-------
All the sources were counted only within the battery limits of
each process unit.
The visual source counts were used as a basis for estimating the
total source populations in some of the major types of refinery process units.
These estimated source populations are presented in Table 5-16. Sources were
not counted in some types of process units including vacuum distillation,
aromatics extraction, delayed cokir.g, hydrodealkylation, and sulfur recovery
units. The number of sources in these units were, estimated from source
counts obtained in other types of units.
An estimate of the number of valves, pump seals, and compressor
seals in various process stream services is required to develop total hydro-
carbon emission rates from refinery process units. These source distribu-
tions were determined for pumps and compressors during the field sampling
program in refineries. Stream service distributions were not established
for valves, however. Thus, the valve distributions were estimated by
indirect means. The method is described in Appendix B (Volume 3).
The estimated distribution of pump seals and valves in selected
refinery process units is given in Table 5-17.
5.2 Nonbaggable Source Measurements and Results
The nonbaggable sources that were sampled included cooling towers,
API separators, corrugated plate interceptors, and dissolved air flotation
units. Other potential nonbaggable emission activities such as spills,
turnarounds, blind changing, coking operations, and air blowing were not
sampled. The emission potentials of some of these activities were evaluated
by surveys. The results are summarized in Section 6 of this report.
171
-------
TABLE 5-16.
ESTIMATED NUMBER OF INDIVIDUAL EMISSION SOURCES2
IN 15 SPECIFIC REFINERY PROCESS UNITS
Estimated Number of Sources Within Battery Limits of Process
Units
Process Unit
Atmospheric Distillation
Vacuum Distillation1
Fuel Gas/Light Ends Processing
Catalytic Hydroprocessing
Catalytic Cracking
Hydrocrar.klng
Catalytic Reforming
AromaticB Extraction
Alkylation
Delayed Coking1
Fluid Coking
Hydroealkylation*
Treat ing /Dewaxing
Hydrogen Production
Sulfur Recovery1
Valves
890
500
180
650
1310
930
690
600
680
300
300
690
600
180
200
Flanges
3540
2000
760
2600
5200
3760
2760
2400
2280
1240
1240
3760
2290
640
800
Pumps3
31
16
3
10
30
22
14
181
11
91
9
141
18
5
61
Compressors'*
1
o1
2
3
3
3
3
O1
0
O1
4
31
1
3.
O1
Drains
69
35
11
24
65
58
49
41
41
28
28
58
44
17
20
Relief
Valves
6
6
6
6
6
6
6
6
6
6
6
6
6
4
4
Sources were not counted in process units of this type. The number of sources was estimated.
Only those sources in hydrocarbon (or organic compound) service.
Number of pump seals - 1.4 x number of pumps.
Number of compressor seals - 2.0 x number of compressors.
-------
TABLE 5-17.
AVERAGE NUMBER AND ESTIMATED DISTRIBUTION OF VALVE
AND PUMP SEALS IN REFINERY PROCESS UNITS
Puap Service
Distribution
Atmospheric Distillation
Vscuuas Distillation
Fuel Ca«/Llght End* Processing
Catalytic llydroproceselng
Catalytic Cracking
Hydrocracklng
Catalytic Reforming
ArumaCicB Extraction
Alkylatlon
Delayed Coking
Fluid Coking
Hydrodcalkylatlon
Deuaxlng/Trcaclng
Hydrogen Production
Sulfur Recovery
Average
No. of
Valvea
U93
SOU1
181
645
1314
911
691
600'
571
3U01
304
7(10 l
399
182
2001
Average
No. of
Pumps
31
16'
3
10
30
22
H
18'
11
91
9
14'
18
5
6'
Average
No. of
Compressors
1
o1
2
3
3
3
3
0'
0
0'
4
3'
1
3
O1
Valve
To Pump
Ratio
29
34
60
65
44
42
49
33
52
33
34
50
33
36
33
Light
Liquid
Service,
%
35
10
83
67
44
55
9O
0.90"
100
21'
21
90'
39
60
84'
Heavy
Liquid
Service,
X
65
90
17
33
56
45
10
0.101
0
79'
79
ID1
61
40
16l
Eattaated
Valves.
Gas
Service
90
55*
88
335
384
250
260
60'
230
30'
30
2661
60
27
90'
Distribution of Estimated Distribution of
, Number/Unit Pump Seals, Number/Unit
Light
Liquid
Service
281
50'
77
2C8
409
375
388
486'
341
57'
58
3911
210
93
901
Heavy
Liquid
Servica
522
945*
16
102
521
306
43
54'
0
213'
216
43'
329
62
20'
Light
Liquid
Service
15
2'
4
9
IB
17
18
15'
15
•3'
3
IS'
11
5
8
Heavy
Liquid
Service
28
l
19
0
5
24
14
2
21
0
10'
10
21
18
3
2
Total
Pump
Si-ale
43
2l'
4
14
42
31
23
17'
15
Ul
13
20'
29
0
10
Sourca counts were not made In tht field. These values are estlaated.
-------
5.2.1 Coo ling Tower Ernisjjions^leas^irenie n t_s_
Hydrocarbon emissions from cooling towers were determined from
hydrocarbon material balances around each tower. The hydrocarbon content of
the incoming and outgoing water streams were determined by a total organic
carbon (TOG) analysis a.nd/or by a volatile organic purging procedure. Both
of these methods are described in Section 4 of this report. A more detailed
description of the sampling and analytical techniques are included in
Appendix A (Volume 2). Calculation methods and complete measurement data
are contained in Appendix B (Volume 3).
Thirty-one cooling towers were sampled. Eight of these had statis-
tically significant emissions. The estimated emissions from the individual
cooling towers are presented in Table 5-18. Streams from five towers were
analyzed by both TOC and purge analyses. Thus, streams from a total of 21
towers were analyzed by TOC and streams from 15 towers were analyzed with
the purging technique. An analysis of the results from both these analytical
methods indicated that the purging technique was more accurate and precise
than the TOC analysis. Where both analytical techniques were used, the
results with the purging technique were chosen for calculation purposes.
The results of the cooling tower sampling program are presented
in Table 5-19. Because the purge method of analysis was found to be the
more precise method, an emission factor of 0.00011 lb/1000 gallons of
circulating cooling water was developed using only the purge method results
from the fifteen towers. A 95 percent confidence interval for this factor
ranges from negligible to 0.0004 lb/1000 gallons.
5.2.2 Wastcwater Systems
APT separators, corrugated plate interceptors, and dissolved air
flotation (DAI'1) units were sampled to determine atmospheric emissions of
hydrocarbon. The emissions were estimated from a hydrocarbon material
174
-------
TABLE 5-18. ESTIMATED EMISSIONS FOR INDIVIDUAL TOWERS
Tower
Nmber
1
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
26
27
28
29
30
31
Analysts
Method
Purge
Purge
TOC
Purge
TOC
TOC
TOC
TOC
TOC
TOC
TOC
Purge
TOC
TOC
TOC
Purge
Purge
TOC
TOC
Purge
TOC
TOC
Purge
TOC
Purge
TOC
Purge
TOC
TOC
Purge
Purge
Purge
Purge
Purge
TOC
TOC
Average
A PPM
0.002
0.018
0.35
0.061
2.14
1.25
-1.17
1.61
0.61
0.38
-5.03
-0.008
10.09
0.29
3.94
0.015
0.034
-0.14
0.83
0.013
-0.03
2.22
0.131
1.45
0.019
1.46
-0.155
-0.30
3.45
-0.025
0.016
0.006
0.011
0.024
-2.09
-0.24
Standard
Deviation
0.020
0.015
2.49
0.139
1.63
1.53
1.82
2.12
1.46
3.69
7.53
0.046
10.49
2.19
1.63
0.035
0.016
1.37
1.57
0.72
3.79
0.090
0.70
2.68
0.324
1.26
4.96
0.045
0.037
3.05
1.64
Student
t Test
0.24
2.00
0.24
0.87
2.63**
1.82**
-1.43
1.86**
1.03
0.23
-1.16
-0.35
2.35**
0.32
4.83**
0.34
4.36**
-0.20
1.19
-0.10
1.17
2.92**
3.61**
1.09
-0.96
-1.42
1.20
-0.94
0.88
-1.67
-0.36
Circulation
(GPM)
1,000
5,000
58,000
58,000
5,250
5,000
5,500
5,900
6,900
9,000
1,800
1,800
714
6,200
3,597
2,350
21,150
25,000
6,700
3,900
48,000
48,000
3,500
5,000
5,000
10,000
15,000
15,000
29,600
8,570
8,300
Slowdown
(GPM)
155.0
155.0
28.5
10.0
15.7
12.3
24.8
30.0
30.0
1.4
23.3
9.7
14.3
15.4
131.7
131.7
50.0
50.0
16.9
106.7
106.7
17.1
106.0
Emissions
(Ib/hr)
6.47±4.44
3.73*3.27
5.56±5.24
4.30+3.20
8.46±3.15
0.36*0.18
3-14±2.32
3.03±1.56
**Statistically significant
175
-------
TABLE 5-19. SUMMARY OF COOLING TOWER EMISSIONS
o\
Cooling Towers Sampled
Cooling Towers Having Statistically Significant Emissions
Range of Cooling Tower Circulation Rates
31
8
714 to 58,000 GPM
Results (estimate with 95% confidence interval)
Mean Cooling Tower A HC Concentration
From Emitting Towers
Both Analyses
0.101 t 0.19 ppm
From All Towers Sampled
TOC Analysis
Purge Analysis
Both Analyses3
Mean Cooling Tower Emissions
From Emitting Towers
Both Analysis
From All Towers Sampled
TOC Analysis
Purge Analysis
Both Analyses
1.25 ± 1.24 ppm
0.01.30 ± 0.0299 ppm
0.0173 ± 0.058 ppm
0.00088 t 0.0016 lb/1000 gal
0.0124 + 0.0123 lb/1000 gal
0.000108 ± 0.00025 lb/1000 gal
0.000151 ± 0.00051 lb/1000 gal
(negligible, 0.29 ppm)
(0.01, 2.5 ppm)
(negligible, 0.043 ppm)
(negligible, 0.075 ppm)
(negligible, 0.0025 lb/1000 gal)
(0.0001, 0.025 lb/1000 gal)
(negligible, 0.00036 lb/1000 gal)
(negligible, 0.00066 lb/1000 gal)
Range of Measurable Emissions 0.36 to 8.46 Ib/hr
Calculated for 15 towers analyzed by TOC only plus 16 towers analyzed by purge. The 5 towers
analyzed by both methods were represented only by the purge values, considered more accurate
than TOC values.
-------
balance around each unit. The methods used to determine the hydrocarbon
content of the oil and water streams are described in Section 4 of this
report. The methods arc described in greater detail in Appendix A (Volume 2)
The results of the sampling program are presented in Table 5-20.
There is a great deal of scatter and uncertainty in the data and results,
particularly in the determination of emissions from the oil phase of the
oil-water separators. Negative value.s are even indicated for some emissions.
The one conclusion that can be made regarding these results is that the
material balance approach, as implemented in this program, is inadequate for
defining emission rates from oil-water separators. The composition of the
incoming stream varies widely, and grab samples are not generally representa-
tive. For this reason, emission factors for oil-water separators were not
developed from experimental results.
Emission measurements for dissolved air flotation (DAF) units were
obtained from four different units using a material balance on the water
phase only. The oily froth was not considered in the material balance.
Emissions from the four water-phase units averap3ed 0.05 lb/1000 gallons of
wastewater. The 95 percent confidence interval about the average value was
from negligible to 0.24 lb/1000 gallons of wastewater. The DAF data were
insufficient, to allow the development of an emission factor which can be
used with confidence.
5. 3 Stack Emissions^
The results of sampling FCCU regenerator stacks, heater stacks,
sulfur recovery/tail gas treating unit stacks, and other miscellaneous stacks
are summarized in the sections below.
177
-------
TABLE 5-20. DESCRIPTION OF SAMPLED DEVICES - WASTE OIL/WATER SYSTEMS
CO
Average Hydrocarbon Emissions
Refinery
1
2
3
4
5
6
7
8
Device
R Rectangular API Separator
Circular DAF
Rectangular API Separator
Corrugated Plate Interceptor
Corrugated Plate Interceptor
Rectangular API Separator
Forebay Covered
Surge Tank
Two Rectangular Separators
Rectangular DAF
Rectangular API Separator
Rectangular API Separator
Rectangular DAF
Circular Separator
Circular DAF
Covered/Uncovered
C
U
C
C
C
U
U
U
U
U
II
U
U
U
Losses from
Oil Phase,
Ib/gal slop oil
1.6 j- 2
1.84 + 1.11
-1.5 + 0.08
-0.11 + 0.06
0.12 + 1.3
0.45
-1.1 + 0.74
0.14 ± 0.4
0.48 ± 0.61
LOBBCE from
Water Fltasft,
IL/gal water
2.7x10"" -r 1.8x10*"
8.2x10 s + 1.5xlO~"
-3.01xlO~* + Ixio"5
—
2.2x10"" ± 2. 7x10" "
1.6xlO'5 + 3xlO~6
-2.4x10 5 + 2.7x10 5
1.5x10"" j- 2.4xlO~"
6.5x10"" + 1.9xlO~"
1.1x10"" + 1.3x10 "
3.4x10"" + 1.8x10""
1.4x10 5 + 1.7xlO"s
-------
5.3.1 FCCU Regenerator Stack Measurements
A total of seven stacks from five different FCCU's were sampled
for criteria pollutants and individual organic species. The results of
the sampling are presented in Tables 5-21 through 5-23. The FCCU regenerator
stacks included in Table 5-21 were all equipped with electrostatic preclpita-
tors and CO boilers. Stacks No. 13 and 18 were from separate CO boilers on
the same FCCU.
The results shown in Table 5-22 were obtained from an FCCU whose
flue gases passed through a CO boiler and then through a scrubber. Two
scrubber units each handled approximately one-half of the fine gas. Both
particulates and S0_ were removed in the scrubbers.
X
In only one case were samples obtained upstream of the CO boiler
and/or ESP. The results are shown in Table 5-23. Only grab samples could be
be taken upstream of the control devices. The CO boiler was effective, in
removing the organic species such as aldehydes and HCN.
In Table 5-24, the FCCU regenerator emissions are expressed as
functions of the fresh feed rate to the FCC units. Although data are limited
on the effectiveness of the scrubbers, they appeared to be somewhat more
effective than electrostatic precipitators in reducing particulate emissions.
The level of SO in the flue gases was quite low in the two FCCU scrubber
s{
stacks.
5.3.2 Crude Unit Process Heater Stack Measurements
Process heater stacks from five crude oil distillation units were
sampled. The results are summarized in Tables 5-25 and 5-26. Detailed data
are given in Appendix B (Volume 3).
