost are summed for each control method used. These two costs and their sum, the
net cost of control, are part of the model output.
7.1.2 Selection of the AQCRs
The United States and its territorial possessions are divided into 247 Air Quality Control
Regions (AQCRs), largely for administrative reasons, to effectively manage the national effort to
attain and maintain a clean environment. Although air pollution in each of these regions tends to
be characterized by different combinations of emission sources and meteorological conditions, a
preliminary analysis of NO control strategies for all the AQCRs is both impractical and unwarranted.
This section, therefore, describes the methodology used to reduce the number of AQCRs under considera-
tion by separating them into four groups, each with distinctive air pollution characteristics. Analy-
sis of one member from each of the groups should be representative of the groups as a whole. For the
purposes of the preliminary screening analysis only two of these representative AQCRs are considered.
The methodology can be summarized briefly as follows:
• Identify air pollution characteristics, including meteorology, emissions, ambient air
quality levels, and data availability
• Group AQCRs according to their air pollution characteristics
• Select one AQCR to represent each group for further analysis
The details of each of these steps are presented in the following subsections.
7-11
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7.1.2.1 Identification of Important Characteristics
One of the main purposes of the environmental assessment program is to identify those controls
which are likely to be needed within at least some areas of the U.S. between now and the year 2000.
Therefore, only those AQCRs which have, or are expected to have, a NOX problem will be considered
for analysis. These regions belong to one of the following two groups:
• Priority AQCRs - For the purpose of this study, regions will be classified Priority AQCRs
if their ambient concentrations exceed the N02 standard when averaged over any consecutive
four quarters (i.e., a rolling quarter basis rather than the statutory calendar year basis)
• AQMAs* - These are regions which have a high probability of exceeding the standard by 1985.
Any region whose ambient NO, concentration lies between 80 and 99 yg/m3, on a rolling quar-
V <-
ter basis, will be considered an AQMA for NOp.
The regions which fall into these two categories were identified by OAQPS (Reference 7-4) and
are listed in Table 7-2. It is recognized that the "rolling-quarter" method will place more regions
into the priority category; however, it has the advantage of providing a conservative approach to
identifying potential problem areas. Moreover, it increases the number of regions for consideration
(thus providing a more representative sample) and enhances the possibility of early identification
of control technologies which may be required in the future. It is these potential control systems
that are deserving of R&D to insure they are technically sound, cost- and energy-effective, and en-
vironmentally safe. The "rolling-quarter" approach is also consistent with advanced thinking in
OAQPS, as witnessed by the listing in Table 7-2 that they supplied.
In order to divide the AQCRs in Table 7-2 into distinctive groups, the air pollution char-
acteristics and emission properties described below must be considered.
Mobile Versus Stationary Sources
The distribution between mobile and stationary sources will be considered because it signifi-
cantly affects the selection of a control strategy. The effectiveness of controlling any particular
source depends, in part, on its total contribution to the problem. Thus, in a region like Los
Angeles, where mobile sources account for approximately 66 percent of the total NO emissions, sta-
tionary source control, although necessary, will have less relative impact on ambient air quality
than in a region like Detroit, which is dominated by NO emissions from stationary sources.
*
AQMA - Air Quality Maintenance Area
7-12
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TABLE 7-2. NOX IMPACTED AQCRs AND AQMAs (ROLLING QUARTERS AVERAGE)
AQCR Number
024
067
045
174
029
115
123
220
042
043
036
225
015
030
119
056
197
181
078
178
122
173
070
234
131
079
106
018
239
047
City Name
Los Angeles
Chicago
Philadelphia
Canton, Ohio
San Diego
Baltimore
Detroit
Salt Lake City
Springfield
New York City
Denver
Richmond
Phoenix
San Francisco
Boston
Atlanta
Pittsburgh
Steubenville
Louisville
Youngstown
Lansing
Dayton
St. Louis
Charleston, VI. Va.
Minneapolis
Cincinnati
Mew Orleans
Memphis
Milwaukee
Washington, D.C.
Concentration
182
121
121
120
119
116
115
114
113
113
110
103
101
101
100
100
98
98
96
96
90
90
85
85
84
83
83
81
81
80
7-13
-------
Dominant Fuel Type
The fuel type from which the majority of stationary source NOX comes should be considered in a
grouping strategy. The type of fuel used in stationary source combustion constrains the effectiveness
and choice of control options. For example, NOX emissions from coal-fired utility boilers are not
reduced significantly by FGR, whereas this technique is effective on gas- and oil-fired boilers.
Stationary Source Type
Stationary combustion sources can be divided into the following categories:
• Utility boilers
• Industrial boilers
• Commercial/institutional boilers
• Residential boilers and furnaces
• Internal combustion devices
The mix of sources within an AQCR is important because the type of control technology and its po-
tential for reducing emissions are heavily dependent on the source type.
Ratio of HC Emissions to NOX emissions (HC/NOX Ratio)
This ratio is important because it controls the conversion of NO to oxidant. Therefore, the
X
appropriate control strategy for oxidants depends on the ambient levels of these two pollutants. If
the HC/NOV ratio is high, the optimal control strategy relies on N(L reductions, whereas if the ratio
A X
is low (a common situation in many cities), the strategy emphasizes HC reductions, at least for cen-
tral urban areas. This ratio may, however, be of less importance in assessing R&D requirements be-
cause current thinking is that both NO and HC emissions must be reduced to simultaneously limit
central urban and downwind oxidant levels.
Ambient Oxidant and NOX Levels
These two quantities indicate the severity of the pollution problem. Also, if these do not
correlate well with NOX emissions it may indicate that the pollution problem is transported in from
an adjacent AQCR. In this case an effective air quality program will require a multi-AQCR strategy.
Solar Insolation
Solar energy is an important factor causing temperature gradients and wind fields which give
rise to mixing and turbulent diffusion. In addition, sun light is a key ingredient in the N0-N02-
Oj-HC interaction.
7-14
-------
stability Class
Stability classes are a function of wind speed and solar insolation. They reflect the mechan-
ical turbulence or mixing in the atmosphere, an important factor in pollutant diffusion and trans-
port. The EPA Star Program'(Reference 7-9) lists Gifford-Pasquill stability class information as
a bivariate frequency distribution of wind direction and wind speed. Stability classes are presented
as:
t A - Extremely stable
• B - Unstable
• C - Slightly stable
• D - Neutral
• E - Stable
Quality of Data
A significant feature of any analysis is the quality of the input data. The complex air
quality models described in Section 7.1.1 require extremely detailed gridded inventories of NO and
RHC* emissions. A rollback model requires much less detail in the data. The Aerometric and Emissions
Reporting System (AEROS) (Reference 7-10), was established by the EPA to be a source of this data. At
this time the data in the AEROS system are not of sufficient quality to be solely relied upon. For
rollback modeling the deficiencies can usually be overcome (see Section 7.1.3.1). However, the com-
plex models require much greater accuracy if they are to be properly utilized. Data of this quality
have been prepared for some AQCRs, and their availability will be an important factor in the selec-
tion of an AQCR for detailed study.
7.1.2.2 AQCR Groups
Data for each of the properties described above are shown in Table 7-3. Some of these data
are more useful than others in grouping the AQCRs. For example, over 90 percent of the AQCRs are
characterized by Stability Class D, so, this property is not a useful criterion. The ozone measure-
ments recorded over a 2-year period show order of magnitude variations and are also of questionable
value. Most of the remaining data originate from the AEROS data bank, are of satisfactory quality,
and were given further consideration.
Three unsuccessful attempts were made to divide the AOCRs into distinctive groupings. The
first sought a relationship between high mobile emissions and high HC/NOx ratios; the second a cor-
respondence between a high HC/NO ratio, a high ozone level, and a high solar insolation level; and
*
RHC - Reactive hydrocarbons
7-15
-------
TABLE 7-3. AIR POLLUTION CHARACTERISTICS OF THE NOX IMPACTED AQCRs AND AQMAs
City
Los Angeles
Chicago
Philadelphia
Canton
San Diego
Baltimore
Detroit
Salt Lake City
Springfield
New York City
Denver
Richmond
Phoenix
San Francisco
Boston
Atlanta
Louisville
St. Louis
Cincinnati
Lansing
Dayton
New Orleans
Minneapolis
Steubenville
Memphis
Charleston, W. Va.
Milwaukee
Washington, D.C.
Pittsburgh
Youngstown
AQCR
Number
24
67
45
174
29
115
123
220
42
43
36
225
15
30
119
56
78
70
79
122
173
106
131
181
18
234
239
47
197
178
Mobile
Ststl onary»
M
66.0-M
63.9-S
54.8-S
56.4-S
70.1-M
58.9-M
52.5-S
54.3-H
54.0-M
61.2-S
54.3-M
66.0-S
76.1-M
70.4-M
53.5-S
55.2-M
78.9-S
75.0-S
56.8-S
64.3-S
57.3-M
77.0-S
57.5-S
90.1-S
58.2-S
88.4-S
53.3-S
55.0-M
77.1-S
53.6-S
Dominant
Fuelb
(«)
38-G
42-C
53-0
80-C
54-G
61-0
62-C
33-G
66-0
82-0
58-C
62-0
70-6
42-0
94-0
52-C
85-C
72-C
79-C
47-C
67-C
54-G
55-C
63-C
64-C
95-C
63-C
48-0
90-C
77-C
Station-
ary Com-
bustion0
W
72. -U
56. -U
• 55.6-U
55.6-U
78.4-U
63.9-U
65. -U
58.7-1
55. 3-D
56.3-U
45.3-1
68.8-U
72.7-U
43.5-U
48.6-U
77.0-U
80.6-U
88. 3-D
69.9-U
95.3-1
51.9-U
67.0-1
75.4-U
62.8-U
77.4-U
94.7-U
69.5-U
71.5-U
83.4-U
63.6-U
61 f ford
Pasqulll
Sta-
bility
Class11
452-D
58%-E
—
—
46%-D
49%-D
66%-D
48%-D
—
51S-D
41*-D
463S-D
46S-E
56%-D
70%-D
463S-D
51*-D
57%-D
—
—
57S-D
39%-D
59%-D
—
47%-D
48%-D
65SS-D
51J-D
66X-D
63X-D
HC/NOX
Ratio
.649
.071
.142
.438
.678
1.805
1.340
0.917
1.308
0.975
0.987
0.917
1.604
1.471
1.348
1.122
0.843
0.615
0.972
0.966
1.373
1.171
0.632
0.139
0.801
0.199
2.519
1.052
0.416
0.855
N02
(ug/m')
182
121
121
120
119
116
115
114
113
113
no
103
101
101
100
100
96
85
83
90
90
83
84
98
81
85
81
80
98
96
1 Hour
03e
(M/*1)
376
193
157
95
189
66
115
99
341
211
176
181
117
163
175
157
122
250
118
—
226
136
190
107
—
127
—
180
199
226
Solar
Insolation^
H
L
L
L
H
M
L
M
L
L
H
M
H
M
L
M
M
M
M
L
L
M
M
L
M
M
L
M
L
L
aM - Mobile
S - Stationary
Dominant source of NOX by fuel type, % of stationary source NOX emissions
6 - Natural Gas
0 - Oil
C - Coal
CU - Utility
I - Industrial
These values represent the percent occurrence of the dominant stability class within each AQCR.
eBasin average of 99 percentile measurements
Average dally solar Insolation:
H i 16.7 MJ/m2
M i 12.5 MJ/m2
L < 12.5 MJ/m2
7-16
-------
the third a relation between high mobile emissions and high ozone levels. None of these resulted in
a significant degree of correlation. For example, ozone formation is not simply a function of solar
insolation and HC/NOX ratios; other influences on the ozone formation mechanism have to be considered.
However, a reasonable set of groupings was obtained when the regions were separated into four groups
as shown in Table 7-4. The major criteria for this grouping are the mobile/stationary source mix,
the major stationary source type (utility or industrial), and the major fuel type for NO emissions.
It should be noted that all of these have direct bearing on the most suitable control methods for
effectively reducing NO emissions.
Group 1 represents regions that are dominated by stationary sources, with utilities as the
largest NOX emitters within the stationary category. Oil-fueled sources account for the greatest
portion of the stationary source emissions. This group is associated with high MO levels, high
HC/NOV levels, and moderate ozone levels.
X
Group 2 is also dominated by stationary sources with utilities as the largest stationary
source, but here coal-fueled sources are the dominant emitters of NO . These regions show moderate
N0v levels, medium HC/NO ratios and relatively low ozone levels.
X A
Group 3 is similar to group 2 except that these AQCRs have high NO levels and high
A
HC/NOX ratios.
Finally, Group 4 is dominated by mobile sources. These regions are characterized by high NO
levels, high HC/NO ratios, and very high ozone levels. The ozone levels are not unexpected, as
mobile source emissions usually contain high concentrations of precursors for photochemical smog.
7.1.2.3 Selection of the Regions
One region is selected to represent each of the four groups. The choice is primarily dependent
upon how well the individual AQCR represents the group as a whole, and on the quality and availability
of emissions and ambient concentration data. The four AQCRs are given below:
• Group 1 - New York City
• Group 2 - Saint Louis
• Group 3 - Chicago
t Group 4 — Los Angeles
For the preliminary screening of control technologies this group was further reduced to Los
Angeles and Chicago. These are logical choices for a limited analysis; they are the two most N0x
7-17
-------
TABLE 7-4. CHARACTERISTIC GROUPS OF NOX IMPACTED AQCRs and AQMAs
1. Stationary - Oil - Utility
New York City
Richmond
Boston
Philadelphia
2. Stationary - Coal - Utility
St. Louis
Louisville
Cincinnati
Minneapolis
Steubenville
Memphis
Charleston
Lansing0'
Pittsburg
Youngstown
3. Stationary - Coal - Utility
Chicago
Canton
Detroit
Milwaukee
4. Mobile
Los Angeles
San Diego
Baltimore
Salt Lake City
Springfield
Denver
Phoenix
San Francisco
Atlanta
Dayton
Washington
N0xa
H
H
H
H
M
M
M
M
M
M
M
M
M
M
H
H
H
M
H
H
H
H
H
H
H
H
H
H
H
HC/NOxb
H
H
H
H
M
M
H
M
I
M
L
H
L
M
H
H
H
H
H
H
H
H
H
H
H
H
H
H
H
Ozonec
M
L
L
L
M
L
L
L
L
—
L
L
L
L
L
L
--
H
L
L
L
H
M
L
L
L
M
L
aHigh: NOX >L 100 yg/m3; Medium: NOX < 100 yg/m3.
bHigh: HC/NOX > 0.9; Medium: 0.45 < HC/NOX <. 0.9; Low: HC/NOX < 0.45.
cHigh: 300 <. Ozone < 400 yg/m3; Medium: 200 <_Ozone < 300 yq/m3;
Low: 100 £ Ozone < 200 yg/m3.