179
-------
TABLE 5-21. RESULTS OF SAMPLING FLUE GASES FROM FCCU REGENERATORS EQUIPPED
WITH ELECTROSTATIC PRECIPITATORS AND CO BOILERS
CO Boller
Stack No. 11
S peel us
Aldnhydfs
(ns Formal dr.hydc)
Methane Hydrocarbons
Nonmethaae Hydrocarbons
(as 'Jexane)
i'articulates
SO,
SO,
H.:S
M COS
C»
0 rs,
NOX (ns N02)
HCN
Nib
pprnv "
0.0 (••,(>
0.602
16.1
(U.184)C
96.8
8.30
ud
rroft
mi
u
0.80
0.87
th/scf
5.12x10"'
2.49x10""
3.57xlO~f>
2.63xlO~'
1.60x.lO~s
1 .72x10"°
U
ND
MO
U
5.58x10""
3.81xlO~8
CO Boiler
Stack No. 14
ppm ^
10.0
2.Vi
9.51
U
625
7.27
ND
Nl)
U
184.9
1.03
0.73
Ib/scf
/. 76x10"'
9.75xlO~"
Z.llxlO"6
U
1.03x10"''
1.50xlO~(
NO
HD
U
Z.20,10-5
7.19xlO~"
3.19xlO~'
CO BoJler
Stack No. 16
ppmv ^
6.70
o.n
2.6J
(0.0154)'
13.4
1.15
<0.10
0.067
<0.06/
415.3
0.204
<4.25
Ib/ncf
5.19x10"'
0.0
5.79xlO"7
: 2.20xlO~6
2.22xlC"6
2.37x10""'
< 8. 7 9xlO~'
1.03x10""'
<1. 31x10" "
4.938xlO"s
1.42xlO~"
< 1.8 7x10"'
CO Boiler
Slack Ho. 13 a
ppmv "B
7.30
KD
3.80
(0.0426)c
406.6
1.14
0.58
KD
0.40
257.7
0.012
0.2H>
5.
NO
8.
6.
6.
7.
5.
Ib/sr.f
66x10"''
44xlO~7
09xlO~6
725x10" s
35x1 0~ '
12xlO~s
ND
7.
3.
8.
1.
86x10 "
064x10"^
37xlO~I(1
48xlO~8
CO
Slack
ppmv ^
5.54
KD
1.91
(0.0493jr
327.3
1.81
ND
ND
1.33
225.0
0.005
ND
Bollc-r
No. 18a
Jb/scf
4.:50xl()"7
NH
4.24xlO~7
7.04xlO~''
5.4l4xlO-s
3.91x10"'
ND
Nl)
2.6lAlO~7
2.675x10" s
3. 49x1 O"'"
NT)
Total Gas Flow Rate,
SCFM
2.70x10*
1.26x10"
8.97xlOG
9.15x10
acn hollors in same FCC unit..
lily basis.
'"Given as f,raiiiR/SCF.
U =• UrideLerinined.
eNll = Not detected.
-------
TABLE 5-22. RESULTS OF SAMPLING FLUE GASES FROM FCCU REGENERATORS
EQUIPPED WITH CO BOILERS AND SCRUBBERS
oo
FCCU CO Boiler
Scrubber-Stack No. 12a
Species
Aldehydes (as Formaldehyde)
Methane Hydrocarbons
Nonme thane Hydrocarbons (as Hexane)
Particulates
S02
S03
H2S
COS
CS2
NOX (as N02)
HCN
NH3
Total Gas Flow Rate, SCFM
ppmv ^
46.3
89.4
28.3
(U.019)C
5.13
0.16
ud
U
U
41.1
U
U
9
Ib/SCF
3.59xlO~6
3.70xlO~G
6.28xlO~6
2.71xlO~6
8.49xlO~7
3.31xlO~a
U
U
U
4.89xlO~6
U
U
.08xl06
FCCU CO Boiler
Scrubber-Stack No. 17a
ppmv b
36.1
14.3
12.7
(0.024)°
12.5
0.35
U
U
U
180.8
U
U
8.
Ib/SCF
2.80xlO~6
5.92xlO~7
2.83xlO~6
3.43xlO~6
2.07xlO~6
7.24xlO~8
U
U
u
2.15xlO~b
U
U
53xl06
Both scrubbers located on same unit.
Dry basis.
f\
Given as grains/SCF.
U = Undetermined.
-------
TABLE 5-23. RESULTS OF SAMPLING FCCU REGENERATOR FLUE GAS UPSTREAM
AND DOWNSTREAM OF CO BOILER/ESPa
CO
NJ
Species Concentration
Upstream of CO
Boiler and ESP
Species
Aldehydes (as Formaldehyde)
Methane Hydrocarbons
Nonmethane Hydrocarbons (as Hexane)
Particulates
SO 2
SO 3
H2S
COS
CS2
NOX (as NO 2)
HCN
NH3
Total Gas Flow Rate, SCFM
ppmv a
208
Uc
U
U
332.5
U
U
U
U
41.5
109.5
3.99
Ib/SCF
1.61xlO~ 5
U
U
U
5.50xlO~5
U
U
U
U
4.93xlO~G
7.64xlO~6
1.75xlO~7
U
Species Concentration
Downstream of CO
Boiler (Stack No. 15)
ppmv a
17.2
U
U
(0.0686)d
677
0.954
U
U
U
100
19.1
11.0
6.
Ib/SCF
1.33xlO~
U
U
9.80x10"
1.12xlO~
1.97x10"
U
U
U
1.19xlO~
1.33xlO~
4.83x10"
53xl06
6
6
'i
7
5
6
7
Flue gas from FCCU regenerator passed through an ESP and into the CO boiler; samples were obtained
prior to the ESP and from the CO boiler stack.
Dry basis.
"U = Undetermined.
Given as grains/SCF.
-------
TABLE 5-24. CONTROLLED EMISSION RATES FROM FLUID CATALYTIC
CRACKING UNIT (7CCU) STACKS
00
Control Devlcua lit Uue During TraLlng
Spectea
Aldcltydca (as Formaldehyde)
Mctliane
Nonrcethane Hydrocarbons (ao llcaano)
P«« clculate Mutter
SO,
so,
II. S
COS
cs,
NO (is ,'in,)
MCN
Nil,
TOTAL Cat Plow, SCFM
CO Seller, CO Boiler, ESP,b ESP, ESP,
ScruU.tr ScruLber CO Uoller CO Holler CO Boiler
Stack .£tack Stuck , Stack Stick
Na. U* ito. 17* No. 15 Mo. 11 Ha, 13°
13 S J < 1 3
11 2 < 1 0
2tt 9 — 5 S
9 10 33 36 34
3 6 381 22 378
0.1 0.2 0.7 2.3 1.3
0.3
— — — o o
0 0,4
16 65 «L -- 173
4.5 0.1 0.005
1.7 0.1 0.07
9.08x10* a.53»10* 6.53«10' J.70«ID' 9.15x10*
*Aimro»l«ata ezlaelon rates. Stacks Ho. 12 and 17 were located en ttie Sana unit. The feed rate Co
LcCwecn Che two stacks for the purpose of calculating emission ratfrQ.
E5i' • elect roat AC Ic prec Ipitntor ,
CApi> re, trout e eiulnaion ralui. KCCll liaJ cuu CO bollcra, Scacka Ho. 13 and No. 18. Tlx faad rata to
between ttie two hollers for the ptirpoee ot calculating eelaaiunt ralea.
ESP, ESP, ESf,
CO Boiler CO Boiler CO Colter
Freih Feed
Stack Stack Stick
No. lac Ho. 14 No. 16
J < 1 5
0 < 1 0
1 1 )
37 ~ 10
186 46 10
2.1 0.7 2.1
0 0 < 0.1
0 0 0.09
1.4 -- < U.I
141 10 441
0.002 0,03 0.13
0 0.01 < 1.7
B.58x 10* 1.26x 10* 8.97 » 10*
tlio FCCU was equally divided
the FCCU wai equally divided
-------
TABLE 5-25. RESULTS OF SAMPLING FLUE CASES FROM
CRUDE UNIT PROCESS HEATERS
00
Species
Aldehydes
(as Formaldehyde)
Methane Hydrocarbons
Nonmethano Hydrocarbons
(as Hexane)
FartlcuJ.ates
SO?
SOi
HjS
COS
cs,
NOX (a;; NO?.)
HCN
Nit)
Total Gas Flow Rate,
SCFM
Stack No. 2
ppmv*1 Ib/SCF
6.6? 5.13xlO~7
O.U 0.0
0.77 T./2xlO"7
(0.04?)h 5.94x10"°
2.15 3.56xlO"7
(I.I.I3 1. 25x10" 7
U I!
U U
U U
U U
0.021 5.40xlO~r' (0.064)b 9.07xlO~f> llc
1.06 1.75xlO~7 295.5 4.89xlO~s 95
O.i_r> 3.02x10"* 0.72 1.49xlO~7 21
U U U U U
U U U I) U
U U U I! U
U U U U U
<0.001 <6.98xlO"n U U 0.
<0.30 <1.32y_LO"8 U U 1.
2.34xlOf 7.03xlOr'
Stack No. 5
nva Ib/SCF
11 R.TlxUr"
67 1.14xlO"7
26 1.39x10"°
U
.7 1.58xlO~s
.2 4.38x10"*
U
U
U
U
85 5.93xJO~"
23 5.40x10"'
2.78x10''
Stack
ppfnv3
8.9.3
0.45
1.80
U
0.18
U
d
ND
ND
ND
92.9
U
U
U
Mo. 6
Ib/SCF
6.92x\0~7
1.86x10"'
3. 99x1 0"7
U
?.98xlO~R
U
ND
ND
ND
1 . 1 0x1 0~ '•
U
U
Dry hnm's.
Given as grains/SCF.
CU = Undetermined.
NP = Not detected.
-------
TABLE 5-26. COMPOSITION OF REFINERY HEATER STACK GAS
QO
Ul
Species
Aldehydes (as Formaldehyde)
Methane Hydrocarbons
Norjnethane Hydrocarbons (as Hexane)
Partlculate Matter
SO,
S03
II, S
COS
csa
N0x (as NO,}
HCN
HH,
TOTAL Ga9 Flow Rate, SCFM
Stack Gag Composition, Parts per million by Volune(ppmv)a
Stack Stack Stack Stack Stack
No. 2 No. 3 No. 4 No. 5 No. 6
6.6 6.8 0.05 0.1 8.9
0.0 0.0 0.5 2.7 0.5
0.8 0.9 1.1 6.3 1.6
(0.042)b (0.038) (0.064) Ue U
2.2 1.1 296 96 0.2
0.6 0.2 0.72 21 U
Ud Ud U U NDC
U U U U ND
U U U U ND
U U U U 93
< 0.021 < 0.001 U 0.9 U
< 0.030 < 0.3 U 1.2 U
3.26x10' 2.34x10' 7.03 x 10* 2.78x10* U
L)ry basis
"J • undetermined
ND • not detected
reported
-------
The process heaters were fired with mixed refinery fuel gas-fuel
oil. No external emission controls were in use during any of the sampling
activities.
5.3.3 Emissions From Tail Gas Treating Units
The stack gases from the tail gas treating processes of two sulfur
recovery units were, sampled and analyzed. The compositions of these gases
are given in Table 5-27. The accuracy of the hydrocarbon and SO analyses
of the gas from Stack No. 7 is uncertain. The concentration of hydrocarbons
in the gas is very high. At the same time alnost no S02 was found. No
satisfactory explanation of these results has been put forward.
5.3.4 Miscellaneous Source Emissions
Several miscellaneous source, stacks were sampled. The results are
summarized in Table 5-28. The flue gas from a fluid coker was sampled up-
stream and downstream of the control devices, a scrubber and a CO boiler.
The effectiveness of the controls can be seen in Table 5-28. The table also
contains data on a resin fume oxidation unit, a TCC regenerator and FCCU
compressor engine (internal combustion) exhausts.
5.4 Identification of Emitted Species
The. characterization and measurement of organic emissions from
controlled and uncontrolled sources were conducted at several petroleum
refineries. The controlled sources from which samples were taken and analyzed
include FCCU CO boiler stacks, TCC CO boiler stacks, fluid coker CO boiler
stack and a fume oxidation unit.
Uncontrolled sources included valves, flanges, pump seals, com-
pressor seals, and drains. Fugitive vapor emission samples and corresponding
liquid samples were obtained in many cases. Vapor samples were obtained from
leaking valves and pump seals. Corresponding liquid samples were obtained
186
-------
TABLE 5-27. COMPOSITION OF STACK GAS FROM SULFUR
RECOVERY TAIL GAS TREATING UNITS
Species
Aldehydes (as Formaldehyde)
Methane Hydrocarbons
Nonmethane Hydrocarbons (as Hexane)
SO,
S0a
H2S
COS
CS,
N0x (as N02)
HCN
NH3
TOTAL Gas Flow, SCFM
I3ry Basis
b
Species Concn.
Stack
No. 7
ub
5870
2080
0.2
U
U
6-4
9.0
15.0
U
U
U
in Flue Gas, ppmv
Stack
No. 8
4.0
0.8
5.7
460
0.7
x
0.5
1.9
16.7
< 0.001
< 0.03
(2.02x 103)C
undetermined
Provided by plant personnel
ND - not detected
187
-------
TABLE 5-28. MISCELLANEOUS STACK EMISSIONS
Froet.a Unit: flM Coklng
Ga. Stre..: *"^*>"
Inlet
Control Devlcaa In Uae- During Teala: Sciubtur, CO
Caa
Coapoal t Ion,
Ib per 1000
tpeclea bbl f««d
Alditiydte (•• Formaldehyde) 3.2
Methane Kydrocarbona 433
Honaethini Hydrocarbon* (aa llexane) 135
rartlculate Hattar 437
OT SO, NDC
00
50, ND
fl,S ND
COS ND
CS. ND
HO^ (» NO,) 7.1
HCH 36.9
Nil. 39.3
TOTAL Caa Mow Rate. SCFM 1.77«10*
Unit
CO Boiler
Out lit
Butler
Imleaion
Rate,
Ib per IOOD
bbl lead
1.3
3.7
12.7
133
267
1.4
ND
ND
ND
159
1.2
0.2
2.44 « 10'
Rtieln Fume
Oxidation
Unit
Flue
—
Cna
Conposlt lont
>4
1.5
2.3
(0.0063)b
ia
0.4
MDC
KD
KO
V*
U
u
3.09» 10*
TC.CU
TCC Unit Cowpie^Ror
60 g
Flue E»haiiat
Caa mva
2.3 U
0.0 4.0
0.2 72
IS (O.U42)'
121 0.50
O.J 0.61
U U
U U
U U
43 U
ND 3.1
0.3 1.4
3.10K 10" 0,35 » 10*
Dry b»la
ND - not d.t.ct.d
Cxpr«aa«4 ••
U - und«t«i»Incd
-------
from liquid .process streams at locations as near as possible to the vapor
sample point. Both the liquid and vapor samples were analyzed. Details of
the sampling and analyses procedures are described in detail in Appendix A
(Volume 2). They are summarized in Section 4 of this report.
The collection and analysis of vapor samples is time consuming.
The collection and analysis of liquid samples is much simpler. Laboratory
experiments were conducted to determine the relationship between fugitive
vapor composition and the corresponding process liquid composition. These
experiments indicated that the composition of fugitive emissions from
refinery equipment is identical to the composition of the liquid within the
leaking source. (See Appendix B, Volume 3.) As a result of these experi-
ments, liquid stream samples were preferentially analyzed, wherever possible,
instead of the corresponding vapor samples.