Lansing is shown in Table 7-3 to be industrial dominated. Since no utility
emissions were reported, it was decided to place Lansing in Group 2. ,
7-18
-------
critical AQCRs in the United States (see Table 7-2), and they represent two opposite categories
with respect to the impact of stationary source control strategies -mobile source dominated versus
stationary source dominated. Saint Louis and New York City may be assessed in subsequent analyses.
7.1.3 Summary of Input Data and Evaluation Matrix
The various inputs to the systems analysis model for the two AQCRs are described in this
section. They are grouped into the following categories:
• Base year NO emissions and fuel use
• Base year N02 ambient concentrations
• Future year growth projections
• Fuel costs
• Stationary source controls
The input data and a brief discussion of how the values were selected are given for each category.
The section concludes with a description of the various scenarios which were investigated with the
preliminary screening model.
7.1.3.1 Base Year NOX Emissions and Fuel Use
The base year for all calculations was 1973, the most recent year for which complete emissions
data are available from a variety of reference documents. Primary sources for fuel use and emissions
data this year were the 1973 NEDS Annual Fuel Summary Report and the 1973 National Emission Report
(Reference 7-15). Copies of the relevant data from these sources are included in Appendix B. As
described below, these data were checked for consistency with each other and were compared with simi-
lar data from other sources (References 7-16 through 7-20).
Consistency was checked first by comparing the emissions and fuel use data from all the data
sources. This check was made for each source category, e.g., oil-fired utility power plants. If
any major discrepancy in emissions was found among the data sources, the fuel use data were compared
and, upon acceptance, used with an assumed emission factor to calculate the emissions. For example,
it is known that reported emissions associated with process gas are often in error fay as much as an
order of magnitude. This is due to the greatly varying heat content of the gas and the use of inap-
propriate emission factors. Therefore, all such emissions were checked for consistency. The NEDS
fuel use and emissions information for electric utilities were also routinely checked against the
FPC fuel use reports (Reference 7-18). This category is such a large contributor that it deserves
7-19
-------
a verification, especially when a simple one is available. Furthermore, since many power plants
in the Los Angeles AQCR implemented some combustion modification (LEA or OSC) for NOX control in
1973, emissions were calculated from FPC fuel use data and actual emission factors as reported in
Reference 7-19.
All source categories were checked in a similar manner. If there were any remaining, unex-
plained discrepancies, the EPA Regional Office or appropriate Air Pollution Control District was con-
tacted. By this procedure a reasonably consistent set of fuel use-emissions data was established
for each AQCR.
The emission source categories were initially selected to be identical to those in the NEDS
reports. Individual source categories are necessary in order to account for distinct growth patterns
and reductions by control for each category. The NEDS categories were judged to be sufficient in all
cases except industrial point source external combustion and electric generation point sources. In
these cases, it was desirable to distinguish between various boiler sizes and types. Also, source
categories with small emissions or for which little or no control information is available were often
combined. The source categories and their 1973 emissions and fuel use are given in Table 7-5 for
Los Angeles and Table 7-6 for Chicago.
7.1.3.2 Base Year N02 Ambient Concentration
Ambient concentrations for the base year were used to calibrate the air quality model. The
calibration was then used to relate emissions to ambient concentration in all future year calcula-
tions. Since the N02 standard is based on the maximum observed annual average throughout the AQCR
for any calendar year, it was deemed reasonable to use this value for the calibration. However,
other averages, such as the rolling quarter average,* have also been suggested as a more representa-
tive basis for a standard. Maximum values of the 12-month average for the Los Angeles and Chicago
AQCRs are given in Tables 7-7 and 7-8, respectively. These values are based on averages from one
calendar year, several calendar years, or the largest rolling quarter average during a 3-year
period. The range of values reflects changes in both emissions and meteorological conditions.
Another consideration in the selection of the ambient concentration for calibration of the
model is that the meteorological conditions of the base year are "frozen" into the calibration.
Although these conditions do not change muchi on the average, over the 20-year periods being consid-
ered here, year-to-year fluctuations in weather can cause ambient concentrations to vary by as much
*
The rolling quarter average is the 12-month average for any four consecutive quarters.
7-20
-------
TABLE 7-5. 1973 NOX EMISSIONS AND FUEL USE FOR LOS ANGELES, AQCR 024
Source
Electric Utilities
Peaking
<50 MW
50 MW - 180 MM
>180 MW
Industrial
1C Engines
'• Ext. Comb. — Large
Ext. Comb. - Small
Area
Industrial Process
Commercial /Institutional
Residential
Furnaces
Other
Solid Waste/Mi sc.
Mobile
Total
NOX Emissions (N02 Basis)
Gg/yr
0.462
3.529
11.308
64.156
14.796
2.891
2.891
12.412
34.505
19.886
9.926
2.586
3.758
353.112
536.237
Gg/yr
79.455
32.990
34.505
19.886
12.512
3.758
353.112
536.237
Percent
14.8
6.2
6.4
3.7
2.3
0.7
65.9
100
Fuel Use (PJ/yr)
Oil
0.0359
13.87
41.23
311.0
3.V9
3.19
8.48
3.147
55.75
439.9
Natural Gas
3.135
4.949
37.11
103.7
9.357
9.599
9.599
45.93
18.64
236.5
231.0
141.5
850.9
Process Gas
20.17
20.17
40.34
Gg = 109 grams = 1.1023 x 103 tons
PO = 1015 Joules = 0.947 x 10U Btu
-------
TABLE 7-6. 1973 N0¥ EMISSIONS AND FUEL USE FOR CHICAGO, AQCR 067
A
I
10
ro
Source
Electric Generation
Coal Firing Boilers
011 Firing Boilers
G.T. (Peaking Unit)
Other Pt. Source
Industrial
Water tube Boilers
Flretube Boilers
Area and Other Pt.
Sources
Industrial Process
Co«erc1al/Inst1tut1onal
Residential
Furnaces
Other
Solid Haste
Mobile
Total
NOX Emissions (NO? Basis)
Gg/yr
167.73
12.28
4.52
4.30
84.59
23.90
28.29
41.34
21.39
13.51
1.67
6.33
249.21
659.06
Gg/yr
188.83
136.78
41.34
21.39
15.18
6.33
249.21
659.06
Percent
28.65
20.75
6.27
3.25
2.30
0.96
37.82
100
Fuel Consumptions (PJ/yr)
Oil
33.54
30.96
93.49
28.63
28.63
36.23
20.24
.75.04
36.39
12.79
395.94
Natural Gas
13.50
45.92
45.92
184.22
60.17
132.98
278.16
97.74
858.61
Coal
357.34
49.11
26.08
1.91
5.43
15.19
455.1
Process Gas
9.81
249.84
259.65
Gg = 10* grains • 1.1023 x 10' tons
PJ = 10" Joules = 0.947 x 10" Btu
-------
TABLE 7-7. MAXIMUM ANNUAL AVERAGE NO? CONCENTRATION,
LOS ANGELES, AQCR 024
yg/ms
Method
150
141
132
182
Average for 1970-1974 (Reference 7-11)
Calendar Year 1974 (Reference 7-12)
Calendar Year 1973 (Reference 7-13)
Rolling Quarter 1972-1974 (Reference 7-14)
TABLE 7-8. MAXIMUM ANNUAL AVERAGE N02 CONCENTRATION,
CHICAGO, AQCR 067
yg/m3
Method
lisa
121
133
Calendar Year 1974 (Reference 7-12, 26 Observations)
Rolling Quarter 1972-1974 (Reference 7-14)
Calendar Year 1974 (Reference 7-12, 8,283 Observations)
Max. of Calendar Year 1972-1974 (Reference 7-29)
The highest valid value for any station in 1973 was 76 yg/m3
(Reference 7-14). The stations reported here did not have enough
observations to be valid in 1973. However, they have retained
their high levels in later years. These values for 1974 are
therefore considered reasonable to use for 1973.
TABLE 7-9. ANNUAL AVERAGE N02 CONCENTRATION USED FOR
MODEL CALIBRATION (yg/m3)
AQCR
Los Angeles 024
Chicago 067
Nominal
132
96
Alternate
160
120
7-23
-------
as 20 percent, even though emission patterns remain the same. Changes in meteorological conditions
could be partially accounted for by changing the calibration, which can be done easily by changing
the base year ambient concentration. This was not deemed necessary, because a suitable range of
ambient levels is provided by the various averages given in Tables 7-7 and 7-8.
Two values of the ambient concentration, given in Table 7-9, were selected for each AQCR.
The nominal value was taken to be the 1973 calendar year average. The alternate value was selected,
to represent the opposite end of the range of values in Tables 7-7 and 7-8. Consideration of both
values will account for alternate averaging methods and perhaps any meteorological differences. In
this way the sensitivity of the results to the calibration of the model can be evaluated.
7.1.3.3 Future Year Growth Projections
Stationary Sources
The uncontrolled emissions for future years were projected from fuel use growth rates. The
assumption was made that in the absence of any further controls, emissions from each source category
would grow at the same rate as fuel use in that category. Growth rates for fuel use were taken from
References 7-21 through 7-26. Generally, these growth rates apply to an end use sector (industrial,
residential, etc.); however, in this case they were extended to apply to each source within the sec-
tor. Whenever possible, growth rates specific to the AQCR were used. In the absence of these rates,
state, regional or national rates were used. In addition, the influence of population growth and any
local limitations on new source growth were considered.
Two scenarios for each AQCR were used. The nominal case represents a moderately conservative
growth influenced by conservation measures and rising energy costs. This case is considered to be
the "most likely to occur" case. The alternate case represents a higher growth rate situation,
which is closer to historical growth patterns. The growth rates used for the two AQCRs for the
years 1985 and 2000 are discussed below.
The two basic sources of growth projections for the Chicago AQCR are the Ford Foundation energy
study (Reference 7-23) and Federal Power Commission projections (Reference 7-24). The nominal growth
case is similar to the "technical fix" case described in Reference 7-23. This case represents a con-
scious effort to improve energy efficiency, and a moderate dependence on nuclear power for electricity
generation. The growth rates and total growth for the years 1985 and 2000 are given in Tables 7-10
and 7-11.
The high growth case for Chicago is similar to the "historical growth" case of Reference 7-23.
The growth rates and total growth for 1985 and 2000 are given in Tables 7-10 and 7-11. In this case
7-24
-------
TABLE 7-10. AVERAGE GROWTH RATES IN ANNUAL FUEL
USE FOR STATIONARY SOURCES IN CHICAGO,
AQCR 067
Sector
Electricity Generation
Industrial •
Commercial
Residential
1973-1985 %/yr
Nominal
Oa
3.3
2.9
-0.1
High
1.8
4.4
2.8
0.3
1985-2000 %/yr
Nominal
1.5
3.3
1.5
-1.3
High
3.7
3.2
0.8
0.2
Growth in electrical demand is expected to be met by an
increase in nuclear capacity for the short term.
TABLE 7-11. INCREASE IN FUEL USE IN FUTURE YEARS
FOR CHICAGO, AQCR 067, 1973 BASE
Source Type
Utility Boilers - Coal
Utility Boilers - Oil
Peaking G.T.
Industrial
Commercial
Residential
1973
1.0
1.0
1.0
1.0
1.0
1.0
1985
Nominal
1.034
0.959
1.0
1.434
1.371
0.989
High
1.104
1.8919
1.0
1.612
1.355
1.032
2000
Nominal
1.379
1.096
1.0
2.345
1.710
0.828
High
2.228
1.397
1.0
2.607
1.532
1.063
This large increase is contrary to the trend toward coal; however, oil is
a small fraction of the utility fuel budget. Commonweath Edison confirmed
their plans to build several new oil-fired power plants.
7-25
-------
there is substantial growth in nuclear power* and an increasing trend toward electrification. In
some cases, this trend will result in less fossil fuel consumption than in the nominal case.
The major sources of fuel use growth projections for the Los Angeles AQCR are References 7-21,
7-25, 7-26, and 7-27- In addition, the population growth of 1.1 percent/year and the New Source Re-
view Rate, SCAPCD Rule 213, were considered. Rule 213, in particular, will severely limit the growth
of NO emissions from industrial and utility point sources.
Both the nominal and the high cases are composites of the scenarios described in the references
given above. The nominal case is a reasonable blend of the "medium" type growth projections and the
expected influence of local regulations. The high case tends to represent a high growth scenario
with effective local regulation (Rule 213). The growth rates and net growth for the various source
categories are given in Tables 7-12 and 7-13.
In most cases, it is not sufficient merely to account for the source growth since a new type
of equipment with significantly different emission characteristics may become available. This possi-
bility has been allowed for by identifying the year of introduction of the new equipment and the
lifetime of the existing equipment. Starting from the year of introduction, existing equipment is
retired at a constant rate over its lifetime, and new equipment is added to make up the difference
between the overall source growth and the remaining old equipment. Figure 7-2 illustrates how a
typical source is divided. Retirement rates used in this analysis are given in Table 7-14. The
emission characteristics of the new equipment may be the same as the old, or they may be improved
depending upon the level of control desired or required.
Mobile Sources
Emissions from mobile sources have been treated in a different manner than those from sta-
tionary sources. The primary reason is that a detailed investigation of mobile source control op-
tions is not of direct interest to this study. What is needed is the emissions contribution of the
mobile sources for a few representative scenarios. One scenario has been selected to reflect his-
torical growth in vehicle population and miles traveled and a moderate emission standard. This is
taken as the nominal case. The alternate, or low, case is for a reduced growth rate, closer to the
population growth rate, and an emission standard of 0.25 g/km.