The. analyses were done by GC-MS. The analytical emphasis was
placed on the Identification and quantisation of aromatic and polynuclear
aromatic compounds. The detailed results of these analyses are presented
in Appendix B (Volume 3). For brevity, the results are only summarized here.
5.4.1 Species Present in FCCU Regenerator Flue Gas
Particulate matter in the flue gas was collected by cyclones in a
Source Assessment Sampling System (SASS) train. Fine particulates were
collected on a filter downstream of the cyclones. The sampled gas also
passed through a cannister packed with adsorbent to collect volatile organic
compounds. The organic material present on or in the particulate matter was
extracted and subjected to GC-MS analysis. The organic material on the
adsorbent was similarly analyzed.
Individual species found and identified in particulate matter
and/or adsorbed material are listed in Table 5-29. A total of seven particu-
late and seven adsorbed vapor samples were analyzed. Those species other
189
-------
TABLE 5-29. ORGANIC SPECIES FOUND IN FCCU
FLUE GAS SAMPLES3.b
Organic Compounds0 Present at Concentrations >0.1 ppb
Anthracene/phenanthrene
Methylanthracene/phenanthrene
Naphthalene
Methylnaphthalenes
C ?. -naphthalenes
Benzole acid
Biphenyl
Cresol
Cyclohexane dlol
Cyclohexanol
Cyclohexanone
Cyclohexene oxide
Methylcyclohexanone
Benzaldehyde
Acenaphthene
Acenaphthylene
Benz(a)anthracene/chryscne
Cz-alkylphenols
Ca-alkylphenols
Dibenzofuran
Fluorcne
Fluoranthene
Indanol
Methylphenols
Nonylphenol
Octylphenol
Species found in particulatc matter and/or vapor samples.
Cjj-Cai alkanes detected but not listed.
CA11 samples were taken downstream of CO boilers and ESP or scrubber.
190
-------
than alkanes which were found in any of the samples at concentrations
above 0.1 ppb are listed. Alkanes were present, but they are not listed.
Particulate samples from two FCCU were subjected to an elemental
analysis. The results are shown in Tables 5-30 and 5-31.
5.4.2 Identification of Organic Compounds in Fugitive Vapor
Samples
Some .samples of hydrocarbon vapors from leaking valves and pump
seals were collected in canisters packed with adsorbent. However, laboratory
experiments indicated that the composition of liquid streams inside a leaking
source was the same as that of the emitted vapor. The analysis of liquid
samples was less time-consuming and more economical. Thus, most of the
sampled material is liquid from process lines.
The sampled stream types are listed in Table 5-32. The organic
compounds which were detected in the vapor samples or which were found in
concentrations above 10 ppm in liquid samples are listed in Table 5-33.
5.4.3 Potentially Hazardous Organic Species in Sampled Refinery
Streams
The results of the detailed analyses of vapor and liquid samples
taken from refinery process streams and emission points are summarized in
this section. Only those organic species which are. potentially the most
hazardous of those which might be present in refinery streams are considered.
These species and their concentration ranges which were found in process
streams are presented in Tables 5-34 and 5-36. The stream identification.
numbers and descriptions are given in Table 5-35.
191
-------
TABLE 5-30. ELEMENTAL ANALYSIS OF FCCU CO BOILER
FLUE GAS PARTTCULATES (STACK A)
Element
Uran i um
Thorium
Bismuth b
Lead
Thallium
Mercury
Gold
Platinum
Ir idlum
Osmium
Rhenium
Tungsten
Tantalum
Hafnium
Lutetium
Ytterbium
Thul i.um
Erbium
Ho 1m i.um
Dysprosium
Cone .
5
6
—
54
—
—
—
—
—
—
—
5
<1
3
1
5
0.9
22
24
230
Element
Terbium
Gadolinium
Europium
Samarium
Neodymium
Praseodymium
Cerium
Lanthanum
Barium
Cesium
Iodine
Tellurium
Antimony
Tin
Indium
Cadmium
Silver
Palladium
Rhodium
Cone.
29
150
14
490
MCC
MC
MC
MC
790
0.2
—
—
0.9
5
e
STD
<0.5
o.s
—
—
Element
Ruthenium
Molybdenum
Niobium
Zirconium
Yttrium
Strontium
Rubidium
Bromine
Selenium
Arsenic
Germanium
Gallium
Zinc
Copper
Nickel
Cobalt
Iron
Manganese
Chromium
Cone .
66
15
48
240
120
<0.5
<3
36
4
<0.7
10
260
40
300
50
MC
300
840
"Element
Vanadium
Titanium
Scandium
Calcium
Potassium
Chlorine
Sulfur
Phosphorus
Silicon
Aluminum
Magnesium
Sodium
Fluorine
Oxygen
Nitrogen
Carbon
Boron
Beryllium
Lithium
Hydrogen
Cone.
150
MC
17
MC
MC
22
MC
MC
MC
MC
MC
MCC
MC
NRc1
NR
NR
69
1
280
NR
Concentration i.n ppra by weight.
.Concentrations < 0.2 ppmw were not listed.
"MC - major component(70.1%)
NR - not rspur Led.
ST!) - analytical method
-------
TABLE 5-31. ELEMENTAL ANALYSIS OF FCCU CO BOILER
FLUE GAS PARTICULATES (STACK C)
a
Element Cone .
Uranium
Thorium
Bismuth
Lead
Thallium
Mercury
Gold
Platinum
Iridium
Osmium
Rhenium
Tungsten
Tantalum
Hafnium
Lutecium
Ytterbium
Thulium
Erbium
Holmium
Dysprosium
, Concentration
It
5
19
—
29
—
NR
—
—
—
—
—
2
1
4
0.4
2
0.6
1?.
10
30
in ppm
Element
Terbium
Gadolinium
Europium
Samarium
Neodyraium
Praseodymium
Cerium
Lanthanum
Barium
Cesium
Iodine
Tellurium
Antimony
Tin
Indium
Cadmium
Silver
Palladium
Rhodium
by weight.
Cone.
7
94
9
930
MC -
MC -
MC -
MC -
860
1
0.4
—
3
4
STDS
<0.3
<0.3
—
—
Element
Ruthenium
Molybdenum
Niobium
Zirconium
.4% Yttrium
. 3% Strontium
2% Rubidium
4% Bromine
Selenium
Arsenic
Germanium
Gallium
Zinc
Copper
Nickel
Cobalt
Iron
Manganese
Chromium
Gone.
—
150
80
260
88
130
< 8
< 3
5
4
< 1
53
130
1/40
550
60
MC
680
MC
Element
Vanadium
Titanium
Scandium
Calcium
Potassium
Chlorine
Sulfur
Phosphorus
Silicon
Aluminum
Magnesium
Sodium
Fluorine
Oxygen
Nitrogen
Carbon
Boron
Beryllium
Lithium
Hydrogen
Cone.
100
MC ^
12
MC
MC
150
MC
MC
MC
MC
200
MC
MC
NRd
NR
NR
8
0.3
1.1
NK
^MC - major component (>0. 1/0 .
Concentrations < 0.2 ppmw were not listed.
CNR - not reported.
il'D - analytical standard.
-------
TABLE 5-32. SAMPLED REFINERY HYDROCARBON STREAMS
Gas Stjr earns
Reformer Recycle Hydrogen
Atmospheric Crude Distillation: Overhead Gas
FCCU Low Pressure Separator Gas
Liqu.id Streams
Atmospheric Crude Distillation: Intermediate Naphtha
Full Range SR Gasoline
Virgin Distillate
Atmospheric Gas Oil
Vacuum Distillation: Light Vacuum Gas Oil
Vacuum Gas Oil
Heavy Vacuum Gas Oil
Vacuum Residuum
Reforming: Naphtha to Feed Hydrotreating
Naphtha to Reformer
Reformate
FCCU: Reflux Accumulator Bottoms
Separator Bottoms
Main Fractionator Overhead Liquid
Light Cycle Gas Oil
Heavy Cycle Gas Oil
Desulfurized Naphtha
Desulfurized Gas Oil
Alkylation: Reactor Product
Crude Alkylate
TCC: Heavy Cycle Gas Oil
Absorber Lean Oil
Slack Wax from Dewaxing
API Separator: Inlet Oil
Surface Oil
Skimmed Oil
194
-------
TABLE 5-33. ORGANIC SPECIES PRESENT IN REFINERY LIQUID
STREAMS AND EMITTED VAPORS3
alkanes
Benzene
Toluene
Xylenes
Ethylbenzene
TrimeLhylbenzene
Dicthylbcnzene
Dimethylethylbenzene
Tetramethylbenzene
sec-butylbenzene
Naphthalene
Methylnaphthalenes
Biphenyl
C2~alkylnaphthalenes
C 3-naphthalen es
Phenanthrene/anthracene
Methylphenanthrene/anthracene
Cz-alkylphenanthrene/anthracene
C3-alkylphenanthrene/anthracene
Propylbenzene
Ethyltoluene
Methyl.Isopropylbenzene
Methylpropylbcnzene
Dlethylbenzene
Dimethylethylbenzene
In dan
Methyl indan
C .s -a Ikylb en 7, cm e
Tetralin
Biphenyl
Methylbiphenyl
CT-alkylbiphenyls
Fluorene
Methylfluorene
C2-alkylfluorenes
Acenaphthcne
Methylacenaphthene
Ci, -alkylacenaphthene
C2-alkylnaphthalenes
Dibenzo Chiophene
Methyldibenzothiophene
Co-alkyIdibenzoChiophene
Ca-alkyldibenzothiophene
C^-alkyldibenzothiophene
C5-alkyldibenzothiophene
Fluoranthene
Pyrene
Methylfluoranthene/pyrene
C?-alkyIfluoranthere/pyrene
C3-alkyIfluoranthene/pyrenc
Cu-alkylfluoranthene/pyrene
Naphthabenzothiophene
Cs-phenanthrene/anthracene
C3-alkylchrysene/benzanthracenes
Listed compounds were detected in vapor samples or were present in liquid
streams at concentrations of 10 ppm or greater.
195
-------
TABLE 5-34. POTENTIALLY HAZARDOUS SPECIES IN VAPOR
SAMPLES FROM REFINERY STREAMS
Potentially Hazardous Species Concentration in
Vapor Samples From The, Various Sampled
Streams
0.01 - 0.1 ppb
0.1 - 1.0 ppb
> 1.0 ppb
Benzene —
Isopropylbenzene —
Trimethyl benzenes —
Naphthalene 1, 4
Anthracene/Phenanthrene 1, 2, 3
Biphenyl 1, 3, 4
Methyl naphthalene 2, 4
Perylene —
Benzo(a)-pyrene 1
Benzo(e)-pyrene —
Methylcholanthrene —
Benzanthracenes — -
Pyrene 1, 2, 3, 4
Fluoranthene 1, 2, 4
Benzofluorenes 1
Benzo(ghi)-perylene 1
1, 2
1, 4
1, 2
1
Acenaphthene
Fluorene
Phenol
o, m, p-cresol
1
1, 2
1
1, 4
1
—
4
1
—
—
—
~
Samples taken from leaking vapor or present on particulate matter from FCCU
regenerator flue gas.
See Table 5-35 for stream type identification.
196
-------
TABLE 5-35. VAPOR AND LIQUID STREAM IDENTIFICATION NUMBER
Scream
ID
Number
1
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
Sample
Phase
Vapor
Vapor
Vapor
Vapor
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liq'uid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Stream Type Description
FCCU CO Boiler Flue Gas
Fluid Coker CO Boiler Flue Gas
Resin Fume Oxidation Unit Flue Gas
TCC CO Boiler Flue Gas
API Separator - Inlet Oil
API Separator - Surface Oil
API Separator - Skimmed Oil
Crude Oil Desalter Water
Sour Water Stripper Feed (Water)
Desulfurized Naphtha (from hydrodesulfurization)
Intermediate range Naphtha frqm Atmospheric
Distillation
Naphtha to Hydrotreating (for Reformer
Naphtha to Reforming
Straight Run Gasoline from Atmospheric
FCCU Reflux Accumulator Bottoms
FCCU Separator Bottoms
FCCU Main Fractionator Overhead
Ref ornate
Absorber Lean Oil
Crude Alkylate (Alkylation. Unit)
Feed)
Distillation
Virgin Distillate from Atmospheric Distillation
Desulfurized Gas Oil
Atmospheric Gas Oil
Light Vacuum Gas Oil
FCCU Light Cycle Gas Oil
FCCU Heavy Cycle Gas Oil
TCC Unit Heavy Cycle Gas Oil
Flashed Crude
197
-------
TABLE 5-36. POTENTIALLY HAZARDOUS SPECIES IN REFINERY LIQUID STREAMS
Potentially Hazardous Bpeclea Concentration in Liquid Baaplea from the Various Hydrocarbon fitrcama*
Potentially Hazardous r
Compounds 1Q _ IQQ fpn 10Q _ iQiOOQ pfa > 10>OOT ppB
Denernc 4, 5, 7, 10, 11, 14, 18, 27 5, 12, 13, 15, 16, 18. 19, 20, 26
laopropylbcnzene 4, 5, 10. 11, 14, IB 6, 7, 12, 13, 15, IB, 19, 20, 26
Trtmethyl benzenes 24, 25, 26 4,5,6,7,10,11,12.13,14,18,19,20,21,26,27 IS, 16. 17
1,2,3,4-tetrahydronaphthalene —
Naphthalene 11. 14, IS, 19, 21, 24, 25, 26 4, 5, 7, 12. 18, 20, 26, 27 13, 15, 16, 17, 2)
Anthraccne/Phenanthrene 13, 21. 25 4, S, 6, 7, 25, 26, 27
Blphenyl IB 4. S, 6, 7, 13, 25
Methyl naphthalenes 11, 18, 24 4, 5, 7, 12, IB, 20. 21, 26 6. 13, 15. 16, 25
Perylene -— — —
Benzo(a)-pyrene —- — ~—
Benzo(e)-pyrena -- — —
Benzanthracenea — — —
Pyrene 21 26, 27
Fluorantliene 21 — --
Benzofluorenea -— -- —
Benzr>(g)il)-perylene — — ~
Coroncne -— — -—
Acenaplithene 21 6 ~-
Fluorene 4. IB, 21 5, 6, 7, 25, 27
Phenol — • ~ ——
o, m, p—crcsol -- — ——
3Sec Table 5-35 for Stream Type Identification.
-------
The species listed in Tables 5-34 and 5-36 met one or more of the
following criteria:
• Threshold limit value (TLV) < 5.0 pprav
• Acute local inhalation rating of 3 (Materials which on a
single exposure lasting seconds or minutes cause injury to
mucous membranes of sufficient severity to threaten life or
cause permanent physical impairment or disfigurement).^
* Acute systemic inhalation rating of 3 (Materials which can
be absorbed into the body by inhalation and which can cause
injury of sufficient severity to threaten life following a
single exposure lasting seconds, minutes, or hours).
• Known or suspected carcinogen.
• Detected by analyses in at least one sample.
The stream identification numbers may appear in more than one
concentration range for a given species. Many stream types were sampled
at several different refineries. The resulting analyses showed different
concentration ranges for some species.
5.5 Quality Control
A comprehensive quality assurance program was an integral part of
this program. The quality assurance program for the sampling and analysis
activities included the following elements:
• Formatted data collection forms for direct
keypunching of data recorded in the field.
199
-------
• Repealed sampling of individual sources with the
same and different sampling teams and sampling
equipment .
* Sampling and subsequent analysis of standard
gas mixtures.
• Continuous sample runs over an eight-hour period.
• Daily testing of screening devices on the same
sources.
• Multiple screenings of the same devices by different
engineers.
• Replicate sample analysis and blind standard
analysis in the laboratory.
Some of the more important results of the quality assurance effort
are summarized in this section of the report. A much more detailed descrip-
tion of the quality assurance program is presented in Appendix C (Volume 4)
of this report.
5.5.1 Quality Cpnt rol fo r_ Baggable Source Hydrocarbon Measurements
The quality control precedures for baggable source hydrocarbon
emissions measurement include laboratory analyses of blind standards,
repeated total hydrocarbon (THC) analyses, recovery studies of the sampling
train, and reproducibility of the sampling/analysis from a given source.
200
-------
5.5.1.1 Laboratory Standard Analyses
Regularly scheduled analyses of blind standards were used to
evaluate the daily calibration of the Byron THC analyzer as well as the
stability of the calibration. The percent differences between the known
and the measured concentrations ranged from - 55 percent to + 13 percent.
The average difference was - 1.75 percent with a standard deviation of
10 percent. The 95 percent confidence interval for the mean difference
was -4.7 percent to + .1.4 percent.
5.5.1.2 Replicate Analyses for Total Hydrocarbons
The precision of the nonmethanc hydrocarbon analysis as determined
with the Byron TL1C analyzer were determined from a statistical analysis of
duplicate analyses made at each refinery. The following statistics summarize
the results of the duplicate analyses:
Number of replicate pairs: 130
Pooled standard deviation: 2.4%
Repeatability - maximum difference
expected between 2 readings 95 %
of the time: 6.2 %
95 % confidence interval for mean
reading based on a single analysis: ±4.8%
95 % confidence interval for mean
reading based on the average of
two analyses: ± 3.4%
201
-------
Since the average of two analyses was used in computing leak rates
for all sources, the ±3.4 percent interval best describes the precision of
the THC analysis.
5.5.1.3 Results of Recovery Studies
The overall accuracy of the baggable source sampling and analysis
procedure was evaluated. Known leak rates were generated and measured. The
percentage of the leaking material which was recovered in the sampling train
was used as a measure of overall accuracy. Sixty-three recovery studies were
made at nine of the visited refineries. The induced leak rates ranged from
0.007 to 2.93 Ib/hr. The recoveries ranged from 44 to 161 percent. The
average recovery was 98.7 percent x^ith a standard deviation of 17 percent.
The 95 percent confidence interval for the average recovery was 94.5 to
102.9 percent.
5.5.1.4 RepeatabilityofIndividual Source Sampling
Repeated sampling of leaking sources was done to determine the
variability of the measured leak rate. This variability is due to sampling
procedures, sampling teams, process (leak) changes, and variations in the
actual leak rate. Approximately 16 percent of the sampled sources were
resampled at least one time.
Table 5-37 summarizes the statistical analysis of the repeat QC
samples. The variability for drains is significantly higher than the other
sources while the variability for relief valves is significantly less. The
other sources have a standard deviation averaging about 40 percent or a 95
percent confidence limit based on a single test of ± 80 percent.
Tnis standard deviation of 40 percent is composed of variation due
to analysis, sampling train components, sampling team effect, and variability
in the actual leak rate. The standard deviation for the THC analysis was
202
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TABLE 5-37. SUMMARY OF BAGGABLE LEAK RATE QUALITY CONTROL SAMPLE
l-o
O
OJ
Source Type
Va 1 v e s
Pump Seals
Compressor Seals
Flanges
Relief Valves
Drains
Overall
Number
Of Sources
WlLh QC
65
62
',0
7
16
14
204
Standard
Total QC
Samples
137
133
66
12
30
33
411
Average %
Difference'1
37
44
39
40
IS
71
41
.8
.7
.5
.0
.5
.1
.9 '
Deviation of
Sampling Analysis
36.
41.
38.
39.
19.
59.
40.
6
9
1
1
5
1
7
S5%
Reproducibility of
Sampling/ Ann lysis3
101
116
105
108
54
153
112
.4%
.2%
.6%
.2%
.0%
.7X
.8%
90% Confidence
Interval about a.
Sample Test Result "*
± 71.
± 82.
± 74.
± 76.
± 38.
±115.
t 79.
7X
2%
4Z
6%
27.
8%
8X
'Average % difference - average of pooled percent differences for each source with QC sample.
Where: 7, cliff - [original - QC leak] / (average of original and QC leak).
2Stanaard deviation of sampling/analysis - estiriated standard deviation of the sampling and
analyses procedures for non-methane hydrocarbons. Estimated from the pool individual
percent differences for each QC sample.
395% rcprodiir.Jbility of sampllng/nnnlysls - quantity that will bs exceeded only about 5X
of the time by the difference of two test results on a given source under similar process
cnncl.it inns. The quantity is equal Lo 2.77 x standard deviation.
U90% confidence interval - When tnken about a single test result, 95X of these intervals
would be expected to include the • "actual" leak rate (without bias considerations);
the quantity is equal to 1.S6 x standard deviation.
-------
about 2.4 percent, and the standard deviation for sampling and analysis
of standard gases was about .17 percent. No significant differences between
sampling teams or sampling carts were found, therefore a significant portion
of the variability in the measured leak rates is apparently due to real
variations in the leak rate.
5.5.2 Quality _Contro1. for Hydrocarbon Screening Devices
The Bacharach TLV Sniffer was the principal device used for
screening baggable sources in this study. The Century Model OVA-108 was
also used for some screening activities. Each was calibrated on a daily
schedule. Two concentrations of standard gases were used. Daily calibration
at two concentration levels with standard gases gave consistent, unbiased
readings.
The repeatability of the screening procedure (including vari-
ability of the leak rate) was investigated by performing repeated screenings
on the same source by the same operators. The percent difference between
duplicate readings were less than 75 percent with the TLV Sniffer and below
40 percent for the OVA-108.
5.5.3 Quality Control for Nonbaggable_ Sources
Quality control for nonbaggable sources (cooling towers, waste-
water systems, and process stacks) involved an evaluation of the accuracy
and repeatability of all analytical procedures. Sampling procedures usually
do not lead themselves to accuracy evaluations although day-to-day variations
give an indication of sampling repeatability.
5.5.3.1 Cooling Towers
The total organic carbon (TOC) content of cooling tower water was
determined with a Dohrmann DC 52D TOC analyzer. However, the average
differences for 48 comparisons of the inlet and outlet cooling water gave a
204
-------
standard deviation of 4.2 ppn for the analytical method. This deviation
is greater than desired, and a purge-arid-trap method was developed to obtain
better accuracy.
An evaluation of the purge method showed that an average of 78
to 93 percent of volatile organics in standard mixtures was recovered. These
standard mixtures contained less than 10 ppm volatile organics. The purge
method was preferentially used to estimate losses of hydrocarbons from
cooling towers.
5.5.3.2 Wastewater Systems
The purge and trap method was used to estimate losses of hydro-
carbon from water passing through the wastewater treatment system. Volatile
organic content of inlet and outlet oil layer samples was determined by
gravimetric means. Standard mixtures of volatile hydrocarbons in a base
oil were prepared. The average percent recovery of volatile hydrocarbons
from these standards was 98.3 percent. The 95 percent confidence interval
for the average recovery is 98.3 ± 3.5 percent.
5.5.3.3. Process Stack Emissions
The major emphasis on quality control for stack samples was on
strict calibration of metering and temperature control, devices, leak testing,
and laboratory standard analysis.
Upon arrival at each refinery site and before setting up on a
stack, all equipment was examined, set up, and the operation of all
thermometers/thermocouples, pumps, and flow meters was checked. All measure-
ment devices were calibrated. All fittings and equipment were checked for
leaks both on the grcmnd and when set up on the stack.
205
-------
Quality control procedures during the analyses of the stack
samples were primarily analyses of standards. Blind standards were analyzed
for aldehydes, sulfur gases, and NO .
X
The percent differences for Lhe 28 aldehyde standard analyses
averaged 0.9 percent with a standard deviation of 5.2 percent. The vari-
ability appears greater at the lower concentration levels (about ± 12 percent)
than for the higher concentration standards (about ± 6 percent). The aldehyde
analysis procedure is concluded to be unbiased with a precision averaging
about ± 10 percent.
The percent differences for the 18 sulfur analyses averaged 0.5
percent with a standard deviation of 14.6 percent. Only two standards above
100 ppm were tested. The percent differences ranged from - 39 percent to
+ 20 percent, but only three of the 18 analyses were low. The overall
accuracy of the method for concentrations below 100 ppm is about ± 30 percent.
The three standard analyses for NO ranged from 21 percent to 73
percent low, indicating potential inaccuracies in the method.
5.6 Survey Information
There are many factors in a refinery which might contribute
directly to the fugitive emission load or indirectly affect the overall
emission level. However, they do not lend themselves to direct sampling.
Among these factors are maintenance practices, laboratory techniques, unit
shutdown procedures, blind changing procedures and blending operations. In
order to evaluate the.se items, a general survey form for each of them was
submitted to the refiner. The results are summarized below.
206
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5.6.1 Maintenance Practices
Generally speaking, the refineries used combinations of in-house
and contract maintenance personnel. The in-house maintenance people did much
of the routine maintenance, and supplemental contract labor was used during
turnarounds and larger maintenance projects.
Some form of preventive maintenance program was in force at five
of six refineries. In one refinery an inspection of each unit is performed
once a year. Piping, furnace tubes, etc. are replaced if it is felt that
they might fail during the following year. Pumps, valves, flanges, etc. are
inspected and adjusted/replaced only when a problem is reported.
At another refinery, however, a preventive maintenance program is
practiced on instrumentation, electric motors and pumps. This includes a
prescribed maintenance schedule for each piece of equipment. The packing
and seals of pumps, valves, etc. are routinely inspected by operating
personnel. Some minor adjustments may be made when the need is observed.
More extensive work is done by maintenance personnel.
In five of the six refineries, equipment files are kept on pumps
and compressors. Seal failures and packing leaks are recorded. However,
valve maintenance records were kept at only one refinery included in this
summary report.
Three of the six refineries reported that 17 percent, .18 percent
and 20 percent of the operating budget is devoted to maintenance. One
reported that 44 percent of its manpower was devoted to maintenance.
Significant differences in emission rates were not found among the
refineries. This would indicate that the variations in maintenance programs
found do not affect the emissions rates.
207
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5.6.2 process Unit Turnaround Procedures
Most normal maintenance in a refinery can be performed while
running, but some major items require that the unit be shut down and opened.
The entire unit must be purged of all hydrocarbons and tested to insure that
it is "gas free." This large scale overhaul of a processing unit is called
a "turnaround."
The following purging procedure is typical of industry practice.
The unit is shut down and process gases are vented to a vapor recovery
system, if available, or to the f2are. Then steam is charged to the unit
to strip out the remaining hydrocarbons. Most of this steam is vented to a
closed blowdown system which will remove condensed water and route the gases
to the flare. A f.ew "high-point" vents are opened to the atmosphere during
the latter stages of steaming out. The amount of hydrocarbons lost at this
point is not known. However, the concentration of hydrocarbon in the unit
should be low by that time. At that point, the steam flow is stopped and
the unit is cooled, thus condensing the steam. The condensate is drained
off. Then the vessel manways are opened and the interiors are gas tested.
This procedure is thorough and effective, and its overall impact on fugitive
emissions is negligible, especially in light of the infrequent nature of its
occurrence.
The frequency of shutdowns for various units at one refinery is
presented in Table 5-39.
5.6.3 Blind Changing
Only when handling very expensive and exotic materials, such as
some lube oil stocks, would the use of blinds be warranted as a means of
controlling direction of flow to prevent any cross-contamination. The
refineries reported that they do not routinely change any significant number
208
-------
TABLE 5-38. SHUTDOWN FREQUENCY
Crude Unit
Crude Unit
Catalytic Cracker
Fuel Reformer
Naphtha HDS
Alkylation
Aromatics Reformer
AromaLics Extraction
Times Down in
Last 12 Months
1
1
1
0
0
1
2
1
Scheduled Period
Between Turnarounds
1 year
1 year
1 year
1 year
3 years
1 year
1 year
3 years
209
-------
of blinds. Most blind changing takes place during the startup or shutdown
of a unit, and at these times, the unit has generally been purged of
hydrocarbons.
5-6.4 SamplingProcedures
Quality control sampling of light ends and volatile hydrocarbons
in refineries has the potential for adding to the overall fugitive, emission
rate. General surveys were made of sampling, flushing and sample waste
disposal procedures.
At one large refinery, laboratory personnel were observed while
drawing routine liquid samples in the field. Line flushings were routed to
a covered oily water drain system with a maximum of 18 inches free fall and
minimum exposed retention time (i.e., less than two minutes). Readings were
taken with the J. W. Bacharach "TLV Sniffer" at the drain entrance immedi-
ately before and after sampling. No significant difference in readings was
discernible, and the absolute parts per million readings were below the
selected sampling limit of 200 ppm. These procedures were typical of those
performed at visited refineries. However, hydrocarbon screening during
sample collection was not done at any other refinery.
The overall sample load at one large refinery was approximately
200 samples per day. Of these, about 40 percent were gas samples for
chromatographic analysis, about 24 percent were volatile liquids (naphtha
or lighter), and about 36 percent were nonvolatile liquids. Sample wastes
were emptied into one of two slop oil collection systems, one for naphtha
and one for heavier materials.
Daily sample loads of 50 to 200 samples per day were reported by
four refineries.
210
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PART B
REFINERY TECHNOLOGY REVIEW AND ENVIRONMENTAL ASSESSMENT
The results of the field measurement program were combined with
data from other sources (literature, government agencies, vendors, etc.) to
develop refinery control technology reviews/evaluations, refinery technology
characterizations, and an environmental assessment of refineries. Section
6 describes potentially hazardous compounds which were found in selected
refinery streams or which might be present in refinery emissions. Refinery
process technology is characterized and control technology is reviewed in
Section 7. An environmental assessment of petroleum refineries is contained
in Section 8.
211
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6.0 POTENTIALLY HAZARDOUS SUBSTANCES
The objective of this section is to present an overview of
potentially hazardous substances which are found in refinery feed,
intermediate, product, and waste streams. Since the potential for fugitive
emissions exists for a wide variety of process equipment, all materials
utilized in refining operations can be emitted to the atmosphere.
The term hazardous is used here to describe a compound which has
shown the potential to cause adverse human health effects. The use of the
term hazardous does not necessarily indicate that the chemical compound
has been designated as hazardous, in a regulatory sense, by EPA. A few
compounds (e.g., benzene) do fall within this legal definition of
"hazardous". For these reasons, the term "potentially hazardous" is
used in many instances to indicate that while the substance has the
potential for causing adverse health impact, it may not be classified by
EPA as hazardous, in a legal sense.
The origin of potentially hazardous substances is discussed in
Section 6.1. Included are substances or classes of substances which
enter the refinery as raw materials. Raw materials include the crude
oil as well as numerous other chemicals required for processing. Also
included in this section are substances which are formed or concentrated
within refinery processes.