*
The national growth in nuclear power given in Reference 7-23 is considerably modified by FPC projec-
tions in the Chicago AQCR.
In effect this rule would prohibit an increase in basin-wide NOX emissions from specified source
categories.
7-26
-------
TABLE 7-12.
AVERAGE GROWTH RATES IN ANNUAL FUEL
USE FOR STATIONARY SOURCES IN LOS
ANGELES, AQCR 024
Source
Utility -Oil
Utility Peaking
Industrial
Commercial
Residential
1973-1985 %/yr
Nominal
1.0
0.5
2.0
2.6
1.2
High
1.7
0.5
2.0
4.3
2.6
1985-2000 %/yr
Nominal
-1.35
0.5
1.0
3.0
0.3
High
0
0.5
1.0
3.9
2.65
TABLE 7-13. INCREASE IN FUEL USE IN FUTURE YEARS
FOR LOS ANGELES, AQCR 024; 1973 BASE
Source Type
Utility Oil
Utility Peaking
Industrial
Commercial
Residential
1973
1.0
1.0
1.0
1.0
1.0
1985
Nominal
1.12
1.06
1.26
1.36
1.16
High
1.22
1.06
1.26
1.66
1.36
2000
Nominal
0.92
1.14
1.47
2.12
1.21
High
1.22
1.14
1.47
2.94
2.02
7-27
-------
c
o
3
Q.
O
CL
C
OJ
3
CT
1.0
1973
Tf
Time (yrs)
TO
Tf
A
B
year of introduction of new equipment type
T0 + equipment lifetime
portion of source that is old equipment
portion of source that is new equipment
Figure 7-2. Distribution of a source into new and old equipment.
-------
TABLE 7-14. EQUIPMENT RETIREMENT RATES
Equipment Type
Utility Boilers
Large Industrial Boilers
Small Industrial Boilers
Commercial Boilers
1C Engines
Small Commercial Furnaces— Oil
Residential Furnaces— Oil
Residential Furnaces - Gas
Small Commercial — Gas
Life Time (yr)
50
35
33
33
50
25
25
20
20
Retirement Rate %/yr
2.0
2.9
3.0
3.0
2.0
4.0
4.0
5.0
5.0
7-29
-------
A description of both scenarios for the two AQCRs is given in Table 7-15. The emission stan-
dard and year of introduction, and the annual growth for the categories considered are shown. The
emission standards for Chicago are representative of federal standards. Those for Los Angeles re-
flect the current and proposed standards for California.
The mobile source emissions for both scenarios and both AQCRs are given in Table 7-16. De-
tails of how the standards and growth rates were ased to calculate annual emissions are given in
Appendix C. For vehicles, the following factors were considered:
• Number of vehicles
• Age distribution
• Average miles traveled
• Emission factor by model year
In addition, the emission factors were adjusted for deterioration with age and for average trip
speed. (It is interesting to note the increasing significance of the "other" category. Much of
this is from rail, ships, construction vehicles, and other off-road vehicles. It is often argued
that these emissions do not significantly contribute to urban air quality.)
7.1.3.4 Fuel Costs
Part of the cost of many controls is the increase or decrease in fuel use as a result of im-
plementing the control method. Therefore, current and projected fuel costs must be input into the
program. Fuel costs for 1973 were obtained primarily from FEA (Reference 7-22) and FPC News (Refer-
ence 7-28). Cost projections to 1985 are based on the "$13/bbl reference case" of Reference 7-22.
Beyond 1985 fuel cost projections are very uncertain. It may be expected that the relative cost of
energy will continue to increase; however, government price controls could stabilize the cost.
Therefore, fuel prices in the year 2000 were assumed equal to the 1985 price with two exceptions.
In Los Angeles, the price of industrial natural gas was increased to equal that of industrial oil.
In Chicago, the price of industrial oil was increased to equal that of industrial coal. Both of
these "equalizations" were done to remove a cost advantage of the "limited" fuel. Fuel costs are
given in Tables 7-17 and 7-18 in 1976 dollars.
7.1.3.5 NOV Controls and Control Costs
A
This subsection summarizes the data on NOV control techniques and control costs which are in-
A
put to the preliminary screening model. For each equipment/fuel combination, an existing or emerging
7-30
-------
TABLE 7-15. MOBILE SOURCE EMISSION FACTORS (g/km) AND ANNUAL GROWTH RATES
<1972
1972
1973
1974
1975
1977
1978
1980
1981
1985
1990
1995
2000
Annua'
Growth
Rate
Nominal
LDVC
Calif a
2.9
1.9
1.9
1.2
1.2
0.93
0.93
0.62
Fed
2.9
2.9
1.9
1.9
1.9
1.2
0.93
0.62
LDTC
Calif
2.9
1.9
1.9
1.2
1.2
1.2
1.2
0.93
0.62
Fed
2.9
2.9
1.9
1.9
1.9
1.2
1.2
0.93
0.62
3.5X
Air-
craft"
z
0
rt-
§
3
.30
d.
0
rt-
O
z
3
IX
Low
LDVC
Calif
2.9
1.9
1.9
1.2
1.2
0.93
0.93
0.62
0.25
Fed
2.9
2.9
1.9
1.9
1.9
1.2
0.93
0.62
0.62
0.25
LDTC
Calif
2.9
1.9
1.9
1.2
1.2
0.93
0.93
0.62
0.25
Fed
2.9
2.9
1.9
1.9
1.9
1.2
0.93
0.62
0.62
0.25
•
IX
Air-.
craftb
o
CD
0>
rt-
o'
3
.30
TO
ro
o.
c
n
^f
o
.40
Q-
r>
o'
.50
ro
a.
c
o
o'
t
IX
Both Cases/Both AQCRs
HDGC
11.7
11.7
11.7
11.7
7.0
5
IX
HDDC
27.4
27.4
22.8
22.8
13.7
9.8
IX
Rail, ships, etc.
z
o
3
Id
c
o> '
o'
3
IX
aReference C-ll
Reference C-23
CLDV - light-duty vehicles, LOT - light duty trucks, HDG - heavy-duty gasoline,
HDD - heavy-duty dlesel.
-------
TABLE 7-16. MOBILE SOURCE NOX EMISSIONS (All Values in Gg/yr Expressed as N02)
--J
OJ
LDV
LOT
HDG
HDD
Aircraft
Other
Total
Los Angeles - AQCR 024
107 3
224.0
27.7
20.2
25.3
4.8
51.6
353.6
1985
Nominal
84.5
12.9
12.2
9.6
3.8
59.8
182.8
Low
40.2
5.6
12.2
9.6
3.7
59.8
131.2
2000
Nominal
121.0
13.6
8.8
9.2
4.4
69.5
226.5
Low
24.9
2.8
8.8
9.2
3.1
69.5
118.3
Chicago - AQCR 069
1Q7'3
155.0
6.7
12.2
26.5
35.9
13.4
249.7
1985
Nominal
61.0
3.9
7.3
10.0
28.5
15.1
125.8
Low
44.6
1.8
7.3
10.0
28.3
15.1
107.1
2000
Nominal
81.4
3.9
5.2
9.6
32.8
17.6
150.5
Low
17.0
0.6
5.2
9.6
23.5
17.6
73.5
-------
TABLE 7-17. FUEL COSTS IN THE CHICAGO AQCR, 1973-2000
Fuel Costs
Utility
Coal
Oil
Natural Gas
Industrial
Coal
Oil
Natural Gas
Process Gas'3
Commercial
Coal
Oil
Natural Gas
Residential
Coal
Oil
Natural Gas
Fuel Costs ($/GJ)a
1973
0.77
1.38
1.01
0.83
0.87
2.39
0.87
1.36
2.34
1.15
1.58
2.34
1.42
1985
0.93
1.55
3.96
1.40
0.96
4.05
0.96
2.00
2.64
2.18
2.34
2.65
2.41
2000
0.93
1.55
3.96
1.40
1.40
4.05
1.40
2.00
2.64
2.18
2.34
2.65
2.41
aFuel costs are in 1976 dollars.
bThe cost of industrial process gas was
arbitrarily set equal to the cost of
industrial oil.
7-33
-------
TABLE 7-18. FUEL COSTS IN THE LOS ANGELES AQCR, 1973-2000
Fuel Type
Utility
Low Sulfur
Oil
Natural Gas
Industrial
Oil
Natural Gas
Process Gasb
Commercial
Oil
Natural Gas
Residential
Natural Gas
Fuel Costs ($/GJ)a
1973
2.49
0.74
2.00
0.77
0.77
2.42
1.14
1.36
1985
2.81
2.87
2.17
1.21
1.21
2.72
2.39
2.50
2000
2.81
2.87
2.17
1.21
1.21
2.72
2.39
2.50
Fuel costs are 1976 dollars.
The cost of industrial process gas was
arbitrarily set equal to the cost of
industrial natural gas.
7-34
-------
control technology is identified as being capable of achieving a given NO emission level. In addi-
tion, the differential costs associated with the control technology are presented. For the most part,
these data are compiled from the information in Section 4 of this report. As noted there, good,
reliable cost data for many -NOX control techniques are not available. In those cases where this is
so, best projected estimates are made based on the available data.
Control costs and other process data are presented in Tables 7-19 through 7-27 for the follow-
ing equipment/fuel combinations:
• Coal-fired utility boilers (Table 7-19)
• Gas- and oil-fired utility boilers (Table 7-20}
• Coal-fired industrial watertube boilers (Table 7-21)
• Gas- and oil-fired industrial watertube boilers (Table 7-22)
• Gas- and oil-fired industrial firetube boilers (Table 7-23)
• Gas- and oil-fired residential furnaces (Table 7-24)
• Gas turbines (Table 7^25)
• 1C engines (Table 7-26)
t Industrial process furnaces (Table 7-27)
It was assumed that most stationary combustion sources of NOX can be divided into these categories
(the exceptions number only a few). The data presented represent expected typical ranges or average
values over the entire spectrum of firing types and sizes within each category.
For a given NO emission level, the tables present a single or combined control technique
capable of achieving that level, taking into account effectiveness, cost, availability, applicability,
and operational impact. Environmental problems, however, were not considered in arriving at these
selections. In those cases where the "earliest year available" is blank, the technology is consid-
ered available now. The differential control costs are shown in terms of both initial investment
and annual costs in 1976 dollars. The annual costs include the differential costs of capital, raw
materials, maintenance, and utilities. However, they do not include the cost associated with a
change in fuel consumption. The effect on fuel consumption is tabulated separately in each table
in accordance with the earlier discussion on the cost model (see Subsection 7.1.1.2)." Details on
other cost assumptions are discussed in Section 4.
Two other NO control methods not mentioned in these tables are ammonia injection and oil de-
nitrification. Ammonia injection is an emerging technology projected to be commercially available
7-35
-------
TABLE 7-19. COST OF NOX CONTROLS FOR COAL-FIRED UTILITY BOILERS3
CO
CT1
New or
Existing
Equipment
Existing0
Newd
Emission
Level
(ng/J)
344
301
258
215
172
129
Control
Technique'3
LEA
LEA + OSC
LEA + OSC
Advanced Design 1
Advanced Design 2
Advanced Design 3
Earliest
Year
Available
~
—
1982
1984
1987
1990
Differential Control Costs
Initial Investment
($/kW)
0.6
1-1.5
0.2
0.5-1
1-2
2-7
Annual Cost
($AW)
0.1
0.2-0.3
<0.1
0.1-0.2
0.2-0.5
0.5-1.2
Effect on
Fuel Consumption
<1% decrease
<1% increase
--
--
--
--
aAmmonia injection may also be used with any of the combustion modification control methods. This results in
an additional 50 percent reduction in NOX emissions.
See Section 4 for control technique characterization.
cThe emissions level for existing uncontrolled units is assumed to be 387 ng/J.
^The emissions level for newly constructed units is assumed to be 301 ng/J.
-------
TABLE 7-20. COST OF NOX CONTROLS FOR GAS- AND OIL-FIRED UTILITY BOILERS3
New or
Existing
Equipment
Existing0
New
Emission
Level
(ng/J)
215
143
107
Control
Technique^
LEA
LEA + OSC
LEA + OSC + F6R
Earliest
Year
Available
—
—
--
Differential Control Costs
Initial Investment
($/kW)
0.3
0.5-1
6-12
Annual Cost
($/kW)
<0.1
0.1-0.2
1-2
Effect on
Fuel Consumption
<1% decrease
1% increase
~\% increase
No new units
Ammonia injection may also be used with any of the combustion modification control methods. This results in
an additional 50 percent reduction in NOX emissions.
See Section 4 for control technique characterization.
cThe emissions level for existing uncontrolled units is assumed to be 258 ng/J.
-------
TABLE 7-21. COST OF NOX CONTROLS FOR COAL-FIRED INDUSTRIAL WATERTUBE BOILERS3
to
oo
New or
Existing
Equipment
Existing*1
Newd
Emission
Level
(ng/J)
193
172
189
163
129
Control
Technique'3
LEA
LEA + OSC
LEA
LEA + OSC
Advanced Design
Earliest
Year
Available
—
—
--
1980
1985
Differential Control Costs
Initial Investment
($/(kg/hr))c
22
55
15
44
110-176
Annual Cost
($/(kg/hr))c
4.9
11.
3.3
8.8
22-35
Effect on
Fuel Consumption
1% decrease
<]% increase
1% decrease
--
--
Ammonia injection may also be used with any of the combustion modification control methods. This results in
an addition 50 percent reduction in NOX emissions.
See Section 4 for control technique characterization.
ckg/hr — kg steam per hour
The uncontrolled emissions level is assumed to be 215 ng/J.
-------
TABLE 7-22. COST OF NO* CONTROLS FOR GAS- AND OIL-FIRED INDUSTRIAL WATERTUBE BOILERSa
i
to
vo
New or
Existing
Equipment
Existing*1
Newd
Emission
Level
(ng/0)
120
108
116
103
66
64
43
Control
Technique"
LEA
LEA + OSC
LEA
LEA + OSC
Advanced Design ]
Advanced Design 2
Advanced Design 3
Earliest
Year
Available
--
--
~
1978
1981
1983
1985
Differential Control Costs
Initial Investment
($/(kg/hr))c
22
44
18
33
55
73
88-154
Annual Cost
($/(kg/hr))c
4.4
8.8
3.3
6.6
11
14.3
18-31
Effect on
Fuel Consumption
1% decrease
<1% increase
1% decrease
—
--
--
~
Ammonia Injection may also be used with any of the combustion modification control methods. This results in
an additional 50 percent reduction in NOX emissions.
See Section 4 for control technique characterization.
ckg/hr - kg steam per hour.
The uncontrolled emissions level is assumed to be 129 ng/J.
-------
TABLE 7-23. COST OF NOX CONTROLS FOR GAS- AND OIL-FIRED INDUSTRIAL FIRETUBE BOILERS
-J
o
New or
Existing
Equipment
Existing0
Newc
Emission
Level
(ng/J)
108
77
108
86
65
43
Control
Technique3
LEA
LEA + FGR
LEA
LEA + FGR
Advanced Design 1
Advanced Design 2
Earliest
Year
Available
--
--
--
1978
1981
1985
Differential Control Costs
Initial Investment
($/{kg/hr))b
0.66
3.7
0.44
1.59
2.41
3.3
Annual Cost
($/(kg/hr))b
0.13
0.66
0.09
0.31
0.48
0.66
Effect on
Fuel Consumption
1% decrease
<1% increase
1% decrease
~
--
—
aSee Section 4 for control technique characterization.
bkg/hr - kg steam per hour.
cThe uncontrolled emissions level is assumed to be 129 ng/J.
-------
TABLE 7-24. COST OF NOX CONTROLS FOR GAS- AND OIL-FIRED RESIDENTIAL FURNACES
New or
Existing
Equipment
Existing11
Newb
Emission
Level
(ng/J)
None
26
17
8.6
Control
Technique3
New Burner
Advanced Design 1
Advanced Design 2
Earliest
Year
Available
1978
1981
1984
Differential Control Costs
Initial Investment
($/kW)
1.37-2.05
2.05-3.42
3.42-5.11
Annual Cost
($/kW)
0.14-0.29
0.29-0.4
0.32-0.68
Effect on
Fuel Consumption
5% decrease
7% decrease
~\Q% decrease
See Section 4 for control technique characterization.
The uncontrolled emissions level is assumed to be 43 ng/J.
-------
TABLE 7-25. COST OF NOX CONTROL FOR GAS TURBINES
i
*•
ro
New or
Existing
Equipment
Existi ngb
New5
Emission
Level
(ng/J)
120
120
86
43
Control
Technique3
Water Injection
Water Injection
Advanced Design 1
Advanced Design 2
Earliest
Year
Available
—
—
1981
1984
Differential Control Costs
Initial Investment
($/kW)
3-20
3-20
10-30
20-50
Annual Cost
($/kW)
0.5-2
0.5-2
2-6
4-10
Effect on
Fuel Consumption
}% increase
1* increase
—
—
See Section 4 for control technique characterization.
The uncontrolled emissions level is assumed to be 172 ng/J.
-------
TABLE 7-26. COST OF NOX CONTROLS FOR 1C ENGINES
I
4*
U)
New or
Existing
Equipment
Existing
Newb
Emission
Level
(ng/J)
1,053
1,338
737
Control
Technique3
Fine Tuning,
Changing A/F
Fine Tuning,
Changing A/F
Advanced Design
Earliest
Year
Available
--
1980
1983
Differential Control Costs
Initial Investment
($/kW)
--
--
13.40-26.80
Annual Cost
($/kW)
0.67-2.01
0.54-1.30
2.70-5.40
Effect on
Fuel Consumption
10% increase
5% - 10% increase
--
See Section 4 for control technique characterization.
The uncontrolled emissions level is assumed to be 1,504 ng/J.
-------
TABLE 7-27. COST OF NOX CONTROLS FOR INDUSTRIAL PROCESS FURNACES
New or
Existing
Equipment
Existing
New
Emission
Level
(ng/J)
258
172
258
129
86
Control
Technique3
LEA
LEA + F6R
LEA
Advanced Design 1
Advanced Design 2
Earliest
Year
Available
—
1978
—
1981
1987
Differential Control Costs
Initial Investment
($/kW)
1.01
5.80
0.68
3.74
5.11
Annual Cost
($/kW)
0.22
1.01
0.14
0.76
1.01
Effect on
Fuel Consumption
1% decrease
1% increase
1% decrease
~
—
aSee Section 4 for control technique characterization.
-------
in the period 1981 through 1983. It is seen to have applicability to utility and large industrial .
watertube boilers with typical NOX reductions of about 50 percent of the existing emission level.
Annual costs have been estimated at $5/kW to $10/kW and 0.88 $/(kg/hr)* to 1.98 $/(kg/hr) for utility
and industrial boilers, respectively. A major portion of these costs is the charge for ammonia.
There seems to be no significant effect on fuel consumption.
Denitrification usually accompanies desulfurization of oil. The nitrogen content of the oil
is reduced such that NO reductions of 10 to 40 percent from baseline can be achieved. Desulfuriza-
A
tion typically adds $0.8 to $1.7 per barrel to the cost of residual or crude oil. Denitrification
as a NOX control method is applicable to residual oil-fired utility and large industrial boilers.
The annual control costs are given in terms of cost per unit output (8.9 $/kW). In order to
utilize these values in the systems analysis it is necessary to estimate the average unit size in
each of the various source categories. The most effective procedure for doing this is to estimate
an average annual capacity factor for each source type and combine this with the fuel use. This re-
sults in a total installed capacity for the particular source (total capacity = annual fuel use x
annual capacity factor). From this the total cost to control the source can be calculated (example:
total capacity in MW x $/MW for the control method = total cost of the control method).
7.1.3.6 Evaluation Matrix
In order to adequately assess the level of emission reduction required to meet the N02 stan-
dard in 1985 and 2000 many combinations of the growth scenarios and base year calibrations could be
considered. These combinations would all be derived from variations of the following four basic fea-
tures:
• Stationary source growth rate
• Mobile source growth rate
• Values of the base year ambient concentration used for calibration of the air quality model
• Value of the source weighting factors for power plants and mobile sources
The first three of these have been discussed previously. The purpose of varying the source
weighting factor is to evaluate the sensitivity of the results to the significance, or weighting,
given to a particular source category. For example, it may be that because power plants emit from
high stacks, a portion of their NOX emissions does not contribute to the ambient N02 concentration in
the AQCR. This may be due to transport out of the AQCR or different NO to N02 conversion rates for
ground level and elevated sources. Therefore, it is of interest to examine what impact a reduction
*
kg of steam per hour
-------
in the significance of power plant emissions has on the results. Conversely, it has often been
argued that mobile source emissions are a more significant contribution to high ambient N02 levels
than other sources, since they emit both oxidant precursors (recall that HQ^ is formed from N0x dur-
ing the photochemical process) at the same elevation as the primary receptors. Therefore, the im-
pact of increasing the significance of the mobile sources was also considered.
The evaluation matrix is a combination of two parts. The first part consists of the various
combinations of growth scenarios for stationary and mobile sources and whether or not control of
stationary sources is attempted. A description of each of these cases considered is given in Table
7-28. The same combination of scenarios was used for both Los Angeles and Chicago, and is considered
to bracket all reasonable combinations of growth scenarios for mobile and stationary sources.
The second part of the evaluation matrix is formed from combinations of the base year ambient
concentration and the source weighting factors. A change in the base year concentration is used to
examine the sensitivity of the results to assumptions made in identifying this level. It also seems
to show the sensitivity of the results to moderate changes in source-receptor spatial relations due
to growth or the application of controls. This portion of the evaluation matrix is given in Tables
7-29 and 7-30. For each entry in these tables all the cases in Table 7-28 were evaluated. The re-
sults for this matrix of simulations for the years 1985 and 2000 are discussed in the following
section.
7-1.4 Results
The preliminary screening model was utilized to compute ambient concentrations and required
levels of control using the assumptions described in Section 7.1.3. The results of these calcula-
tions are presented and discussed in this section. Only a limited number of cases, selected as repre-
sentative of the entire matrix of cases, will be described. The results are not intended to be pre-
dictions of future ambient concentration, because the limitations of the model and the uncertainty
of the input data preclude such expectations. Rather, the results are indicative of the effective-
ness of and the need for control of various sources.
Two types of results are described. The first is the ranking of the controls in order of
cost-effectiveness. This is intended to provide guidance for the development of control methods and
strategies. The second is an indication of the degree of control required to meet the annual stan-
dard. These results on the extent of control implementation to attain and maintain the standard are
also compared with conclusions from similar studies.
7-46
-------
TABLE 7-28. EVALUATION MATRIX, GROWTH SCENARIOS
Nominal growth for all sources
Controls applied to meet std of 100 yg/m3 in 1985, 2000
AN Nominal growth for all sources
No controls beyond those in use as of 1976
AM Nominal growth for stationary sources
Low growth mobile sources
Controls applied to meet std of 100 yg/m3 in 1985, 2000
AH High growth for all stationary sources
Nominal growth for mobile sources
Controls applied to meet std of 100 yg/m3 in 1985, 2000
7-47
-------
TABLE 7-29. EVALUATION MATRIX: BASE YEAR CONCENTRATION AND
SOURCE WEIGHTING FACTORS FOR LOS ANGELES
Power Plant
Weighting Factor3
1
2
3
4
5
6
7
8
1.0
1.0
0.7
1.0
0.7
0.7
1.0
0.7
Mobile
Weighting Factor
1.0
1.0
1.0
1.2
1.2
.1.0
1.2
1.2
Base Year (1973)
Ambient Concentration
132
160
132
132
132
160
160
160
For Los Angeles a power plant weighting factor of 0.7 was selected
as a lower value for power plant sources. This was because the
inversion layer above Los Angeles deflects emissions back into the
air basin, thereby partially off-setting the effect of elevated
sources. Thus, a significant reduction in weighting for power
plant emissions would not be expected.
7-48
-------
TABLE 7-30. EVALUATION MATRIX: BASE YEAR CONCENTRATIONS
AND SOURCE WEIGHTING FACTORS FOR CHICAGO*
1
2
3
4
5
6
7
8
Power Plant
Weighting Factor
1.0
1.0
0.5
0.2
1.0
1.0
0.5
0.2
Mobile Weighting
Factor
1.0
1.2
1.2
1.0
1.0
1.2
1.2
1.0
Base Year (1973)
Ambient Concentration
(yg/m3)
96
96
96
96
120
120
120
120
aDispersion of emissions from high stacks may have a very pro-
nounced effect on the impact of elevated sources in the Chicago
AQCR. For these sources Yeager (Reference 7-30) has suggested
a source weighting factor of 0.356 as appropriate for nonreac-
ting species for regions such as Chicago. Consequently, two
reduced values of the power plant weighting factor were con-
sidered.
7-49
-------
7.1.4.1 Ranking of Controls
The order in which controls are applied by the screening model is based on the cost per unit
reduction in ambient concentration. As explained in Section 7.1.1 this approach allows for considera-
ion of the impact of each source/control combination on the ambient air quality. It differs, however,
from the customary method of evaluating the cost-effectiveness of controls based on the reduction in
emissions. For the air quality model used here, these two approaches yield the same result if all
source weighting factors are equal. In the present analysis power plant weighting factors less than
1.0 and mobile source weighting factors greater than 1.0 are also considered. This has the effect
of reducing the cost-effectiveness of power plant controls, i.e., the cost per unit reduction in
ambient concentration increases. In both Los Angeles and Chicago this results in a moderate shift
downward of the power plant control in the overall control ordering. Control rankings for Los Angeles
and Chicago are given in Tables 7-31 and 7-32 for the year 2000 and for equal source weighting fac-
tors. Although the ranking is based on changes in ambient concentration the percent reduction listed
for each control is the reduction of the uncontrolled emissions.* The controls have been divided
into three groups according to their cost-effectiveness. Control levels will be described in terms
of which group of controls is required to meet the ambient standard. Group I consists of all the
controls that result in a net dollar savings. These include modifications to residential and small
commercial furnaces and most low excess air controls. The net savings results from the decrease in
fuel consumption associated with the control method. Group II contains the combustion modification
controls that require hardware changes — off-stoichiometric combustion, flue gas recirculation, etc.
In some cases these controls are applied in conjunction with some from Group I, e.g., low excess air
plus off-stoichiometric combustion. The last set of controls, Group III, consists of the addition
of ammonia injection to those controls in Group II for which this technique is applicable.
Tables 7-31 and 7-32 show that, with the exception of residential and small commercial furn-
aces, the maximum reduction in stationary source NOV emissions by combustion modification is about
X
20 to 60 percent. The addition of ammonia injection increases this to 50 to 80 percent. It should
also be noted that there are no controls for two potentially significant source categories - indus-
trial processes and large commercial sources. These were omitted primarily because of the extremely
*
New equipment types with factory-installed NOX controls are included as control methods. The cost
associated with new equipment designs is that portion of the cost attributable to the NOx control
features (i.e., excludes R&D costs as these may be subtotaled in the estimate of the initial cost of
the equipment).
+
'Commercial sources were divided into two groups -one that represents furnaces similar to residential
furnaces, although larger; the other "large sources" consist of firetube boilers, large forced air
heaters, and other miscellaneous types. For the purposes of control the latter group was considered
too diverse to assign specific control methods.
7-50
-------
TABLE 7-31. CONTROL PRIORITIZATION FOR LOS ANGELES
(2000, EQUAL SOURCE WEIGHTING)
Rank
1 <
f i
2
3
4
5
6
7
V. 8
II <
9
10
11
12
13
14
15
16
17
18
19
20
,21
( 22
III ) 23
1 24
Us
Source/Control
RES. FURN NEW BURNER
SM COMM FURN NEW D.
IND (WTB) LEA
SM COMM FURN A.D. #1
COMM/ INST FURN A.D. #2
RES. FURN A.D. #1
RES. FURN A.D. #2
IND (FTB) LEA
SM PP LEA+OSC
1C ENGINES ADO A/F
aMED PP TO 250 PPM
1C EHG.-NEW ADJ A/F
1C ENG.-NEU A.D.