Section 6.2 contains a discussion of potentially hazardous
substances leaving the refinery as constituents of the product streams
or of solid and liquid waste streams. Also included in this section is
information on the destruction of certain substances during processing.
Section 6.3 contains information on atmospheric emissions of
potentially hazardous substances. Emissions from both point sources and
fugitive sources are included. This section concludes with a discussion
212
-------
of factors which affect atmospheric emissions of potentially hazardous
substances. These factors include the type of refining, the processing
scheme, and the properties of the incoming crude oil.
6. 1 Origin of Potentially Hazardous Substances
Many hazardous substances enter the refinery with the raw
materials. Others are produced within various process units. Particular
compounds or groups of compounds which enter via the above mechanisms are
discussed below.
6.1.1 Potentially Hazardous Substances in Refinery Raw Materials
Many of the potentially hazardous substances found within
petroleum refineries enter the refinery as constituents of crude oil.
Classes of potentially hazardous materials include hydrocarbons, sulfur
compounds, nitrogen compounds, and trace elements.
Hydrocarbons—A list of potentially hazardous hydrocarbons which
have been identified in crude oil is given in Table 6-1. The compounds
included in the table have been assigned either a threshold limit value (TLV)
by the American Conference of Governmental Industrial Hygienists or a
rating of 2 or 3 (capable of causing permanent damage to humans) by Irving
Sax in Dangerous Properties of Industrial Materials, 1975 edition.26
A complete listing of all potentially hazardous substances of
crude oil would be nearly impossible since there can be more than 3,000
r\ rj
compounds in any one crude."
One group of hydrocarbons, commonly called polynuclear
aromatics (PNA's), has received considerable attention due to their
hazardous nature. These compounds are composed of fused aromatic, rings and
213
-------
TABLE 6-1. POTENTIALLY HAZARDOUS3 HYDROCARBONS
IN CRUDE OIL
Compound Concentration
Methane T
Ethane T
Propane m
Methylpropane T
Butane m ->- M
Methylbutane m
n-Pentane m
2,2-Dimethylpropane T -> m
n-Hexane tn
2-Methylpentane m ->• M
3-Methylpentane m
2,2-Uimethylbutane m
2,3-Dimethylbutane m
n-Heptane m-M
2,3-l)imethylpentane m
2,4-Dimethylpentane m
n-Octane m
2-Methylheptane m
2,3-Dimethylhexane m
2,3-Diroethylhexane m
2,3,4-Trimethylpentane T
n-Dodecane T -»• m
Cyclopentane m
Cyclohexane m
Methylcyclohexane m -> M
Cycloheptane m
Benzene T ->- m
Toluene T -»- m
Ethylbenzene T ->• m
Dimethylbenzene (Xylene) T -* m
n-Propylbenzene m
Isopropylbenzene (Cumene) ra
1,2,3-Trimethylbenzene m
1,3,4-Trimethylbenzene m
1,3,5-Trimethylbenzene m
Isobutylbenzene ra
sec-Butylbenzene m
tert-Butylbenzene m
l-Methyl-5-Isopropylbenzene m
1,2-Diethylbenzene m
1,3-Diethylbenzene m
(Continued)
214
-------
TABLE 6-1. Continued
Compound Concentration
1,4-Diethylbenzene m
l-Methyl-4-tert-butylbenzene T
1-Methylnaphthalene T
2-Methylnaphthalenc M
Pyrene T
Coronene T
Benzo(a,e)pyrene T
1,2,3,4-Tetrahydronaphthalene T
Biphenyl T
Acenaphthene T
Benzofluorenes T
Phenanthrenc T
Benzophenanthrene T
Naphthenophenanthrenes T
Dinaphthenophenanthrenes T
Trinaphthenophenanthrenes T
Tetranaphthenophenanthrenes T
Pentanaphthenophenanthrenes T
Fluoranthrenes T
Perylene T
Phenyleneperylene T
Dibenzopcrylcne. T
Chrysene T
Benzo(g)chrysene T
3-Methylchrysene T
Naphthenochrysencs T
Anthracene T
Bcnzanthraceno T
Sources: References 28,29,30,31,32,33,34,35,36.
The compounds included in this list have either been assigned a
Threshold Limit Value (TLV) by the American Conference of Governmental
Industrial Hygienists or assigned a rating of 2 or 3 (capable of causing
permanent damage) by Irving Sax in Dangerous Properties of Industrial
Materials, 1975 edition.
Key to concentrations: T = trace: <100 pptn
m = minor: 100 ppra to 2.99%
M = major: >3.0%
215
-------
are found in crude oils at levels of up to 0.1 percent. Several of
these materials are known carcinogens.
Sulfur Compounds—The sulfur content of crude oil can vary
from 0.06 to 8.0 weight percent.38 Sulfur is incorporated into the
structure of a variety of hydrocarbons and tends to concentrate in
compounds of higher molecular weight.
Potentially hazardous sulfur compounds in crude oil include
trace quantities of 48 thiols, almost 200 sulfides, and a number of
sulfites, sulfonates, and sulfones. In lower boiling point fractions
(up to 400°F), mercaptans (thiols) appear to predominate. Cyclic
mercaptans appear in the kerosene range; thio-ethers and cyclic sulfides
in the naphthenes. in higher boiling fractions, there is a tendency
toward sulfur substitution in saturated rings.
NitrogenCompounds—The nitrogen content of most crude oils
is less than 1 percent.38 Approximately one-fourth to one-third of this
nitrogen is contained in basic compounds including alkyl-substituted
quinolines and pyridines. All of these alkyl quinolines and some of the
pyridines have been designated potentially hazardous by the criteria in
Table 6-1. Other hazardous nitrogen compounds in crude oil include
indole and the carbazoles.
Oxygen Compounds—Crude oil generally contains less than 2 percent
oxygen. The oxygen compounds designated as potentially hazardous by the
criteria in Table 6-1 include the lower molecular weight carboxylic
acids and alkyl ketones, and some cyclic ketones and phenols.
Trace Metals—Trace quantities of a number of metals have been
found in crude oil. Twenty-eight metals, most of which are considered
potentially hazardous, are listed in Table 6-2. Of the metals listed,
vanadium, nickel, and iron are usually present in the greatest quantities.
216
-------
TABLE 6-2. TRACE METALS FOUND BY SPECTROGRAPHIC
ANALYSIS OF ASH FROM CRUDE OIL
Ag
Al
As
B
Ba
Ce
Co
Cr
Ca
Cu
Fe
Ga
K
La
Mg
Mn
Mo
Na
Nd
Ni
Pb
Sn
Sr
Tl
V
Zr
Zn
U
Source: Reference 39.
In addition to crude oil, a variety of other raw materials
enters the refinery. These materials, many of which are considered
potentially hazardous, are used as treating agents, solvents, catalysts
or additives.
Catalysts—Both solid and liquid catalysts are used in a wide
range of petroleum processing operations. The hazardous nature of liquid
catalysts such as hydrofluoric, sulfuric, and hydrochloric acids is well-
known. Many of the solid catalysts contain metals listed as hazardous
in Table 6-2.
Catalyst fines are emitted to the atmosphere during catalyst
regeneration. Most catalysts are regenerated only a few times a year;
therefore, the escaping catalyst fines are considered insignificant.
Fluid catalytic cracking catalysts, on the other hand, are regenerated
continuously. In this case, particle collection devices are used
extensively to control the emissions, both for environmental protection
and for economic reasons. Table 6-3 lists some of the commonly used
catalysts and the processes in which they are used.
217
-------
TABLE 6-3. PRINCIPAL APPLICATIONS OF CATALYST MATERIALS'
ho
M
00
Alumina
Aluminum chloride
Antimony trichloride
Bauxite
Bentonite clay
Clay
Cobalt-molybdena
Cobalt molybdate
Cobalt oxide
Copper
Copper pyrophosphate
Hydrochloric acid
Hydrofluoric acid
Iron oxide
Kaolin clay
Magnesia
Processing Application
Crack-
ing
Reform-
ing
Hydro-
treating
Isomeri-
zatlon
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Alkyla-
tion
Many catalyst materials are also used for other purposes in a refinery.
Source: Reference 40.
X
X
Polymer-
ization
Molybdena
Molybdenum
Nickel sulfide
Phosphoric acid
Platinum
Potassium X
Rhenium
Silica-alumina X
Sulfuric acid
Tungsten nickel sulfide
X
X
X
X
X
X
X
X
X
X
X
X
-------
Gasoline Additives—Gasoline is the primary product in many
refineries. Additives arc introduced to improve the burning characteristics
and other qualities of the gasoline. These additives include:
• Antiknock compounds such as tetraethyl lead or
similar alky1-lead compounds.
• Metal deactivators.
• Anti-corrosion additives.
• Anti.sta.il additives including light alcohols, polyalkylene
glycols, and alkyl phosphates or amines.
• Antipreignition agents containing phosphorus compounds.
• Luhricants.
Many of these materials are potentially hazardous and some can
form hazardous combustion products.
Other chemicals—Numerous other chemicals are utilized during
the refining process. And, many are considered hazardous. Some of the
major chemicals used in refining are listed with their principle uses
in Table 6-4.
6.1.2 Potentially Hazardous Materials Produced in Refining Processes
Many of the potentially hazardous materials found in refinery
process streams are produced within the process units rather than entering
with various raw materials. Alternatively, certain other processes serve
to concentrate hazardous materials, either as product or intermediate
219
-------
TABLE 6-4. MAJOR CHEMICALS USED IN REFINING AND
THEIR PRINCIPAL USES
Chemical
Uses
Acetic Acid
Acetone
Aluminum Chloride
Aluminum Oxide (Bauxite)
Aluminum Naphthenatcs
Aluminum Phenates
Aluminum Soaps
Aluminum Stearate
Barium Hydroxide
Barium Salts
Break up emulsions
Increase treating of sul.furic acid
Reduce sulfur content
Extract polymers from cracked
distillates
Separate waxes
Regenerate clays
Isolate benzene in azeotropic
distillation
Solvent in determining oil content
of waxes
Cracking, alkylation, and iso-
merization catalyst
Cracking catalyst
Detergent additive for lubricating
oils
Treat spent caustic solutions
Neutralize acid-treated oils
Precipitate naphthenic acids
Prevent foaming before caustic soda
treating for mercaptan removal
Remove inorganic salts from furfural
before refining
Oxidation inhibitors, detergent
additives in lube oils
(Continued)
220
-------
TABLE 6-4. Continued
Chemical
Uses
Benzene
Bone Char
Cadmium-Ammonium
Chloride
Cadmium Hydroxide
Cadmium Chloride
Cadmium Sulfide
Cadmium Oleate j
Cadmium Naphthenate /
Cadmium Dithiocarbamate
Cadmium Sulfonate
Calcium Oxide
Calcium Hydroxide
Calcium Carbonate
Calcium Chloride
Calcium Hypochlorite
Chlorine
Solvent extraction to improve viscosity
index of lube oils and remove waxes-
Decolorize oil
Distillate Desulfurizing
Oxidation inhibitor in lube oil
De.tergent additive
Neutralize acid-treated oils
Remove hydrogen sulfide and organic
acids from oils
Dessicant
Oxidize sulfides and mercaptans in oils
Oxidize dlsulfides to sulfonyl halides
and to remove mercaptans
Regenerate Bcntonite clay
Regenerate sodium plumbite "doctor
solution"
Prepare calcium and sodium hydroxide
Improve cetane number of fuels
(Continued)
221
-------
TABLE 6-4. Continued
Chemical
Uses
Clays
Cupric Chloride
Cresol
Dichloroethyl Ether
Ethanolamines
(MEA, DEA, TEA)
Ethylenc Bichloride
Ethylene Glycol
Formaldehyde
Furfural
Hydrogen
Adsorbents to improve color, odor, and
stability of waxes and lube oils
Cracking catalysts
Convert mercaptans to insoluble
disulfides
Extraction of high-viscosity-index,
light-color, ,1 ow-carbon-residue
lubricants from residual or
distillate base stock
Solvent in chlorex extraction to
improve viscosity index and yields
of paraffinic oils
Removal or recovery of water, hydrogen
sulfide, or carbon dioxide from
gaseous streams
Removing wax from lube oil
Selective recovery of benzene, toluene,
and xylenes from petroleum stocks
Laboratory reagent and solvent
Extraction of diesel fuels, burning
oils, cracking stocks, and crude oils
Removal of low-eetane materials,
unstable and acidic materials, sulfur,
organometallic and nitrogen
compounds
Extraction of aromatic, naphthene,
olefinic, and unstable hydrocarbons
from lube oils
Hydrotreating
Hydrocracking
Hydroalkylation
(Continued)
222
-------
TABLE 6-4. Continued
Chemical
Uses
Hydrogen Fluoride
Methyl Ethyl Ketone (MEK)
Methyl Isobutyl Ketone
(MIBK)
Natural Oils
Nitrobenzene
Phenol
Phosphorous Compounds
Phosphorous Pentoxide
Potassium Hydroxide
Potassium Phosphate
Propane
Sodium Carbonate (Soda Ash)
Sodium Hydroxide
(Caustic Soda)
Sodium Hypochlorite
Alkylation Catalyst
Remove wax from oils
Deoiling high-quality waxes
Production of lubes and greases
Extract carbon and sludge-forming
compounds from lube oils
Extraction of high-viscosity-index,
high-color, low-carbon-residue
lubricants from residual or
distillate base stock
Improve viscosity index, color and
oxidation resistance, and to reduce
carbon and sludge-forming tendencies
of lube oils
Polymerization catalysts
Catalyst for air-blowing of asphalt
Remove acids from petroleum
Remove hydrogen sulfi.de from gas
Solvent, extractions-deasphalting,
dewaxing, and decarbonizing
Neutralize acids in processing streams
Remove acidic substances
Sweeten gasoline
(Continued)
223
-------
TABLE 6-4. Continued
Chemicals
Uses
Sodium Phenolate
Sodium Plurabite
Sulfur Chlorides
Sulfur Dioxide
Sulfuric Acid
Toluene
Trichloroethylene
Remove hydrogen sulfide from gasoline
Stabilize color of gasoline
"Doctor sweetening" agent to convert
raercaptans to disulfides
Solvents
Extract aromatic, hydrocarbons and
sulfur-bearing compounds from
paraffins and naphthenes
Improve viscosity index and remove
waxes from lube oils
Remove aromatics from kerosene
Remove or dissolve resinous and
asphaltic materials and sulfur
Remove waxes from lube oils
Extract carbon- and sludge-forming
constituents of lube oils and
increase their viscosity index
Source: Reference 40.
224
-------
streams, or as waste streams. Examples of hazardous materials production
or concentration are discussed in this section.
Hydrogen Sulfidc—Hydrogen sulfide is an extremely toxic gas.
It is found in small quantities in crude oil and is produced in a variety
of refining operations including reforming, desulf irrigation processes,
coking, catalytic cracking, and hydrocracking.
The H2S from these processes is usually concentrated in acid-gas
absorption processes for use as sulfur plant feed. Common absorption
processes utilize aqueous solutions containing an alkanolamine such as
moncthanolamine (MEA) or diethanolamine (DEA) as the absorbing agent.