3LA PP TO 250 PPM
SM PP LEA+OSC+FGR
1C ENGINE-EGR
aCCGT-NEW-H20 INJ
CCGT-NEU A.D. #1
CCGT-MEW A.D. #2
IND (WTB) LEA+OSC
IND (FTB) LEA+FGR
LA PP C.M.+NH3 INJ
MED PP C.M.+NH3 INJ
SM PP C.M.+NH3 INJ
IND (WTB) C.M.+NH3
Cost Per Unit
Change in Air Quality
106$/(ug/m3)
-15.4
-14.6
-13.9
-12.7
-13.3
-11.4
-11.3
- 3.67
1.57
2.18
2.43
2.48
0.305
2.50
2.74
4.10
4.13
3.38
3.94
5.00
6.57
6.74
7.59
8.25
13.4
* Red/Unit
40
40
7
60
80
60
80
17
45
30
16
11
51
16
58
20
30
50
75
17
40
79
79
79
42
in
CO
Required to meet present legislated emission levels.
A.D. -Advanced design
C.M. - Combustion modifications (LEA, OSC, FGR)
COMM - Commercial
CCGT - Combined cycle gas turbine
EGR - Exhaust gas recirculation
FGR — Flue gas recirculation
FTB - Firetube boiler
FURN - Furnace
H20 INJ - Water injection
I, IND - Industrial
INST - Institutional
LA - Large
LEA - Low excess air
HED - Medium
OSC - Off-stoichiometric combustion
PP — Power plant
RES - Residential
SM -Small
WTB - Watertube boiler
7-51
-------
TABLE 7-32. CONTROL PRIORITIZATION FOR CHICAGO
(2000 EQUAL SOURCE WEIGHTING)
Rank
1
I <
"<
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
/ 29
III
30
, 31
32
33
34
35
:36
Source/Control
RES. NEW BURNER
RES. FURN A.D.iH
RES. FURN A.D.I2
SM COMM FURN NEW D
SM COMM FURN A.D.#1
SM COMM FURN A.D.#2
IWTB-OIL LEA
N IWTB-C LEA
N IWTB-0 LEA
IWTB-COAL LEA
PP-OIL LEA
N IFTB-0 LEA
IFTB-OIL LEA
PP-COAL LEA
N PP-C LEA+OSC 1982
N PP-C A.D.#2 1987
PP-COAL LEA+OSC
N IFTB-0 LEA+FGR
N IWTB-0 LEA+OSC
N IWTB-0 A.D.#2 1983
N IWTB-C LEA+OSC
N IFTB-0 A.D.#2 1985
PP-OIL LEA+OSC
IWTB-COAL LEA+OSC
N IWTB-C A.D.fl 1985
IFTB-OIL LEA+FGR
PP-OIL LEA+OSC+FGR
IWTB-OIL LEA+OSC
IWTB-COAL C.M.+NH3
PP-COAL C.M.+NH3
N PP-C A.D.#2+NH3
N IWTB-0 A.D.I2+NH3
PP-OIL C.M.+NH3
N IWTB-C A.D.+NH3
IWTB-OIL C.M.+NH3
G.T. (PEAK) H20 INJ
Cost Per Unit
Change in Air Quality
106$/(pg/m3)
-43.8
-40.2
-38.3
-20.5
-18.6
-19.7
- 3.98
- 3.47
- 2.94
- 2.62
- 0.923
- 0.673
- 0.408
- 0.397
0.294
0.335
0.709
0.789
0.821
0.712
0.918
1.01
1.04
1.76
1.79
1.94
1.97
2.39
4.29
4.51
4.56
5.22
5.25
6.14
6.46
11.16
% Red/Unit
40
60
80
40
60
80
6
12
10
10
16
17
17
11
14
43
22
40
20
50
24
67
45
20
40
40
58
17
60
55
71
75
79
70
58
30
N - New
C - Coal
0 - Oil
A.D. -Advanced design
C.M. -Combustion modifications (LEA, OSC, FGR)
COMM - Commercial
CCGT - Combined cycle gas turbine
EGR - Exhaust gas recirculation
FGR - Flue gas recirculation
FTB - Firetube boiler
FURN - Furnace
H20 INJ -Water injection
I, IND - Industrial
INST - Institutional
LA — Large
LEA - Low excess air
MED - Medium
OSC - Off-stoichiometric combustion
PP - Power plant
RES -Residential
SM - Smal1
WTB -Watertube boiler
7-52
-------
diverse equipment types in these categories. Control costs and emission reduction information would
be little more than guesswork. Certainly there is potential for reduction in both categories; how-
ever, omission of control methods did not have significant impact on the conclusions. To verify
this, all the cases were run with a specified reduction in emissions from these two categories of
20 percent in 1985 and 60 percent in 2000. The result was to slightly decrease the control level
necessary to meet the ambient standard. In most cases one or two fewer other sources required control.
In Tables 7-31 and 7-32 there are a few entries that appear to be out of order. For example,
in Table 7-31 entry number 13 is more cost effective than the preceding entries. This is a conse-
quence of the ranking process in the screening model. Second generation advanced designs of new
equipment were forced to follow the new design in ranking. (In the example above, Entry 13 is the
second generation advanced design for internal combustion engines.) This was done for two reasons.
The first, and most obvious, is that the new design will be available before its own second genera-
tion and should therefore be given first consideration. The second is that the need for a second
generation advanced design can be assessed independently of its relative cost advantage. If the
new design did not provide sufficient reduction there would be some incentive to accelerate develop-
ment of more advanced designs.
Figures 7-3 and 7-4 show the cumulative cost and reduction in ambient concentration resulting
from the application of the controls in the order given in Tables 7-31 and 7-32 respectively. The
location of most of the controls is indicated on the figures. The most striking feature of both fig-
ures is that the cumulative net cost for stationary control, up to ammonia injection, is negative.
This result is heavily dependent upon the fuel savings or fuel penalties assigned to the control
methods and upon the price of fuel. The major contributions (>60 percent) to the cost savings are
the second generation advanced designs for residential and commercial furnaces (10 percent fuel
savings). Without these two the break-even point occurs at a much lower level of control. This
strongly suggests that the improved designs for these two sources should be vigorously promoted not
only for the emission reduction but also for the significant fuel and cost savings potential.
Another interesting feature of these figures is that the total reduction in ambient concen-
tration from all the controls is clearly evident. Those source/control combinations which have the
7-53
-------
O
o
-------
+J
1C
in
o
o
10
15 20 25 30 35
Cumulative reduction in ambient concentration
40
45
Figure 7-4. Cumulative cost and reduction in ambient concentration for application of the
controls in Table 7-32 (preliminary process data, Chicago, 2000, nominal
growth, 1973 concentration = 96 ug/m3).
-------
greatest reduction potential can be easily identified.* This information is more useful than cost
effectiveness along in setting priorities for standards or control development.
The results and implications of Figures 7-3 and 7-4 are considered to be very tentative at
this point and are critically dependent upon the process and cost information, the modeling assump-
tions, the growth scenarios, and the source weighting factors.
Control rankings such as those discussed above are created for each case of the evaluation
matrix. These rankings are then used to establish the level of control needed for each case. These
results are discussed in the following paragraphs.
7.1.4.2 Ambient Air Quality
The overall purpose of the preliminary screening effort is to identify the extent of combus-
tion modifications that are likely to be needed in the future to attain and maintain NO -related
A
ambient standards. Results from this analysis are, therefore, presented in terms of the general
degree of control required to meet the annual average NOo standard. This method of presenting the
results is used to avoid obscuring comparisons of the various cases by the details of exactly
which control methods are required. The degrees of control (0, 1, 2, 3; see Table 7-33) are
defined in terms of the groupings given in Tables 7-31 and 7-32.
Results for approximately half of the cases described in the previous section (Section 7.1.3)
are presented here. These represent the extremes of the base year ambient concentrations, the two
mobile growth and control scenarios, the two stationary source growth scenarios, and the case of re-
duced power plant impact and increased mobile impact. These cases effectively bound all the scenarios
examined. Differences in results between these cases and those not discussed are minor.
The results for Los Angeles are given in Table 7-33. For each combination of growth scenario,
base year concentration and source weighting factor, the required level of control for both 1985 and
2000 is shown. The most obvious conclusion is that the control level required is dominated by the
assumptions on the mobile source emissions. This is not really surprising since mobile sources
accounted for 66 percent of the NOX emissions in 1973. In the low mobile case the combination of
low growth (1 percent per year) and stringent controls (0.25 g/km in 1981) results in a 63 percent
*
The distance along the horizontal axis in Figures 7-3 and 7-4 is a measure of the potential impact
on ambient concentration of each control method. It is a combination of the total emissions con-
tribution of the source and the effectiveness of the control method. In the case of combinations
of controls (LEA+OSC) or improvements in design (second generation) only the additional improvement
is credited to the method.
7-56
-------
TABLE 7-33. SUMMARY OF CONTROL LEVELS REQUIRED TO MEET N02 STANDARD IN LOS ANGELES, AQCR 024
r
in
Case
Nominal Growth
Low Mobile
High Stationary
BYR = 132 yg/m3
PP = 1.0
MS = 1.0
1^""^
^"3
C 1^^
^^"0
2^-"^
^•^v
PP = 0.7
MS = 1.2
°^^
^^
0 /^""
^U
^^^
/^*
BYR = 160 ug/m3
PP = 1.0
MS = 1.0
3 1^"""
^^
2>^
^l
3>^^^
^v
PP = 0.7
MS = 1.2
3^/^"
^^V
°^^^
^§
V^^
^^V
0 — No additional control required
1 -Controls from Group I
2 — Controls from Groups I and II
3 — Controls from Groups I, II, and III
V - Violation of NAAQS, insufficient controls to meet ambient
standard
1985.
2000
PP - Power plant weighting factor
MS - Mobile source weighting factor
BYR - Base year ambient concentration for calibration
-------
reduction in mobile emissions in 1985 and a 66 percent reduction in 2000. This more than offsets the
growth in stationary sources and results in a net reduction in total emissions of 36 percent and 38
percent respectively. This level of reduction is enough to achieve the ambient standard except in
the 160 pg/m3 base year case. Even in the nominal mobile case, a slight increase in the weighting
of the mobile sources has significant impact in 1985.
In contrast to the low mobile cases, maximum control is needed for all other cases in 2000,
and also for the high base year ambient concentration case in the near term (1985). Both of these
are again consequences of the dominance of the mobile sources -control of the stationary sources
cannot yield sufficient emission reduction to offset growth and the large mobile source emissions
contribution.
These results strongly suggest that all possible stationary source control methods may have
to be implemented. According to the results discussed above, which admittedly are based only on N02
ambient goals, a less vigorous approach could be justified only if all of the most favorable assump-
tions were valid (i.e., low base year concentration, low mobile growth, strict and effective mobile
control, and validity of the higher mobile weighting assumption). It is unreasonable to expect that
all of this will happen and imprudent to plan1control development on such an assumption. For the
short term the current combustion modification control technology might be sufficient if a favorable
mobile situation exists. For the longer term, however, all the advanced control methods presently
considered should be pursued, including ammonia injection, and research on even more effective
methods seems justified.
The results for Chicago are shown in Table 7-34. Control of stationary sources is required
in all cases except for 1985 if the base year (1973) concentration of 96 yg/m3 is appropriate. The
principal reason for this (no control in 1985) is that the reduction in mobile source emissions*
counterbalances the growth in stationary sources. For example, in the nominal growth case, mobile
source emissions in 1985 are 123 Gg below their 1973 level; whereas, stationary sources have in-
creased by only 112 Gg. In the high stationary growth case, however, an increase of 154 Gg for sta-
tionary sources in 1985 is enough to require a small amount of control. Even with the low base year
concentration the complete range of combustion modification controls is needed in the year 2000.
For the high base year concentration cases combustion modifications and ammonia injection are not
always sufficient, and even in the low mobile case combustion modification controls are needed.
*
Mobile source emissions in 1985 are reduced by 50 and 57 percent of the 1973 level for the nominal
and low mobile cases, respectively.
7-58
-------
TABLE 7-34. SUMMARY OF CONTROL LEVELS REQUIRED TO MEET N02 STANDARD IN CHICAGO, AQCR 067
Ul
<0
Case
Nominal Growth
Low Mobile
High Stationary
BYR = 96 yg/m3
PP
MS
1.0
1.0
PP = 0.5
MS = 1.2
PP
MS
0.2
1.0
BYR = 120 yg/m3
PP
MS
1.0
1.0
PP = 0.5
MS = 1.2
PP
MS
0.2
1.0
0 — No additional control required
1 - Controls from Group I
2 - Controls from Groups I and II
3 — Controls from Groups I, II, and III
V - Violation of NAAQS, insufficient controls to meet ambient standard
2000
PP — Power plant weighting factor
MS -Mobile source weighting factor
BYR - Base year ambient concentration for calibration
-------
(The 1973 mobile emissions constitute 38 percent of the total; consequently, mobile emissions are
not as dominant as in Los Angeles.)
The conclusions for the Chicago AQCR are essentially the same as for Los Angeles. For the
long term all combustion modifications will be required and, in some cases, will not be sufficient
to meet the annual standard. In the short term, combustion modifications are needed unless the low
base year concentration is valid (see Section 7.1.3.2 for a discussion of this value).
These conclusions can be qualitatively extended to many of the AQCRs identified in Table
7-2 as Priority AQCRs and AQMAs. Those that are heavily mobile dominated (Group 4, Table 7-4)
will respond to stationary source control in much the same manner as Los Angeles. It is quite
likely that for these AQCRs, mobile source controls (0.63 g/km) would be sufficient for the short
term; however, combustion modifications to stationary sources would be required in the long term.
The stationary source dominated AQCRs, particularly those in the upper half of Table 7-2, will
likely require combustion modifications, and perhaps ammonia injection, in both the near term and
far term.
7.1.4.3 Comparison with Related Studies
The conclusions for the required control levels for both Los Angeles and Chicago are very
similar to those of other studies, for example, the DOT study (Reference 7-29) and an EPA study (Ref-
erence 7-30). Both of these studies reported that neither Los Angeles nor Chicago could achieve the
ambient standard with even maximum stationary source control and 0.25 g/km mobile controls. The re-
sults here indicate that it may be possible in favorable circumstances. The primary differences be-
tween the present analysis and the two cited above are in the growth rates and the base year ambient
levels for which the models were calibrated. The DOT study allowed stationary sources to grow at
3.9 percent per year. The EPA study considered 5 percent per year growth and a base year concentra-
tion of 182 pg/m3. Because of growth restrictions in Los Angeles (see Section 7.1.3.3), an effective
annual growth of about 1 percent per year for the aggregate of the stationary sources was used in
this work. In Chicago, electric power plant growth was much less than 3.9 percent, primarily be-
cause of growth in nuclear capacity. These factors account for the difference between never meeting
the standard and possibly meeting the standard. These differences also help to illustrate the in-
fluence of the basic assumption (growth rate, base year concentration, and source weighting factors)
on the quantitative results. However, the following qualitative conclusions remain the same.
7-60
-------
7-1.4.4 Conclusions
The conclusions of this portion of the analysis can be summarized as follows:
t NOX controls for residential furnaces and small commercial furnaces yield substantial
reductions in fuel use and can significantly effect the break-even point in the cost
for stationary source control strategies
• The order in which controls should be implemented is significantly influenced by the fuel
savings features of the control method and, of course, the availability of the technology
• For the short term, combustion modifications for stationary sources will be needed for
most of the priority AQCRs. Both retrofit and "new design" controls should be developed -
particularly those that also result in an energy savings
• For the long term, all combustion modifications and ammonia injection will be required.
This is probably the case even for the minimum mobile source emissions case (low growth,
0.25 g/km).
7.2 SUMMARY OF SOURCE/CONTROL PRIORITIES
This section combines the results of Section 7-1 with those of other sections to set NO E/A
program priorities on sources and source/control combinations. The source priorities will be used
to determine the order in which the process engineering and environmental assessment studies will be
conducted for the major source categories (utility boilers, industrial and commercial boilers, gas
turbines, commercial and residential warm air furnaces, 1C engines and industrial process combustion
equipment). The source priorities will also guide the level of effort to be devoted to the study of
each major source category and to individual design types within the category. These studies will
"focus primarily on near-term source/control applications; far-term application of emerging technology
will be studied later in the program. The source/control priorities will be used to determine which
source/control combinations will be given major or minor emphasis in the near-term process studies
and which will be emphasized in the far-term studies. The source/control priorities will also guide
the field test program. Other factors such as site availability and the potential for teaming ar-
rangements will also have a significant role in the test priorities.
The source prioritization used the following sequence:
• Subdivide major source categories (utility boilers) into source/fuel categories (coal-
fired utility); further subdivide to major design types (tangential) likely to be exten-
sively controlled for NO , and minor design types (vertical) not likely to be extensively
controlled due to dwindling use and/or lack of control flexibility
7-61
-------
• Assess the extent to which controls are in use or are planned for each source/fuel cate-
gory
• Rank source/fuel categories on basis, of nationwide mass emissions of NOX
t Assess the relative baseline environmental impact potential for each source/fuel category
• Identify the relative effectiveness of near-term and far-term source control implementa-
tion in maintaining 'air quality in urban areas
Table 7-35 summarizes the results of this prioritization sequence. The prioritization is largely
qualitative due to the uncertainty and lack of data in these areas. The considerations which were
made in constructing Table 7-35 are summarized below.
Source Categorization
The division of the source/fuel category into major and minor design types used the results
of Section 2 of this report. The major design types are those, which in the near-term, will be
subject to NO controls. The designation "major" implies a design type will be given primary empha-
sis in the process studies and is a candidate for the field test program. The minor design types
are either obsolete or difficult to control and therefore unlikely to be subject to significant NOX
controls. The minor design types will be given secondary emphasis in the process studies and will
not be candidates for field tests. It should be noted that minor design types are not necessarily
insignificant sources of NO . For example, cyclone boilers emit 8 percent of stationary source NO
X A
and rank fourth among all stationary source design/fuel combinations (see Table 5-33). Yet, the
cyclone combustion characteristics make them very difficult to control for NO . Their sale has
been discontinued and it is unlikely many existing units will be controlled for NO . Other consider-
ations made in the source categorization are as follows:
• Vertical- and stoker-fired utility boilers are obsolete; although they are amenable to
some control, the current application is insignificant
• Firebox and horizontal return tube package firetube boilers are dwindling in use in favor
of the scotch design; the vast majority of new sales to meet the planned NO standard
will be of the scotch design
• Firetube stokers are dwindling in number due to cost
• The use of NOX controls on space heaters in the near term is unlikely
• Insufficient data are available to divide industrial process combustion equipment into
major and minor design types
7-62
-------
TABLE 7-35. EVALUATION OF NOX E/A SOURCE PRIORITIES
Source Category
Coal-fired utility
011-flred utility
Gas-fired utility
Coal-fired watertube
011 -fired watertube
Gas- fired watertube
Coal -fired flretube
01l-f1red flretube
Gas-fired flretube
Gas- and oil-fired
gas turbines
Gas- and oil-fired
warm air furnaces
Compression Ignition
1C engines (dlesel
fuel and mixed)
Spark Ignition
1C engines
Industrial process
combustion
Major
Design Types
In E/A Program
Tangential ,
single and
opposed wall-
fired, turbo
Same as above
Same as above
Pulv. Stoker-
spreader
Single and
multl burner
Single and
multlburner
Scotch
Scotch
Industrial ,
utility,
simple cycle
Res., Conn.
furnace
Turbocharged
Turbocharged
naturally
aspirated
Process heat-
ers, furnaces,
kilns
Minor
Design Types
1n E/A Program
Cyclone,
vertical,
stoker
Cyclone
Underfeed/
overfeed
Stoker
Firebox, HRT
Firebox, HRT
Comb, cycle
repowerlng
Space
heaters
Blower
scavenged
Degree of
Control
Implementation
All new sources, moder-
ate for existing sources
Extensive for existing
sources
Same as above
Low for existing,
Impending for new
Same as above
Same as above
Same as above
Same as above
Same as above
Moderate for existing
sources, Impending for
new sources
Increasing use for
energy conservation
Negligible for existing
sources; Intending for
new sources
Same as above
Negligible
Nationwide
NOv Emission
Ranking
1
4
3
5
10
7
14
6
9
11
12
8
2
13
Relative
Impact b
Potential"
H
M
L
H
M
L
H
M
L
L
L-M
L-M
L-H
M-H
Source
Need/Effe
Near term
H
H
H
H
H
H
M
H
H
H
H
H
H
M
Control .
:t1veness
Far term
H
L
L
H
H
M-L
L
H
M-L
H-N
H-M
M-L
M
M-H
Source
Ranking
1n E/A
Program
1
3
8
2
6
11
14
5
12
4
7
10
9
13
"Major refers to sources likely to be controlled for NOx; minor refers to sources for which controls are unlikely to be Implemented 1n the near term.
bH > high; M = medium; L - low
-------
The growth projection and design trends taken from Section 2 for this prioritization are preliminary.
They will be studied in greater detail later and Table 7-35 will be updated as necessary.
Control Implementation
The information for the "Degree of Control Implementation" column on Table 7-35 is taken from
Section 4.1. Since the assessment of current controls application is a major objective of the N0x
E/A, the degree of control implementation is a dominant criteria in setting source priorities. To
date, the vast majority of stationary combustion source NOX controls has been on utility boilers.
Gas and oil units have been the most extensively controlled, but an increasing number of standards
have been set recently for coal units. No new gas- or oil-fired units are being sold, so N0x controls
for coal units via the New Source Performance Standards (NSPS) will dominate in the future. Other
sources with current control applications are large industrial boilers and gas turbines. NSPS are
also planned for these sources along with 1C engines. The lead time for implementing the standard
and delivering new unit orders is typically several years. Thus, the degree of control application
for these sources will not be comparable to that for utility boilers in the near term. This
fact alone is sufficient to rank utility boilers as the top priority in the N0x E/A.
Nationwide Emission Ranking
The ranking of design/fuel types by nationwide mass emissions of NOX is given in Table 5-33.
These results have been consolidated on Table 7-35 for the specific source categories listed there.
Nationwide mass emissions are useful for weighting relative emission contributions of various sources
and detecting emission trends independent of local variations. They are used within the EPA to set
priorities on emission standards. Use of nationwide emissions does suffer a drawback, however, in
that it does not account for variations among source categories in proximity to population centers
and variations in regional use of specific source/fuel types. These factors were qualitatively
included in the relative impact potential column. These factors will be quantified later in the
NO E/A and used for a formal ranking of sources according to pollution potential.
Relative Impact Potential
The ranking of sources by relative impact potential was based on the multimedia emissions
inventory of Section 5 and the evaluation in Section 7.3 of potential adverse impact of these emis-
sions. Although impacts due to NO controls were not considered in the evaluation, the results 'Of
X
Section 6 were useful in relating design type and fuel to potential for emissions of specific pol-
lutants (e.g., organic emissions from 1C engines) where firm emission data were sparse. Additionally,
7-64
-------
the proximity of specified sources (e.g., residential furnaces) to populated areas was also consid-
ered. As shown on Table 7-35, the relative impact potential resulting from the above considerations
was generally high for coal firing, medium for residual oil firing, and low with the firing of clean
fuels. The borderline L-M for residential furnaces resulted from the proximity of these sources to
populated areas and the potential for increased emissions during cycling transients. 1C engines were
also a borderline case. Even though they fire clean fuels, the emissions of organics are much higher
than for other sources. Little emission/impact data are available for industrial process furnaces.
They were rated M-H on the basis of fuel use.
Effectiveness of Source Control in Air Quality Maintenance
These criteria are based on the results of the air quality screening analysis discussed in
Section 7-1. Separate consideration is given to near-term effectiveness and to far-term effectiveness
in order to isolate effects of design trends and growth projections for source categories. The
analysis in Section 7.1 showed that the need for bringing specific source categories under control
is highly uncertain. The estimated control needs were found strongly dependent on growth projections,
assumptions on future mobile source control, measurements of ambient concentrations of NO-, and the
relative weighting of the NO^ air quality impact emissions from point sources (power plants) and
ground level sources (mobile sources). These factors are all in a state of flux. Assuming optimistic
resolution of these factors (in terms of stationary source air quality impact), only moderate control
of major stationary sources will be needed in the near term (1985). Assuming moderate or pessimis-
tic resolution of these factors, however, implies the need for extensive near-term control of station-
ary sources. In the far term (2000), extensive control is generally needed regardless of assumption.
For purposes of setting priorities in the NO E/A program, the estimated control needs for moderate or
pessimistic assumptions are used. This is because the NOX E/A is largely a problem definition study
and its purposes would not be served by using optimistic assumptions on the potential for adverse
impact. For the moderate or worst case scenarios, the estimated near-term control needs, as shown
on Table 7-35, are generally high for all source categories. For the far term, the needs are focused
on extensive control of new sources. Thus, sources with dwindling new sales due to design trends or
fuel availability are derated in the far term. As expected, the trend is for increasing use of coal
and oil and decreasing use of gas. The projected availability of clean fuels for industrial sources
and gas turbines will be examined in more detail later in the program.
Overall Source Ranking
The final column on Table 7-35 gives a qualitative ranking of the 13 source/control categories.
In deciding this ranking, the degree of control implementation and the relative impact potential were
7-65
-------
given the most weight. Based on this ranking, the process and environmental assessment studies in
the NO E/A will be conducted in the follov/ing sequence:
X
1. Utility and large industrial watertube boilers
2. Industrial and commercial packaged boilers
3. Gas turbines (simple cycle and combined cycle)
4. Residential and commercial warm air furnaces
5. Reciprocating internal combustion engines
6. Industrial process combustion equipment
Within each of these studies, the relative effort for specific source/fuel categories will follow
the order of ranking of Table 7-35.
The source prioritization discussed above is extended on Table 7-36 to include consideration
of specific source/control combinations. The table shows which source/control combinations are to re-
ceive major or minor emphasis in the six process studies of near-term applications listed above.
The table also shows preliminary selection of which advanced source/control combinations will be
evaluated in the later study of far-term applications. The prioritization of current technology
was based directly on the information in Section 4 (see Tables 4-26 and 4-27). The prioritization
considered the extent of current applications of specific source/control combinations and the cost
effectiveness of a given control compared to competitive techniques. Major emphasis will be given
to the vast majority of source/control combinations likely to see significant control in the next 5
years. The selection of advanced techniques for study in the far-term effort was also based on Sec-
tion 4. The developmental status and schedule as well as the potential availability of competitive
techniques were considered. The selection of advanced techniques also considered the results of
Section 7.1 which showed the need for advanced combustion modifications and, possibly, ammonia in-
jection in the 1980's and 1990's. Advanced techniques which are being covered by other assessment
efforts (e.g., fluidized beds, advanced cycles) will be given minor emphasis in the far-term effort.
7.3 POLLUTANT/IMPACT SCREENING
The source/control combinations prioritized in Section 7.2 are further evaluated here to
identify specific pollutants which may cause adverse environmental impact with or without NO con-
A
trols. These results will be used to set priorities for the sampling and chemical analyses to be
done during the later field test programs. The emphasis in the pollutant/impact screening is on
flue gas emissions. The data on liquid and solid effluent streams are very sparse. They will
7-66
-------
TABLE 7-36.