Mono-aromatic Hydrocarbons—A variety of mono-aromatic hydro-
carbons are considered potentially hazardous. The simplest component
in this group, benzene, is suspected of being carcinogenic and has been
officially designated by EPA as a hazardous compound. These compounds
are produced and purified for use in gasoline, petrochemicals, plastics,
and synthetic fibers.
A refinery's major source of aromatics is usually the catalytic
reforming unit. Here, hydrocarbon molecules containing six or more
carbon atoms are converted to aromatics. This type of processing is useful
in increasing the octane rating of certain naphthas. Products from these
processes include benzene, toluene, xylenes, and other substituted
aromatics.
Aromatic hydrocarbons are found in varying concentrations in a
large number of refinery streams. The results of analyses conducted during
this program for aromatics in 60 refinery streams are given in Appendix B
(Volume 3) of this report.
225
-------
Polynuclear Aromatic Hydrocarbons—As was previously discussed,
polynuclear aromatic hydrocarbons are found In abundance in coal tar and
are minor constituents of crude oil. Environmental concern over these
compounds centers on the carcinogenic activity of certain PNA compounds.
Several, most notably benzo(a)pyrene, have been shown to induce cancer,
while others are suspected carcinogens or may inhibit or accelerate
the activity of benzo(a)pyrene. Hazardous PNA's have been identified or
1, y
are suspected to be in the following refinery streams.
• Catalyst regeneration gases from fixed-bed desu.lfurization,
hydrocracking, and sweetening processes.
• Fluid catalytic cracker regenerator off gases.
• Fluid catalytic cracker cycle oil streams.
• Fluid coking off gases.
• Asphalt blowing off gases.
• Decoking operations.
• Oil-fired heater f.lue gas,
• Certain brines and sour water condensates.
• Flare combustion gases.
• Heavy oil sludges, wastewater system sludges, and
spent catalysts.
The above list represents potential sources of atmospheric
emissions of PNA's. PNA's have also been identified in other refinery
226
-------
streams in samples analyzed during this program. The results of these
analyses are given in Appendix B (Volume 3) of this report.
Carbon Monoxide—Carbon monoxide is formed as a result of
incomplete combustion. It is found in process heater flue gas and in
the off gas formed during catalyst regeneration. By far, the largest
source of CO in refining operations is FCC catalyst regeneration. The
flue gas contains CO in concentrations ranging from 5-10 percent. This
gas is usually burned in a CO boiler to recover the energy content of
the off gas.
Other Potentially Hazardous Materials—A list of potentially
hazardous materials has been provided in Table 6-5. For each material,
a list of processes is given in which that material has been identified
or is suspected present. These processes are listed as numbers and may be
identified by referring to Table 6-6.
6.2 In-Line Fate of Potentially Hazardous Substances
Potentially hazardous materials present in refining streams
must eventually leave, the refinery. Many of these mate.rials leave as
components of the final products. Examples of this are discussed in
Section 6.2.1.
Additional hazardous materials exit as components of the numerous
waste streams generated during refining. Some of these waste streams
require additional, treatment or careful disposal to minimize environmental
danger. Potentially hazardous constituents of various waste streams are
discussed in Section 6.2.2.
Other hazardous materials may be destroyed prior to leaving the.
refinery. This may occur as a by-product of a refining process, or as
a result of specific efforts to remove the material in question. Examples
227
-------
TABLE 6-5. HAZARDOUS CHEMICALS POTENTIALLY EMITTED
FROM PROCESS UNITS
Cnealcal
Halelc Acid
Betuolc Acid
Cresyllc Add
Acetic Acid
Foralc Acid
Sulfurlc Acid
DtethylaBlne
Methylelhylamine
Arcxutic Awines
Amnonii
Chlorides
Sulfates
C« routes
Kilones
Aldehydes
Formaldehyde
Acetaldehyde
Carbon Monoxide
Sulfur Oildes
Nitrogen Glides
Pyridines
Pyrroles
Qvinolines
Indoles
Furins
Benzene
Toluene
lylene
Phenol
Dinethylphenol
Cresols
Xylenols
Thiophenols
Cirbaioles
Anthracenes
8enio(a)pyrene
Pyrene
ftenzo(e)pyrene
Perylene
tenzolghOperylene
Coronene
Phenanthrene
Fluoranthrene
Httilloporphrfns
Nickel Csrbonyl
Cobalt Carbonyl
Tttraethyl Lead
Sulfides
Sul fates . '
Sulfonates
SuHones
NercapUns
Thiophenes
Hydrogen Sulfide
HethylnercipUn
Carbon Dtlsulfide
Cirbonyl Sulfidt
ThlosuUide
Dtbenzothiopher*
AUyl SuUide
Vanadium
Nickel
Lead
Zinc
Gobi It
Molybdenum
Copper
Strontium
Biriutn
Sulfur Partlculatcj
Catalyst Fines
Code Fines
Cyanides
Potential Emission Source
Process Module ttunbm
\ ,2,3.«.7,16.17.18.19,20.22.23,», 25.26.27.28.30
1,2.30
3,7.16.17.18.19.20.Z2.23.24.25.26.27.28.30
4.30
4.30
27.30
4.S.3D
4.5,30
18.19.26,30
3.S.7.16.17.IB.19.20.22.23.24,25.26.27.30
1.2.30
27.30
30
1.2.3.7.16.17.18.19,20.22,23,24.25.26,27.30
1.2.3.7 ;i6.17.18.19,20.22.23,24,25.26.27,30.32
-18,19,26
18,19.26
5,9,10,12,13.16.17,18,19,20.22.24,25,26,27.32
5,10,13,16,17,18,19,20.22,24.25,26,27,32
31.32
1,2,3.7,16,17,18,19,20,22.23,24,25.26.27,28,30
1.2.3,7,16.17,18.19,20.22,23,24,25,26,27,28,30
28.30
18,19.26.30
28.27,30
1,2,3.7,10,13,14,16,17.18.19,20.21.22,23,24,25,26,27,28,29.30
1.2.3,7,10,13,14.16,17.IB,19,20,21.22,23,2<.25,26,27,28,29,30
1.2.3.7.10,13,14.16.17.18,19.20.21,22,23,24,25.26,27,28,29.30
1.2.7,18,19,25,26.28,30
1.2,27
1,2,7.18,19.25,27,28,30
7.18,19,25,26,27,28,30
26,30
1,2,28,30
1.2.18,19,26,28.30
18,19,26.28,32
18,19,26.30
18,19.26
18,19,26,30
18.19
18.19.26
18.19.26
18.19.26
1.2.30
10,16,17,20.22,24.27
10.16,17,20,22,24,27
14,21
3,7.15,16,17,18,19,20,22,23,24,25,26,27,28,29,30
30
3,7.16,17.18,19,20,22.23,24,25,26,27,28,29,30
30
1,10,15,26,30
1,2,3,7,16,17.18,19,20,22,23,25,25,26 ,27 ,28,30
1.3,5,7,10,13,15,16,17,18.19,20,22,23,24,25,26,27
3.4,7,16.17,13,19,20,22.23,24.25,26,27
4,5,10.16,17,18,19,20,22,24,27
a.5.ID,13.16.17.IB,19.20.22.24,27
4
28
28
1,2.10.16.17.18.19.20,22,24.25.26.27,28,30.32
1.2.10.16.17,18.19.20.22.24.25,26,27,28.30.32
1.2.32
1.2.18,19,25,26.28.30
10,16,17,20.22,24.27
10.16,17,20.22,24,27
18.19,25,26,28,30,28
23
28
5
9.10.12.16,17.18,19,20.22.24.27
10.16.17,20,22.24,25.26,27.32
4.5.18,19,26,30
Source: Reference 42.
228
-------
TABLE 6-6. LIST OF PROCESS UNITS FOR TABLE 6-5
1 Crude storage
2 Desalting
3 Atmospheric distillation
4 Acid gas removal
5 Sulfur recovery
6 Gas processing
7 Vacuum distillation
8 Hydrogen production
9 Polymerization
10 Naphtha HDSa
11 Alkylation
12 Isomerlzation
13 Catalytic reforming
14 Light hydrocarbon storage & blending
15 Chemical sweetening
16 Kerosene HDS
17 Gas oil HDS
18 Fluid bed catalytic cracking
19 Moving bed catalytic cracking
20 Catalytic hydrocracking
21 Middle distillate storage & blending
22 Lube oil HDS
23 Deasphalting
24 Residual oil HDS
25 Visbrcaking
26 Coking
27 Lube oil processing
28 Asphalt blowing
29 Heavy hydrocarbon storage & blending
30 Wastewater treating
31 Steam production
32 Process heaters
r\
HDS = hydrodesulfurization
229
-------
illustrating the destruction of certain hazardous materials are included
in Section 6.2.3.
6.2.1 Potentially Hazardous Substances Present in Refinery Products
Refinery Gases—Refinery gases consist of saturated and
unsaturated hydrocarbons in the C-x to C5 range along with varying amounts of
inert gases such as N2, H20, anc^ C02. Also, gases such as H2 and
H2S may be present. These gases might have been part of the original
crude, or they might be by-products of certain process units. Process
units producing refinery gases include atmospheric distillation, catalytic
reforming, fluid catalytic cracking, hydrocracking, hydrorefining, and
coking.
Hydrogen sulfide is often a constituent of raw refinery gases.
It is produced from heavier sulfur compounds during hydrotreating and
hydrocracking processes and is extremely hazardous. In addition to
hydrogen sulfide, many of the hydrocarbons in refinery gases are considered
potentially hazardous.
Aviation Gasolines—Aviation gasolines consist of high octane
hydrocarbons with a boiling range of 85 to 300°F. In general, these fuels
contain a high percentage of isoparaffins and smaller percentages of
naphthenes and aromatics. Although most of the components of aviation
gasoline are not extremely toxic, many are considered potentially hazardous.
In addition, tetraethyl lead is added to prevent knocking.
Jet Fuels—Jet fuels consist of hydrocarbons with a boiling
range of 300 to 460°F. The aromatic content of these fuels is limited
to reduce smoke formation during combustion.
Additives are added to the fuel to control oxidation, to
chelate any copper remaining after refining, to ensure that any water
230
-------
dissolved in the fuel will not freeze, to inhibit corrosion, and to
increase conductivity and thus reduce static electricity. Most
constituents of jet fuel are considered potentially hazardous.
Automobile Gasoline—Gasoline is defined as a petroleum fuel
for use in reciprocating, spark-ignition, internal combustion engines. It
is a complex mixture of hydrocarbons, mostly in the C^ to C^2 ran8c»
which distill between 85°F and 410°F. Gasolines from different refineries
may vary widely in exact composition according to the processes used at
the refinery. A summary of the main components of gasoline and their
sources is given in Table 6-7.
Gasoline contains a relatively high proportion of aromatics,
supplied mainly by the catalytic reforming process. Gasoline also
contains a variety of additives including anti-knock compounds, anti-icing
additives, anti-oxidants, metal deactivators, carburetor detergents, and
anti-corrosion additives.
Distillate and ResidualFuels—A variety of heavier fuels are
manufactured by refineries. These include diesel fuels, heating oils,
gas oils, and fuel oils. Some of these fuels contain PNA's and PNA's
have also been found in their combustion products. Heavier fuel oils
also contain other potentially hazardous materials, including sulfur
and nitrogen compounds.
Solvents (Industrial Naphtha)— A variety of solvents are
produced by refineries. These range from pure hydrocarbons such as
benzene, toluene, xylene, ethylbenzene, hexane, and cyclohexane, to
blends consisting of varying proportions of paraffins, cycloparaffins,
and aromatics.
Asphalt—Asphalt cement is the -material remaining after the
removal of light and heavy distillates from asphaltic crudes. It is
231
-------
TABLE 6-7. MAIN COMPONENTS OF GASOLINE
COMPONENTS
SOURCE
BOILING
RANGE,°F
REMARKS
to
LO
Paraffinic
Butane
Isopentane
Alkylate
Isotnerate
Straight-run
Naphtha
Hydrocrackate
Olefinic
Thermal Reformats
Catalytic Naphtha
Steam Cracked
Naphtha
Polymer
Aromatic
Catalytic
Reformats
Crude oil distillation 30
Conversion processes
Crude ollidistillation 81
Conversion procesaes
IsomerIzatlon of •
n-pentane
Alkylation process 100-300
Isomerlzatlon process 100-160
Crude oil 90-200
distillation
Hydrocracklng 100-390
process
Thermal reforming 100-390
Catalytic cracking 100-390
Steam cracking 100-390
\
Polymerization of 140-390
olefins
Catalytic reforming 100-390
Widely used in proportions
up to 10%.
Widely used as high-octane.
high-volatility component.
Used widely in aviation gaso-
line, but lesa frequently In
motor gasoline.
Relatively little used at
present. Excellent anti-
knock properties under severe
engine conditions.
Widely used low-octane compo-
nent.
Heavy products used as feed
for catalytic reforming. Con-
tains also nromatica.
Obsolescent process.'
Widely used component, par-
ticularly in premium gasoline.
By-product of chemical processes,
High-octane component but not
widely used.
Host widely used high-octane
component of gasolines.
Source: Reference 38.
-------
usually mixed with distillates in varying proportions to obtain materials
for specific purposes.
Cutback asphalts contain lighter distillates such as naphthas,
gasoline or kerosene. They may be medium- or rapid-curing. Emulsified
asphalts are emulsions of asphalt ceraent with chemically treated water.
"Blown asphalt" may be produced by blowing air through a
O Q
residual oil at temperatures usually ranging from 400 to 600°F. Asphalt
blowing operations have been identified as a source of polynuclear
aromatics. Compounds detected in one study included pyrene, anthracene,
^ o
and trace amounts of phenanthrene and fluoranthene. Asphalt also contains
heavier PNA's which apparently are not volatilized at air blowing temperatures.
6.2.2 Potentially Hazardous Materials in Refinery Waste Streams
Potentially hazardous materials in solid or liquid refinery waste
may find their way into ground waters or Lhe atmosphere if improperly
disposed of. Hazardous materials in the more common refinery waste
streams are discussed below.
Storage Tank Bottoms—Crude oil storage tanks contain solid
sediment which accumulates on the tank bottom. This sludge is usually
composed of iron rust, iron sulfides, clay, sand, water, and oil.
Hazardous materials contained in the sludge include various organics
and organo-metallic compounds, and heavy metals found in incoming crude oil.
Tanks containing refinery products will also accumulate sludges
over a period of time. Tanks with leaded products will produce sludges
containing lead residues.
Wastewatcr Processing Sludges—Wastewatcr processing sludges
are produced by operations including primary separation, chemical
233
-------
coagulation and precipitation, air flotation, and biological treatment.
Since refinery wastewaters can contain water utilized in all process units,
they may contain nearly any hazardous material found in the refinery. Many
of these materials are found in the sludge by-product, along with chemicals
used in processing the water. Volatile hazardous materials can readily
leave the wastewater system due to weathering and turbulence generated
by some treating units.
Spent or Neutralized Acid Sludges—Acid sludges are produced
by the sulfuric acid and the hydrofluoric acid alkylation process. In
addition, sulfuric acid is used as a treating agent. Spent acid from
sulfuric acid alkylation is usually regenerated off-site. Spent acid
from hydrofluoric acid alkyiation is usually neutralized rather than
regenerated. Neutralization with lime produces an insoluble calcium
fluoride sludge. Spent sulfuric acid from treating operations may
contain a high proportion of oil.