SUMMARY OF NOX E/A SOURCE/CONTROL PRIORITIES
Source
Ranking
1
3, 8
2
6. 11
14
5. 1Z
4
7
9
10
13
Source
Coil-fired utility
boilers, existing
Co*1-f1red utility
boilers, new
01l-f1red, gas-
fired utility
boilers
Coal -fired water-
tube, Industrial-
pulverized
Coal-fired water-
tube Industrial -
stoker
011-flred. gas-
fired watertube
Coal-fired fire-
tube stoker
Oil-fired, gas-
fired flretube
Sas- * oil-fired
gas turbines
Gas- t oil-fired
warn air furnace
Spark Ignition 1C
engines
Compression Igni-
tion 1C engine
(diesel. mixed fuel
Industrial process
combustion
NEAR TERN EFFORT IN E/A PROGRAM: CURRENT AND IMPENDING APPLICATIONS
Major Emphasis -
Sources1
Tangential, opposed 1
single wall, turbo-fired
Sane as above
Sane as above
Single or multlburner
wall-fired
Spreader
Single or mUlburner
wall-fired
Scotch
Utility. Industrial
simple cycle
Residential, commercial
furnaces
Turbocharged. natural-
ly aspirated
Turbocharged
Process heaters,
furnaces, kilns
Major NO. E/A
Emphasis - Controls
LEA. BBF. BOOS. OFA.
low-NOx burners
LEA 1 OFA; 1ow-NOx
burners, enlarged
firebox
LEA. BBF, BOOS, OFA.
F6R
LEA, BBF. BOOS. OFA.
low-NOx burners
LEA, OFA
LEA, OFA. low-NOx
burners
LEA, FGR. OFA. low-
NOx burners
Hater Injection
Low-NOx burners
Operational tuning,
reduced Inlet air
temperature
Operational tuning
LEA, load reduction,
RAP. FGR. H20
Injection
Minor NOX E/A
Emphasis — Sources
Cyclone, vertical
stoker
Cyclone
Underfeed/overfeed
Firebox, horizontal
return tube
Firebox HRT
Combined cycle,
repowerlng
Space heaters
Blower scavenged
Low-NOx burners
Minor NO, E/A h
Emphasis - Controls"'0
FGR. RAP. H»0 inj..
load reduction,
NH3 injection
FGR, RAP, H20 Inj..
NHa injection
RAP, HzO Inj., NHs
Injection
Load reduction
Load reduction
LEA
Load reduction
Can modifications
EGR. derate
Derate
FAR TERM EFFORT IN E/A PROGRAM:
ADVANCED TECHNOLOGY
Major
Emphasis
NH3 Injection
Advanced OFA
techniques;
adv. low-NOx
burners, NH3
Injection
Advanced low-
NOx burners,
NH3 Inj.
Advanced low-
NOx burners,
advanced OFA,
NH3 injection
Factory
Installed
OFA. NH3 Inj.
Adv. low-NOx.
burners, adv.
OFA, NH3 Inj.,
alt. fuels
Adv. low-NOx
burners, adv.
OFA, alt. fuels,
catalytic comb.
Adv. can design,
comb, cycles,
alt. fuels.
catalytic comb.
Adv. burner/
firebox des.,
alt. fuels.
catalytic comb.
Chamber redesign,
alt. fuels
Chamber redesign
alt. fuels
loH-NO, burn-
ers. OFA,
alt. fuels
Minor
Emphasis
Flue gas
treatment;
fluldized
beds; adv.
cycles
Chemically
active
fluid bed
Exhaust
gas
treatment
I
o>
*Major refers to sources or controls emphasized In near term control programs; minor refers to sources or controls less likely to be used.
bLEA • low excess air; BBF • biased burner firing; BOOS • burners out of service; OFA • overflre air; FGR • flue gas reclrculatlon; RAP « reduced air preheat
-------
therefore be sampled during the test program to obtain the data needed for a pollutant/impact
screening such as done here for flue gas emissions.
The set of pollutant classes under consideration was described in Section 6 and includes carbon
monoxide, vapor phase hydrocarbons, particulates, sulfates, condensed phase organics, and trace
metals. Several of these classes can be further speciated into more detailed pollutant groups, which
give a better representation of potential health/welfare hazards, as was done in Section 3. For ex-
ample, the vapor phase hydrocarbon class is comprised of alkanes, alkenes, alkynes, aldehydes, car-
boxylic acids, and aromatics. (Of course sulfates, organics, and trace metals are generally emitted
as particulates, but the particulates class has been separately discussed because it is a criteria
pollutant, and because more emissions data on this class of pollutants are available.)
Baseline emissions for each pollutant species group, as a function of combustion source class,
were tabulated and discussed in Section 5. In addition, Section 6 tabulated (where data were avail-
able) and discussed the incremental emissions of these pollutant groups as a function of applied NO
combustion control. The health and welfare aspects of each species/group were discussed in Section
3 in terms of developing a set of maximum ambient screening concentrations. By combining information
developed in each of those sections with the dispersion model (which relates ground level pollutant
concentrations to single source emission levels as a function of combustion source) described in Ap-
pendix D, it is possible to flag the pollutants from each combustion source which represent poten-
tial environmental hazards due to applying NO controls.
Such a summary appears in Tables 7-37 and 7-38. Table 7-37 shows baseline emissions, typical
emission levels with NO controls, maximum ambient screening concentrations (from Section 3), and
derived maximum allowable emission level (from the dispersion model) for the pollutant groups under
consideration. The pollutant groups listed in Table 7-37 are those for which incremental emissions
data are available. Table 7-38 shows a similar summary for those pollutants groups for which little
or no field data exist on the incremental effects of NO combustion controls.
From the data presented in Tables 7-37 and 7-38, it is possible to identify those pollutant
groups which are emitted at levels near, or exceeding, the defined maximum allowable emission level.
For current purposes, pollutant group/combustion source combinations are flagged if emission levels
with NOV control data (Table 7-38), or baseline emissions in the absence of incremental NO control
A *»
data (Table 7-38) exceed 10 percent of the maximum allowable level. These combinations are noted
in Tables 7-37 and 7-38, and further summarized in Table 7-39.
7-68
-------
TABLE 7-37. COMPARISON OF POLLUTANT EMISSION LEVELS WITH NOX CONTROLS TO MAXIMUM ALLOWABLE EMISSIONS
Pollutant Class
Carbon Monoxide
Total Vapor Phase
Hydrocarbons
Partlculates
Combustion
Source
Utility Boilers
Industrial Boilers
Residential Units
1C Engines
Gas Turbines
Utility Boilers
Industrial Boilers
Residential Units
1C Engines
Gas Turbines
Utility Boilers
Industrial Boilers
Residential Units
1C Engines
Gas Turbines
Fuel
Natural Gas
Oil
Coal
All Fuels
Natural Gas
Oil
All Fuels
All Fuels
Natural Gas
Oil
Coal
Natural Gas
Oil
Coal
Natural Gas
Oil
All Fuels
All Fuels
Natural Gas
Oil
Coal
Natural Gas
Oil
Coal
Natural Gas
Oil
Oil
01 1 i Kerosene
Maximum
Ambient
Concentration
(ppb)
9,000
240
(mg/m>)
0.075
Maximum
Allowable
Emission Level
(ppm)
110,000
920,000
529,000
920,000
920,000
2,930
24,500
14,100
24,500
24,500
(g/m3)
0.91
7.65
4.41
7.65
7.65
Baseline
Emissions
(ppm)
23-175
25-46
23-96
0-110
40
90
90-10,300
53-970
0-35
0-30
0-40
10-25
0-15
10-90
20
25
60-4,600
0-230
(g/»3)
0.01
0.11
0.42-2.73
0.01
0.01-0.63
3.9-5.1
0.01
0.03
0.02-0.04
0.03-0.08
Emissions
with NOX
Control s
(ppm)
25-65
10-35
20-148
0-220
„
90-3,280
51-1,320
> 0-40
| 0-35
~
80-6,400
0-1 ,200
(g/«3)
0.60-2.6
<0.03
0.02-1.23b
7.5-10.0b
0.01
0.03
<0.26C
0.04-0.09d
Concern
Flag3
+
++
+
4-t
+ denotes emission with NOX controls greater than 10 percent of maximum emission level.
++ denotes emission with NOX controls greater than maximum emission level.
bNOx control by off-stoichiometric combustion.
CNOX control by exhaust gas recirculation.
NOX control by derating.
-------
TABLE 7-38. COMPARISON OF BASELINE POLLUTANT EMISSION LEVELS TO MAXIM ALLOWABLE EMISSIONS
Pollutant Class/Group
Vapor Phase Hydrocarbons'1
Alkanes
Alkenes
Alkynes
Aldehydes
Carboxylic Acids
Aromatics (benzene
and one-ring
derivatives)
»
Sul fates
Organics (POM's)
Anthracene
Phenanthrene
Combustion Source
Utility Boilers
Industrial Boilers
Utility Boilers
Industrial Boilers
Utility Boilers
Industrial Boilers
Utility Boilers
Industrial Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Utility Boilers
Industrial Boilers
Residential Units
Utility Boilers
Industrial Boilers
Residential Units
Fuel
Natural Gas
Oil
Coal
Oil
Coal
Natural Gas
Oil
Coal
Oil
Coal
Natural Gas
Oil
Coal
Oil
Coal
Natural Gas
Oil
Coal
Oil
Natural Gas
Oil
Coal
Natural Gas
Oil
Coal
Natural Gas
Oil
Coal
Coal
Oil
Coal
Coal
Coal
Natural Gas
Oil
Coal
Coal
Maximum
Ambient
Concentration
(ppb)
4,420
59,500
62,700
2.1
13
0.002
(mg/m3)
0.002
(ppt)
0.14
4,000
Maximum
Allowable
Emission Level
(ppm)
54,000
450,000
725,000
Unlimited
765,000
Unlimited
25.6
214
159
0.024
(9/m3)
0.024
(ppb)
1.71
14.3
8.2
50,000
420,000
240,000
Baseline
Enissions
(ppm)
<80
<15
<10
<40
<150
<80
<15
<10
<40
<150
<5
<5
<10
<5
<10
5
5
<10
2.5-200
2.5
6-12
200
<20
<30
<50
(9/m3)
0
0.047
0.056
(ppb)
0.3
2
0.1-0.3
0.4-1,000
0.1-0.3
0.04
0.7-3.7
0.3-3
9-2,300
Concern
Flag"
4
+
+
++
++
++
•H-
++
++
++
+
+-f
++
+ denotes baseline emissions exceed 10 percent of maximum allowable level
++ denotes baseline emissions exceed maximum allowable level
Maximum ambient concentration and associated maximum allowable emission level for hydrocarbon
primary health hazards. Effects of secondary (derived) pollutants are not considered.
7-70
species consider only
-------
TABLE 7-38. CONTINUED
Pollutant Class/Group
Organic? (POM's) (Cent.)
Fluoranthrene
Pyrene
Benzo(a)pyrene
Benzo(e)pyrene
Perylene
Trace Metals
As
B
Ba
Be
81
Cd
Co
Combustion Source
Utility Boilers
Industrial Boilers
Residential Units
Utility Boilers
Industrial Boilers
Residential Units
Utility Boilers
Industrial Boilers
Residential Units
Utility Boilers
Industrial Boilers
Residential Units
Utility Boilers
Industrial Boilers
Residential Units
Utility Boilers
Fuel
Coal
Natural Gas
011
Coal
Coal
Coal
Natural Gas
Oil
Coal
Coal
Coal
Natural Gas
011
Coal
Coal
Coal
Natural Gas
Coal
Coal
Coal
Coal
Coal
Oil
Coal
Oil
Coal
011
Coal
Coal
Coal
011
Coal
011
Coal
Maximum
Ambient
Concentration
(PPt)
10.900
0.121
0.097
0.097
0.097
(ug/m3)
0.825
IE. 5
0.825
0.0033
16
0.00825
0.165
Maximum
Allowable
Emission Level
(ppb)
133.000
1,110.000
641 .000
1.48
12.4
7.1
1.2
9.9
5.7
1.2
9.9
5.7
1.2
9.9
5.7
(mg/m3)
10.1
201
10.1
0.04
195
1.01
2.0
Baseline
Emissions
(ppb)
0.003-0.5
0.04-3.4
0.02-1.8
0.8-10
13-350
0.01-0.5
0.5-7.5
0.005-2.2
0.6-4.5
2-2,500
0.003-0.1
0.006-0.1
0.006-0.3
0.007-2.2
0.008-800
0.007-0.15
0.006-0.5
0.02-1.7
1-330
0.005-0.015
0.35
0.1-770
(mg/m3)
0.004
0.45
0.068
3.41
0.52
0.65
0.52
0.03
0.006
0.12
0.27
0.11
Concern
Flag*
4-
+
+
+
•M-
+
++
•f
+
++
+•+
++
+
+
* + denotes baseline emissions exceed 10 percent of maximum allowable level
++ denotes baseline emissions exceed maximum allowable level
7-71
-------
TABLE 7-38. CONCLUDED
Pollutant Clsss/Group
Trace Metals (Cont.)
Cr
Cu
Hg
Mn
Mo
Hi
Pb
Sb
Se
V
Zn
Zr
Combustion Source
Utility Boilers
Fuel
Oil
Coal
Oil
Coal
Oil
Coal
Oil
Coal
Oil
Coal
Oil
Coal
Oil
Coal
Oil
Coal
Oil
Coal
Oil
Coal
Oil
Coal
Oil
Coal
Maximum
Ambient
Concentration
(vg/m3)
0.001
1.65
16.5
8.25
8.25
0.165
0.247
0.825
0.33
0.825
1.65
8.2
Maximum
Allowable
Emission Level
(mg/ms)
0.012
20.1
201
101
101
2.0
3.0
10.1
4.0
10.1
20.1
100
Baseline
Emissions
(mg/m3)
0.68
0.43
0.55
1.20
0.008
0.23
0.55
1.58
0.55
0.25
32
0.68
0.62
0.59
0.004
0.04
0.632
0.173
47.5
1.20
0.87
9.36
0.17
0.86
Concern
Flag"
++
++
++
+
+
+
++
++
+
+ denotes baseline emissions exceed 10 percent of maximum allowable level
++ denotes baseline emissions exceed maximum allowable level
7-72
-------
TABLE 7-39. SUMMARY OF POTENTIAL POLLUTANT/COMBUSTION SOURCE HAZARDS
Pollutant Class/Group
Vapor Phase Hydrocarbons
Total
Aldehydes
Carboxylic Acids
One-Ring Aromatics
Participates
Sul fates
Organics
Anthracene
Pyrene
Benzo(a)pyrene
Benzo(e)pyrene
Peryl ene
Trace Metals
Be
Cd
Co
Cr
Ml
Pb
V
Zn
Combustion Source
1C Engines
Utility Boilers, all Fuels
Oil-Fired Industrial Boilers
Coal -Fired Utility Boilers
Utility Boilers, all Fuels
Coal -Fired Boilers
Oil-Fired Industrial Boilers
Coal- and Oil-Fired Utility
Boilers
Oil-Fired Boilers
Coal-Fired Residential Units
Coal-Fired Utility Boilers
Coal-Fired Residential Units
Boilers, all Fuels
Coal-Fired Residential Units
Coal-Fired Industrial Boilers
Coal -Fired Residential Units
Coal -Fired Boilers
Coal -Fired Residential Units
Coal -Fired Utility Boilers
Coal-Fired Utility Boilers
Oil-Fired Utility Boilers
Coal- and Oil-Fired Utility
Boilers
Oil-Fired Utility Boilers
Coal -Fired Utility Boilers
Coal- and Oil-Fired Utility
Boilers
Oil-Fired Utility Boilers
Coal-Fired Utility Boilers
Coal-Fired Utility Boilers
Emission Exceeds
Potential Hazard
Threshold
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Emission Exceeds
10% of Potential
Hazard Threshold
X
X
X
X
X
X
X
X
X
X
X
X
X
7-73
-------
Table 7-39 illustrates that incremental emissions from large coal- and oil-fired boilers
potentially represent most significant environmental hazards. Baseline emissions of participate,
sulfates, and certain POM species from this source class currently exceed the derived maximum allow-
able emissions levels, while emissions of several other POM species are within an order of magnitude
of the maximum limit. In addition, while emissions of total vapor phase hydrocarbons from large
boilers were not identified as being of concern, emissions of several hydrocarbon classes, notably
oxygenates and aromatics, were flagged. Finally baseline emissions of several trace metals from
coal- and oil-fired boilers were noted as exceeding, or falling within a factor of 10 of maximum
levels. It is interesting to note that'six of the eight flagged elements exhibit Class II, or segre-
gating, behavior; they tend to repartition and concentrate in fine particulate.
Large coal- and oil-fired boilers were not the only source class associated with pollutant
streams of concern. Incremental total vapor phase hydrocarbon emissions from 1C engines operating
with dry NO controls exceeded 10 percent of maximum allowable emissions and therefore represent
X
another concern. In addition, baseline emissions of several organics from residential coal stokers
exceeded maximum limits. However, the use of coal firing in residential heating applications is
definitely declining, so this source/pollutant combination should not be considered a priority
concern.
Based on the information presented in Table 7-9, it is clear that further study is needed
of NO controls which could increase emissions of:
• Particulates from coal- and oil-fired boilers, e.g., off-stoichiometric combustion (OSC),
flue gas recirculation (FGR), and ammonia injection (NH,)
• Sulfates from coal- and oil-fired boilers, e.g., OSC, FGR, and NH3
• Organics from coal- and oil-fired boilers, e.g., low excess air (LEA), OSC, and FGR
* Segregating trace metals from coal- and oil-fired boilers, e.g., LEA, OSC, and FGR
• Vapor phase hydrocarbons emissions from 1C engines, e.g., all controls
7.4 FUTURE EFFORT
This report has:
1. Documented the scope of sources, pollutants, impacts and controls to be considered in the
NOX E/A
A
2. Evaluated data on impact criteria, control effectiveness, baseline multimedia emissions
and incremental impacts of NOV controls
X
7-74
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3. Set preliminary priorities on source/control combinations and effluent stream/pollutants
to be considered
These results will serve to initiate and scope the next efforts;
• Screen and rank the pollution impact potentials of uncontrolled sources and effluents (Bl)
— Update the Section 5 emissions inventory
- Develop approach to assess emissions during nonstandard operation
— Generate growth projections of source/fuel use and emissions
- Expand impact analysis of Section 7.3
• Generate impact screening criteria for Bl and B5 assessments (B2)
- Coordinate with other studies developing impact criteria; finalize human health im-
pact criteria of Section 2
- Decide approach to generalize terrestrial and aquatic impacts
- Develop scenarios for alternate N02 air quality standards for the Task C air quality
modeling
t Conduct field tests of priority source/control combinations (B3)
- Survey candidate test sites for coal- and oil-fired utility and industrial boilers
and oil-fired gas turbines using NO controls
- Finalize sampling and analysis requirements based on the E/A steering committee recom-
mendations and Section 7 results
• Generate process engineering and environmental assessment reports for utility boilers (B5)
- Expand process data and control results of Sections 2 and 4
- Develop cost model to standardize control cost estimates
• Develop systems analysis model with chemistry and dispersion effects (C)
- Update model inputs with cost data from B5 and regional inventories from Bl
- Expand control assessment of Section 7.1 to consider N02-oxidant reactions and a
short-term N0? standard
These efforts are discussed in the Preface and illustrated in Figure P-l.
The data evaluations contained in this report have shown the strong need for setting priori-
ties in all areas of the program. Serious data gaps exist for baseline and controlled multimedia
7-75
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emissions and impacts. These data gaps make it impossible to consider to a meaningful level all
potential source/control/effluent stream/pollutant/impact combinations within the scope of the NOX
E/A. The program results will be most useful if the effort is prioritized to allow comprehensive
assessment of fewer source-impact combinations. The prioritizations contained in this report have
accordingly set the emphasis of the NOV E/A as follows:
A
• Sources: Major emphasis on stationary fuel combustion sources firing coal or residual
oil and projected to use a significant degree of NOX controls in the near term; less
emphasis on sources firing clean fuels; minor emphasis on sources which will not be
controlled in the near term
• Controls: Major emphasis on most widely used current applications; less emphasis on ad-
vanced technology; minor emphasis on control techniques not widely used
• Effluent Streams and Pollutants: Major emphasis on flue gas emissions during steady-
state operation; less emphasis on liquid and solid effluent streams; minor emphasis on
emissions during transient or upset conditions
• Impacts: Major emphasis on human health impacts due to inhalation; less emphasis on ter-
restrial and aquatic impacts and on human health impacts due to ingestion via the food
chain; minor emphasis on materials impacts
7-76
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REFERENCES FOR SECTION 7
7-1. Eschenroeder, A., "An Assessment of Models for Predicting Air Quality," Environmental Research
and Technology, Inc., ERTW-75-03.
7-2. "Air Quality Models Required Data Characterization," Science Applications, Inc., EPRI EC-131,
May 1976.
7-3. Personal communication, Dr. Alan Eschenroeder, Environmental Research and Technology, Inc.
7-4. Personal communication, Mr. Alan Hoffman, Chief Monitoring Section, EPA, October 1, 1976.
7-5. AEROS - Emission Summary Report, Office of Air Quality Planning and Standards, U.S. EPA.
7-6. AEROS - Fuel Summary Report, Office of Air Quality Planning and Standards, U.S. EPA.
7-7. AEROS - National Emissions Summary Report, Office of Air Quality Planning and Standards, U.S. EPA.
7-8. "Climatic Atlas of the United States, 1974," U.S. Department of Commerce, Environmental Science
Services Administration, Environmental Data Service.
7-9. Star Program, U.S. Department of Commerce, National Climatic Center, Asheville, North Carolina.
7-10. "AEROS Manual Series, Volume I: AEROS Overview," EPA-450/2-76-001, February 1976.
7-11. Trijonis, J. C., et al., "Emissions and Air Quality Trends in the South Coast Air Basin,"
EQL Memorandum No. 16, Environmental Quality Laboratory, California Institute of Technology,
Pasadena, California, January 1976.
7-12. "Monitoring and Air Quality Trends Report," EPA-450/1-76-001, February 1976.
7-13. "Air Quality Data - 1973 Annual Statistics," EPA-450/2-74-015, November 1974.
7-14. Personal Communication, Ms. Pamela Henrichs, Ambient Air Monitoring Section, Division of Air
Pollution Control, Illinois Environmental Protection Agency.
7-15. "1973 National Emissions Report, National Emissions Data System (NEDS) of the Aerometric and
Emissions Reporting System (AEROS)," EPA-450/2-76-007, May 1976.
7-16. Babcock, L. R. and N. L. Nagda, "POPEX - Ranking Air Pollution Sources by Population Exposure,"
EPA-600/2-76-063, NTIS-PB 261 458/AS, March 1976.
7-17. "Fuel Use and Emissions from Stationary Combustion Sources," Southern California Air Pollution
Control District, July 1976.
7-18. "Steam-Electric Plant Air and Water Quality Control Data for the Year Ended December 31, 1973,"
based on FPC Form No. 67 -Summary Report FPC-S-253, January 1976.
7-19. Bartz, D. R., et al., "Control of Oxides of Nitrogen from Stationary Sources in the South
Coast Air Basin," KVB Report No. 5800-1795, ARB 2-1471, September 1974.
7-20. Personal communication, Mr. Robert Hilousky, Southern California Air Pollution Control
District.
7-21. "Energy Alternatives for California: Paths to the Future," Rand Corporation, R-1793-CSA/RF,
December 1975.
7-22. "National Energy Outlook -1976," FEA/N-75/713, February 1976.
7-23. "A Time to Choose -America's Energy Future," Final Report by the Energy Policy Project of
the Ford Foundation, 1974.
7-24. Personal communicatton, Mr. David Simon, FPC, Chicago Office.
7-25. Behrin, E. and R. L. Cooper, "California Energy Outlook," Lawrence Livermore Laboratory,
UCRL-J1966, November 1975 (revised February 1976).
7-77
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7-26. "Meeting California's Energy Requirements, 1975-2000," Stanford Research Institute, SRI
Project ECC-2355, May 1973.
7-27. Personal communication, Mr. David Smith, Southern California Edison.
7-28. FPC News, Vol. 8, No. 13, March 28, 1975.
7-29. "Air Quality, Noise and Health," Interim Report, Interagency Task Force on Motor Vehicle Goals
Beyond 1980, March 1976.
7-30. Yeager, Kurt, "The Effects of Desulfurization Methods on Ambient Air Quality," Advances in
Chemistry Series 127, 1973.
7-78
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APPENDIX A
EMISSION INVENTORY
Summary emission tables were presented in Section 5.4. A complete listing of emissions of the
29 pollutants considered for each equipment type, together with emission factors and NOX control fac-
tors, is given in this appendix which has been subdivided into three parts.
A.I NONCRITERIA POLLUTANT EMISSION FACTORS
Emission factors for noncriteria pollutants for utility boilers are presented in Tables A-l
and A-2. Factors for packaged boilers and warm air furnaces are in Tables A-3 and A-4, respectively.
Trace element emissions were not computed for other equipment types, and no emission factors appear
here.
A. 2 FORMULATION OF NOX EMISSION CONTROL FACTORS
Controlled NOX emissions from a particular source type (A) firing a particular fuel (B) were
calculated as
Emissions = (FC) x (UEF)£f1 {& + (1 -£f1) x (FC) x (UEF)
i i . (A-l)
V J v
Term 1 Term 2
where
FC = total fuel consumption of fuel "B" in sources of the type "A"
UEF = uncontrolled emission factor for source/fuel "A/B"
f i : = fraction of FC burned in controlled sources located in region "i"
EFi = regulated emission factor assuming 100 percent compliance for sources of type "A/B"
in region "i" (EFi < UEF)
The first term is a sum over all regions "i" in which local control regulations demand an emission
factor lower than the uncontrolled value. The second term accounts for the uncontrolled sources.
A-l
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TABLE A-l. SECTOR I NONCRITERIA POLLUTANT EMISSION FACTORS
1
Equipment Type
Utility Boilers
Tangential
Anthracite
Bituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Single Wall-Fired
Anthracite
Bituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Opposed Wall and
Turbofurnace
Anthracite
Bituminous
Lignite
Residual Oil
Distillate Oil
Natural Gas
Cyclone
Anthracite
Bituminous & Sub
Lignite
Residual Oil
Distillate Oil
Natural Gas
Vertical & Stoker
Anthracite
Bituminous & Sub
Lignite
Residual Oil
Distillate Oil
Natural Gas
Sul fates
(ng/J)
4.73
16.8
3.01
12.9
3.01
4.73
16.8
3.01
12.9
3.01
4.73
16.8
3.01
12.9
'3.01
4.73
16.8
3.01
12.9
3.01
4.73
16.8
3.01
12.9
3.01
POMs Low
(P9/J)
0.957
0.957
0.957
0.862
0.862
0.313
0.398
0.398
0.398
0.862
0.862
0.313
0.398
0.398
0.398
0.862
0.862
0.313
1.84
1.84
1.84
0.862
0.862
0.313
0.474
0.474
0.474
0.862
0.862
0.313
POMs High
(P9/J)
121.3
121.3
121.3
0.862
0.862
27.48
121.3
121.3
121.3
0.862
0.862
27.48
121.3
121.3
121.3
0.862
0.862
27.48
1.84
1.84
1.84
0.862
0.862
0.313
121.3
f21.3
121.3
0.862
0.862
0.862
Dry Removal Ash
(ug/J)a
0.589
0.520
0.37
0.589
0.520
0.37
0.589
0.520
0.370
0.589
0.520
0.370
0.589
0.520
0.37
Liquid Removal Ash
(ug/J)»
2.36
2.09
1.46
2.36
2.09
1.46
2.36
2.09
1.46
2.36
2.09
1.46
2.36
2.09
1.46
aAsh generation factors based on 65 percent flyash of coal ash and 70 percent collection
efficiency. Assumed 80 percent of utilities use sluice (wet) removal and 20 percent dry
removal (Reference A-l).
A-2
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TABLE A-2. METAL EMISSION FACTORS (ng/J) - SECTOR I
Utility Boilers
Anthracite
Bituminous
Lignite
Residual 011
Equipment Type
Utility Boilers
Anthracite
Bituminous
Lignite
Residual 011
Al
86.0
81.6
3.7
Cu
558.9x10-'
356.8x10-'
202.1x10-'
150.5x10"'
Sb
0.77x10-'
12.0x10-'
5.59x10"'
1.2x10-'
Pb
98.9x10-'
176.3x10-'
111.8x10-'
167.7x10-'
As
77.4x10-'
133.3x10-'
107.5x10-'
1.2x10