Spent or Neutralized Caustic Solutions—Large amounts of caustic
are utilized by refineries for the neutralization of acidic materials in
crude oil, the neutralization of acidic products such as those formed in
catalytic cracking, and for use in chemical treatment processes. These
solutions may contain sulfides, mercaptans, sulfonates, phenolates,
napthenates, atmaonia, and various other organic and inorganic compounds.1*3
Coke Fines—Coke fines are produced during decoking operations.
The coke fines produced by attrition may become airborne particulates if
allowed to dry. Additionally, heavy hydrocarbons entrained in the coke
may be released during the coke cutting procedure. Often, vapors are
condensed during the earlier stages of decoking to recover heavier
hydrocarbons. A water quench is used to minimize particulate emissions.
234
-------
The feedstock to the coking unit is usually atmospheric or
vacuum resicl. Heavy metals present in the feed will concentrate within
kit
the coke product.
Spent Clay—Filter clays are used in removing color bodies,
chemical treatment residues, and trace moisture from gasoline, kerosene,
jet fuel, light fuel oil and lube oil. The spent filter clay forms a
sludge or cake which contains traces of oil and heavy metals.
Spent Catalysts and Catalyst Fines—Solid catalysts are used in
a number of processes. These catalysts are deactivated by contaminants
within the process and must eventually be replaced. These spent catalysts
can contain heavy metals plus organics absorbed from process feedstocks.
In some cases, the spent catalysts are reprocessed to recover their
metals content.
Catalyst fines are produced by attrition within fluid-bed catalytic
cracking units. These fines contain vanadium and nickel and arc emitted
from the catalyst regenerator. The emission of fines frora this source
is reduced by passing the regenerator flue gas through a series of cyclones.
Further reductions are obtained using electrostatic precipitators.
Foul or Sour Water—Distillation products are often stabilized by
steam stripping. The resulting condensate can contain sulfides, ammonia,
mercaptans, phenolics, organic acids, nitrogen bases, and cyanides. Foul
water from the catalytic cracking unit, often high in phenolics, is
occasionally used as raw desalter water. In the desaltcr, the phenolics are
absorbed by the crude oil resulting in lower phenolic loading at the
h 5
wastcwater treatment plant.
235
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6.2.3 Destruction of PotentiallyHazardous Compounds
Several compounds, or groups of compounds which are suspected
to be hazardous are not contained in either the product or waste streams.
Instead these compounds are chemically converted to less toxic materials
during processing. Often, the destruction of these materials is not the
primary purpose of the processing step. In other cases, units arc designed
for specific removal of a particular contaminant. Other hazardous compounds
may be eliminated by pollution abatement equipment. Examples of the
destruction of hazardous materials arc described below.
Hydrogenation Processes—A variety of hydrogenation processes are
utilized by refiners. In most of these processes, potentially hazardous
sulfur compounds are converted to I^S. And, the products of these processes
are often low in residual sulfur. Higher severity hydroprocessing can
also lead to a reduction in the nitrogen content. In this case, potentially
hazardous nitrogen compounds are converted to ammonia.
Hydrogen sulfide and, under certain circumstances, ammonia can
be removed in a Glaus sulfur plant. Tail gas from the. Glaus plant contains
significant quantities of sulfur compounds including ^S, 862, COS, and
CS2. This tail gas is either treated further to remove sulfur compounds or
flared to produce S02, the least toxic of these sulfur compounds.
Destruction of Potentially Hazardous Materials by Combustion—A
variety of potentially hazardous materials may be destroyed by combustion.
These materials include:
• Hydrocarbons (rnono-aroraatics, PNA's, other hazardous
hydrocarbons)
• Organic chemicals
236
-------
Hazardous gases (CO,
• Hazardous solid wastes
The most common types of combustion equipment for waste disposal
include flares, CO boilers, process heaters, and incinerators.
Flares — Flare systems are common to all crude oil refineries.
The use of flares, or any other combustion sources, will, result in the
discharge of combustion pollutants such as SO and NO . Incomplete
X X
combustion can result in carbon monoxide, unburncd hydrocarbons, and smoke
emissions.
Combustion is improved by injecting steam into the combustion
zone. Steam improves combustion by increasing turbulence, by reacting
with the fuel to form oxygenated compounds that burn readily, and by
retarding full polymerization that results in heavier and more difficult
to burn hydrocarbons.
CO Boilers — CO Boilers are commonly used to burn CO in the
catalyst regenerator gas from fluid-bed catalytic cracking units and flue
gas from fluid cokers. Additionally, the CO boiler is also effective
in reducing the levels of aldehydes, cyanides, and hydrocarbons, including
PNA's generated during catalyst regeneration. J
Incineration — Incineration is a disposal technique used to minimize
the volume of combustible wastes. It has been used successfully on
streams such as API separator bottoms, DAF float, waste biosludge, and slop
oil emulsion solids. The resulting product consists of non-combustible
material which occupies only 10 to 20 percent volume of the original waste.1*7
Incineration can be quite effective in destroying hazardous hydrocarbons and
other organic chemicals.
237
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6.3 Atmospheric Emissions of Potentially Hazardous Substances
This section contains information on atmospheric emissions of
potentially hazardous substances. Sources of atmospheric pollutants can
be divided into two groups. The first group, discussed in Section 6.3.1,
consists of process emission sources (point sources). The second group of
sources of atmospheric emissions are fugitive sources. In contrast to
point sources, the emission rates of pollutants from individual fugitive
sources are quite low. However, there, are thousands of Fugitive sources in
refineries, and fugitive emissions constitute a large portion of the total
emissions from the refinery. In addition, fugitive emissions can occur
on lines containing nearly any process fluid. Hence, the potential exists
for atmospheric emissions of nearly every hazardous material in the
refinery. Fugitive emissions of hazardous materials are discussed in
Section 6.3.2.
Section 6.3.3 concludes with a discussion of miscellaneous
factors affecting emissions of potentially hazardous substances. The
various factors considered include the type of refinery, the type of
processing units, and the type of crude oil processed.
6.3.1 Point Sources
There are several operations within the refinery which produce
a waste gas stream for discharge to the atmosphere. Most of these point
sources emit potentially hazardous materials. The quantity of emissions
depends on the size of the unit and the degree to which control methods
have been adopted for the source.
Atmospheric emissions point sources discussed in this section
include:
• FCC catalyst regenerator flue gas
238
-------
• Claus sulfur plant tail gas
• Asphalt blowing emissions
• Process heater flue gas
• Flare emissions
A brief discussion of the mechanism for pollutant formation and
the types of hazardous materials generated is included for each source.
In addition, emission factors or estimates of the quantity of emissions
generated by each source are included where possible.
FCC Catalyst Regenerator Flue Gas—Coke is deposited on cracking
catalysts during processing, and it must be removed to restore catalytic
activity and selectivity. This is accomplished by introducing air into
the regenerator and burning the coke to CO and C02. In conventional
operation, the conversion of CO to C02 is minimized to avoid high tempera-
tures which might damage internal regenerator materials. The resulting
flue gas contains from 5-10 percent CO. Many refiners utilize CO-burning
waste heat boiler to recover the energy contained in the flue gas and to
reduce CO emissions.
Emissions from the FCC regenerator, with and without the use of
a CO boiler, are listed in Section 5. Also given in that section are
the results of sampling conducted during this program. The section contains
a summary of data obtained from five FCC unit CO boiler stacks. Detailed
information on these sampling results is given in Appendix B (Volume 3)
of this report.
Aromatic species from cracking catalyst regeneration operations
were also identified during this study. These compounds are listed in
Tables B5-1 through B5-8 in Appendix B (Volume 3) of this report.
239
-------
Glaus Sulfur Plant Tail Gas-^—Claus sulfur plants are unable to
remove all the sulfur from the acid gas feed stream. Table 6-8 shows the
typical composition of a sour gas feed, the Claus unit tail gas, and the
thermally incinerated tail gas.
Asphalt Blowing Unit Tail Gas—Air blowing is used to improve the
hardness and increase the melting point of asphalt. Available data
indicate that uncontrolled emissions amount to 60 pounds per ton of
asphalt.7 The operating conditions are favorable for the production of
extremely hazardous polynuclear aromatics. The PNA's identified in one
study include pyrene, anthracene, and traces of phenanthrenc and
'i i
rluoranthcne.
Process Heater Flue Gas—Potentially hazardous compounds in the
flue gas of fired heaters and boilers include various sulfur and nitrogen
compounds, carbon monoxi.de, and unburned hydrocarbons. Sulfur emissions
generally occur as S02 and are dependent on the amount of sulfur in the
fuel. Nitrogen oxide (NO ) emissions depend on the nitrogen content of the
fuel but are also influenced by the combustion conditions. Carbon monoxide
and unburned hydrocarbon emissions are usually quite low. However, improper
firing condition can cause a significant increase in emissions of both
carbon monoxide and hydrocarbons.
EPA emission factors for process heaters are listed in Section 7
of this report.
Flares—Flares are. used as final disposal method for hydro-
carbon gases and other waste gas streams. In general, emissions of carbon
monoxide and hydrocarbons from flares are higher than those from process
heaters of boilers. Factors which may account for less effective combustion
in flares include:
240
-------
TABLE 6-8. TYPICAL GLAUS TAIL GAS COMPOSITIONS'
Component
H2S
SO 2
Sg vapor
SB aerosol
COS
CS2
CO
C02
02
N2
H2
H20
B.C.
Temperature, °C
Pressure, atm.
Total gas volume
Sour Gas Feed,
Volune Zb
89.9
0.0
0.0
0.0
0.0
0.0
0.0
4.6
0.0
0.0
0.0
5.5
0.0
100.0
40
1.45
2
Claus Tail Gas ,
Volume Zb
. 0.85
0.42
0.10 as S-i
0.30 as Si
0.05
0.05
0.22
2.37
0.00
61.04
1.60
33.00
0.00
100.00
140
1.1
3.0 x'feed
gas volume
Thermally Incinerated
Tail Gas,
Volume 2b
0.001
0.89
0.00
0.00
0.02
0.01
0.10
1.45
7.39 -
71.07
0.50
13.57
0.00
100.00
400
1
5.8 x feed
gas volume
Two catalytic reactors - overall efficiency of 94%.
Gas volumes compared at standard conditions.
Source: Reference 48.
241
-------
• Variable firing rates which make control of steam and
combustion air flow rates difficult.
• Variable heat values for fuel which may also contain
significant quantities of oleflus or aromatics.
• Relatively low combustion temperatures with short
residence times compared to process heaters and boilers.
Emission factors for smokeless flares are listed in Section 7.
The emissions listed are given as pounds of pollutant per thousand
barrels of refinery capacity.
6.3.2 Fugitive Sources
To quantify fugitive emissions of a particular component, the
emission rate of each type of source emitting that component must be
known. In addition, knowledge of the total number of each source type
and the concentration of the component within the leaking process stream
is also required.
During the course of this program, Radian has accumulated much of
the information required for such an anlysis. Estimates of total fugitive
emissions of a particular component may be estimated in a direct manner
using that data. For example, the following procedure can be used to
estimate the emissions of any hazardous substance from a refinery process
unit. The first step consists of identifying different process streams
characteristic to the unit. Then, the fugitive emission sources, developed
from source counts taken during this program, are divided between the
available process streams.
Finally, the component analyses can be applied to these process
stream emissions. That is, total stream emissions are multiplied by the
242
-------
weight fraction of each component in the process stream. And, total
emissions of a particular component will be the sum of emissions from
all refinery streams containing that component.
Radian has performed this analysis for a number of pure components.
Other components have been consolidated into groups containing compounds
with similar chemical properties. The results of this analysis, given in
Table 6-9, show total fugitive emissions from a large existing refinery
model (see Appendix D, Volume 4) on a component basis. This procedure is
discussed in detail in Appendix D (Volume 4) of this report.
6.3.3 Miscellaneous Factors Affecting Emissions of Hazardous Substances
The characteristics of the crude oil and the type of processing
utilized by a refinery can have a marked effect on the quantity of various
hazardous materials emitted to the atmosphere. Factors influencing
emissions of hazardous substances are discussed below.
Characteristics of Crude Oil—Fugitive emissions sources include
equipment located in every process unit in the refinery. Hence, it is
likely that all materials contained in the crude oil feed to the refinery
will be emitted to the atmosphere to some extnet.
The concentration in crude oil of several groups of potentially
hazardous materials can vary widely. These groups include sulfur and
nitrogen containing compounds, aromatics, and heavy metals. Sulfur and
nitrogen are incorporated into the structures of a wide variety of compounds,
many of which are potentially hazardous. High sulfur crudes may require
substantial hydrodesulfurization to meet product specifications. This
increases the quantity of hydrogen sulfide fed to the sulfur recovery unit
and results in increased emissions of sulfur compounds with the tail gas.
243
-------
K:
*-
•P-
TABLE 6-9. SUMMARY OF HYDROCARBON SPECIES EMISSIONS FROM
FUGITIVE SOURCES IN A LARGE EXISTING REFINERY
MODEL (SEE APPENDIX D, VOLUME 4)
Source
V
CouiponL-nt
Benzene
Toluene
Ethylbcnzene
Xylencb
Other Alkylhenzenea
Naphthalene
Anthracene
Dlphenyl
Other PNA's
n-llexane
Other Alkalies
Olefins
Cycloalkanes
Hydrogen
TOTALS
. r, c, F,
ppmu
7.200
21.000
5.600
31,000
42,000
1,700
20
230
7,700
16,000
651,000
46,000
135,000
31,000
I), CT*
kg/hr
2.8
tt.2
2.2
12.1
16.6
0.7
0.01
0.1
3.0
6.3
255.9
18.1
52.9
12.3
391.2
Kollof Valves
ppmw
23,000
24,000
A, 500
26,000
35,000
1,400
1
110
3,300
9,700
67 8, GOO
30,000
82,000
,82,000
kg/hr
0.4
0.4
0.1
0.4
0.6
0.02
0.0
0.0
0.05
0.2
11.3
0.5
1.4
1.4
16.8
API Scparulors
pptnu
700
2.200
590
2.100
7.900
2,900
390
1.800
1.500
i**
980,000
i.
i.
4.
kg/hr
0.4
1.1
0.3
1.1
4.1
1.5
0.2
0.9
0.8
•I.
502.4
4.
4.
i.
512.8
Totala
ppraw
3,900
11,000
2,800
15,000
23,000
2,400
220
1.100
4,200
7,100
840,000
20,000
59,000
15.000
kg/hr
' 3.6
9.7
2.6
13.6
21.3
2.2
0.2
1.0
3.9
6.5
769.6
18.6
54.3
13.7
920.8
i-fre emissions from valves, pumps, compressors, flanges, drains, and cooling towers.
** Components marked with "-c" are indicated present, but no quantifiable concentration data
v;crc available.
-------
Effect of Processing—An important finding of this program is
that both the frequency and the magnitude of fugitive leaks increase with
increasing volatility of material being processed. Therefore, fugitive
emissions, on a per source basis, are most likely higher from refineries
with substantial light ends processing or refineries producing gasoline as
opposed to heating oil.
245
-------
7.0 REFINERY CHARACTERIZATION AND CONTROL TECHNOLOGY
The individual refinery technologies are described in Section 7.1.
Refinery control technology is discussed in Section 7.2. Existing and
available control techniques are included for fugitive and process emission
sources.
7.1 Re finery Technology Characterization
This section contains a brief description of each of the major
refinery processes and a description of their respective emissions. Emis-
sion factors for fugitive emission sources were determined as a part of the
refinery assessment program.
The estimated fugitive nonmethane hydrocarbon emissions from each
source type and stream category as well as an estimate of emissions from
the entire unit are included for most processes. Many of these estimates
are listed as a range because of variations in the estimated sources and
source distributions. In addition to the source counts and estimates
developed by Radian, a second set of source counts is given for most process
units. These counts were based on information contained in a study by
Pacific Environmental Services (PES).'|J In this study, process flow dia-
grams were used to determine the number of pumps and compressors within
the unit. Other sources were estimated from pump counts.
It must be emphasized that all of the source counts and stream
service distributions given in this report are, at best, rough estimates.
Even those values based on actual source count data should be considered
rough estimates since only a small number of process units were counted.
In addition, source counts for similar types of process units showed large
variations. Therefore, reliable estimates for emissions source counts and
distributions should be obtained for the particular process unit in
246
-------
question rather than using the estimates which are designed to characterize
typical refinery operation.
Additional information concerning the emissions estimates is con-
tained in Appendix B (Volume 3) and Appendices C and D (Volume 4) of this
report. More detailed process descriptions are included in Appendix F
(Volume 5).
7.1.1 Separations
Crude oil is separated by distillation into a variety of inter-
mediate products which are used as feedstocks for downstream processing
units. Boiling ranges of each fraction vary with the intended use for
the fractions.
Higher efficiencies and lower costs are achieved if crude oil
separation is accomplished in two steps: (1) fractionating the total crude
stream at atmospheric pressure, then (2) fractionating under a high vacuum
the high boiling bottoms fraction (topped crude.) from the first fractiona-
tion. A third separation in petroleum refineries is the extraction of
aromatic compounds from reformate streams. These arornatics are then used
in gasoline blending or petrochemical operations.
7.1.1.1 Atmospheric Distillation
Nearly all crude oil feed must pass through a refinery's atmo-
spheric distillation unit before it can be further processed. Atmospheric
distillation separates the hydrocarbon components of the crude into frac-
tions by distillation and steam stripping.
Process Conditions—Typical operating parameters and utility
requirements for an atmospheric distillation unit with a capacity of
24,000 bbl/day are listed below:
247
-------
• Pressure: Atmospheric
• Temperature: 250 °F - at top of fractionator
700°F - at bottom o£ fractionator
• Electricity: 4.1 kW/bbl
• Thermal Energy: 10s 3tu/bbl
• Steam: 50 Ib/bhl
• Process Water: 5C gal/bbl
Potentially Hazardo u s Atmospheric Enijssions—Emissions from atmo-
spheric distillation operations include process heater flue gas emissions and
fugitive emissions. These emissions are summarized in Tables 7-1 and 7-2.
Table 7-3 provides information on the composition of the fugitive emissions.
7.1.1.2 Vacuum Distillation
Vacuum distillation is used to fractionate, topped crude from the
atmospheric distillation unit into a heavy residual oil and one or more
heavy gas oil streams. A vacuum distillation unit is an integral part of
most refineries.
P r o ces_s Condi t ions—Typical operating parameters and utility
requirements for a vacuum distillation unit are listed below:
• Temperature: 750 to 830°F.
• Pressure: 0.4 to 0.7 psia.
• Thermal Energy: 74,900 Btu/bb].
248
-------
TABLE 7-1. TYPICAL EMISSIONS FROM ATMOSPHERIC
DISTILLATION UNIT PROCESS HEATERS
EPA Eaission ?accor
(lb/103 gal-oil fired)
(lb/10s scf-gas fired)
Tocal Emissions
(lb/103 bbl of
crude oil feed)
Oil Fired Heaters
Particulars
- Distillate oil
- Residual oil
Grade 4
Gradft 5
Grade 6
Sulfur Dioxide
- Distillate oil
- 'Residual oil
Sulfur Trioxide0
Carbon Monoxide
Hydrocarbons (as
Nitrogen Oxides
(as NQ2)
- Distillate oil
- Hesidual oile
7
10
10(S)+3
142(S)
157(3)
2(S)
5
1
22
22+400(N)'
1.4
5.0
7.1
101(S)
112(S)
1-4(3)
3.6
0.71
16
16+286(N)'
Gas 7ired Heaters
Particular as
Sulfur Oxides (as SC2)'i'
Carbon Monoxide
Hydrocarbons (as CHu)
Hitrogen Oxides (as N02)
5-15
0.6
17
3
120-230
0.43-L.43
0.057
1.6
0.29
11.4-21.9
aSource: Reference 7.
Based on 3 heat input of l.OxiO5 Btu/bbl of fresh feed with the following
fuel heating values: Oil - 140,000 3tu/gal; Gas - 1050 3tu/scf.
C5 - Wt 2 sulfur in the fuel oil
Improper combustion xay cause a significant increase in emissions
Use this emission factor for residual oils with less than 0.52 QK.5) nitro-
gen content. For oil with higher nitrogen content QJ>0,5}, use emission
factor of L2Q lb/103 gal
Based on sulfur content of 2000 gr/10s scf
249
-------
TABLE 7-2. ESTIMATED FUGITIVE NONMETHAKE HYDROCARBON EMISSIONS
FROM A TYPICAL ATMOSPHERIC DISTILLATION UNIT
ho
Oi
o
Eniiag ions
Source Type
Valvea
(V?
0.1 putj 6 100'F)
Heavy Liquid
< 0.1 pal> % 100'F)
Hydrogen Service
Total
All
Light Liquid
> 0.1 pfilJ 3 100'F)
Heavy Liquid
< 0-1 p«U * 100'K)
To c u 1
All
All
All
Hydrocarbon
Hydrogen
Total
Number of Sources In Process Unit _
•• " Source
founts or Estimates Counts or Estimates Emission
From Radian Study From PES Study >e Factor. Ib/li
80
281
521
0
893"
-
11(15)
20(2B)
31(43)a
69a
3997
6C
1(2)
0
l(2)a
263 - 270 0.059
1663 - 1727 0.024
704 - 703 0.0005
0 0.018
2630 - 2700C
56 - 57b 0.005
26(36)-27(38) 0.25
11 (lb)-ll<15) 0.0',6
37(52)-38(53)b
0.070
8695 - 8930C 0.00056
0.19
0 1.4
0 0.11
0
Estimated Total
Emissions,
ir Ib/hr
5.25 -
6.74 -
0.262 -
0.
12.3
0.280 -
3.75 -
0.690 -
4.44 -
4.
2.24 -
1.
0.0
0.
0.0
25.2 _
15.9
41.4
0.352
0
57.7
0.285
9.50
1.29
10. 6
83
5.00
14
2. HO
0
2.60
82.6
Physically Counted
Counted From Flow
c
dHeference 49.
Ttiiu PES estimate Includes vacuum distillation as part of the crude
distillation unit. Kitdlun ebtlmiitea for emissions from vacuum
distillation are listed In Section 7.1.1.2 and may be added to the
Radian estimates for atmospheric distillation tor comparJson to the
PES estimates.
-------
TABLE 7-3. ESTIMATED COMPOSITION OF NONMETHANE HYDROCARBON FUGITIVE
EMISSIONS FROM A CRUDE DISTILLATION UNITa
Ni
S t rcaei
Estimated percentage ot emissions
attributed to each stream - %
Weighted contribution uf each ,
component to unit emissions - ppmw
Uunzenu
Toluene
Ethylbiinzune
Xy Leiics
Other Alkylbenzenea
Naphthalene
Anthracene
Ulplicny 1
Other I'olynuclear Aror»it5cs
n-ll«>xanc
Other Alkanea
Olefins
Cyclo Alkan«s
Crude
Oil
74
46
522
169
676
2S71
660
108
246
6051
13820
673680
0
44770
Straight run
naphtha
24
59
617
208
382
3904
344
1
147
3528
9167
117660
0
'J9503
Middle
distillate
1
0
0
0
1
8
1
1
0
56
0
8627
0
1024
Atmospheric
gas oil
1
0
0
0
0
1
0
0
0
2
0
9724
0
512
Totals
100Z
105
1139
377
1059
6/84
1005
110
391
9637
22987
&09691
0
145BOO
999096
Based on GC-MS analysis of liquid stream samples (and some vapor samples) ,
Estimates hasc-ri on tho assumption thar fugitive emission compos! t. ion a from
sources in liquid stream service is the same composition as that of the
liquid contained in the emission source.
Compositions are estimated to 2-3 significant figures. Additional significant
figures are a result of calculations! procedures, and they should not be given
any Importance.
-------
• Electricity: 0.10 to 0.20 kW/bhl.
• Steam: 8 Ib/bbl.
Atmospheric Emissions—Emissions from vacuum distillation units
include emissions from steam ejectors and barometric condensers, process
heater flue, gas emissions, and fugitive emissions.
The size and number of ejectors and condensers used are determined
by the vacuum needed and the. vapor load. To maintain a fractionator pres-
sure of no more than 0.4 psia, three ejector stages are usually required.
Process hydrocarbon emissions from steam ejectors have been estimated at
50 lb/10J bbl charge. If barometric condensers are used, emissions may be
as much as 1,060 lb/103 bbl charge. Nonc.ondensable hydrocarbon vapors
removed by the ejector system are released to the atmosphere unless com-
busted in a furnace, firebox or other combustion device. Fugitive emissions
and emissions from process heaters are summarized in Tables 7-4 and 7-5.
7.1.1.3 Aromatica Extraction
Aromatics are extracted from reformate streams by a liquid/liquid
solvent extraction process. There are a number of proprietary commercial
extraction processes. The Sulfolane and Udex processes account for the
majority of commercial installations for aromatics extraction: each is in
use in more than 50 refineries throughout the world. The Tetra process is
installed in more than 35 refineries. Sulfolane, originally developed by
Royal Dutch/Shell, is licensed by the UOP Process Division of COP, 'Inc.,
as Udex. The Tetra licensor is Union Carbide Corporation. Most of the
remaining commercial installations are processes licensed by Howe-Baker
Engineers (Aromcx), Snamprogetti S.p.A. (Formex), and the Institute
Francais due Petrole (IFF).
252
-------
TABLE 7-4. TYPICAL EMISSIONS FROM VACUUM DISTILLATION
UNIT PROCESS HEATERS
EPA Emission Factor
(lb/103.gal-oil fired)
(lb/106 scf-gas fired)
Total Emissions
(lb/103 bbl of
crude oil feed)
Oil Fired Heaters
Particulates
- Distillate oil
- Residual oil
Grade A
Grade 5
Grede 6
Q
Sulfur Dioxide
- Distillate oil
- Residual oil
Sulfur Trioxidec
Carbon Monoxide
Hydrocarbons (as CHi,)
Nitrogen Oxides
(as N02)
- Distillate oil
- Residual oile
7
10
10(S)+3
142(S)
157(S)
2(S)
5
1
22
22+400(N)'
1.4
5.0
7.1
7.1(5)4-2.1
112 (S)
3.6
0.71
16
16+286 (N)'
Gas Fired Heaters
Particulars
Sulfur Oxides (as S02)
Carbon Monoxide
Hydrocarbons (as CH^)
Kitrogen Oxides (as NDj)
5-15
0.6
17
3
120-230
0.48-1.43
0.057
1.6
0.29
11.4-21.9 -
Source: Reference 7.
Based on a heat input of l.OxlO5 3tu/bbl of fresh feed with the following
fuel heating values: Oil - 140,000 Btu/gal; Gas - 1050 Btu/scf.
CS = Vt % sulfur in the fuel oil
f
Improper combustion may cause a significant increase in emissions
Use this emission factor for residual oils with less than 0.5% (N^-5). nitro-
gen content. For oil with higher nitrogen content 0^0,5), use emission
factor of 120 lb/103 gal
Based on sulfur content of 2000 g,r/10s scf
253
-------
TABLE 7-5. ESTIMATED FUGITIVE NONMETHANE HYDROCARBON EMISSIONS
FROM A TYPICAL VACUUM DISTILLATION UNIT
Emissions
Source Type
Valves
Open-End
(Sample)
Valveu
Pumpu (Pump
Seals)
Drains
Flanges &
Fittings
Kellef Valves
Couiprctisoru
(Compressor
Seals)
"CounueJ From
Kul 1 mated
cRef ereur.e W
Stream Service
Classification
Gas/Vapor
Light Liquid
(VI- > O.I psla j> 100'K)
Heavy Liquid
(VP < 0.1 p»la 8 100'f)
Hydrogen Service
Total
All
Light Liquid
(VP > 0.1 polu 8 100'T)
Heavy Liquid
(VP < o.i psia a inn'F)
Total
All
All
All
Hydrocarbon
Hydrogen
Total
Flow Diagrams
Number of Sources In
Counts or Estimates
From Radian Study
50
45
405
0
5()0b
-
2( 2)
14(20)
I6(22)b
42b
1785
b
6
0
0
0
Process Unit
Counts or Estimates
From PES SCudyc
71
142
497
0
7lOb
14*
2( 3)
7(10)
9(13)a
-
K
2350D
-
0
0
0
Emission
Factor, Ib/hr
0.059
0.024
0.0005
0.018
0.005
0.25
0.046
0.070
0.00056
0.19
1.4
O.I I
Emissions,
Ib/hr
2.95 - 4.19
1.08 - 3.41
0.203- 0.249
0.0
4.23 - 7.85
0.070
0.50 - 0.75
0.46 - 0.92
0.96 - 1.67
2.04
i . 00 - 1 . 32
1.14
0.0
0 . 0
0.0
10.3 - 15.0
-------
Tetraethylene glycol, mixtures of several glycols, diinethyl-
sulfoxide, formul-raorpholine, and tetrahydrothiophene-dioxide are some of
the .solvents used.
Process Conditions—Typical operating parameters for the most
widely used processes are given in Table 7-6.
Atmospheric Emissions—Since aromatlcs extraction is a closed
process, the only significant emissions are fugitive hydrocarbon emissions.
These emissions are summarized in Tables 7-7 and 7-8.
7.1.2 Thermal Operations
Thermal operations are noncatalytic processes used to convert
large hydrocarbon molecules into smaller molecules at high temperatures.
These processes convert low value stocks such as heavy gas oil into lighter,
more valuable products. The thermal operations currently used by U.S.
refineries include delayed coking, fluid coking, visbreaking, and thermal
cracking.
7 .1.2.1 Visbreaking
Visbreaking (viscosity breaking) is a mild thermal cracking
operation used to reduce the viscosity of materials such as atmospheric or
vacuum residuals and pitch. This procedure reduces the amount of valuable
light heating oil which must be blended with the residuum to produce a fuel
oil of acceptable viscosity.
Process Conditions—Typical operating parameters and utility
requirements for a visbreaking operation are given below.38>°°
255
-------
TABLE 7-6. OPERATING PARAMETERS AND UTILITY REQUIREMENTS
FOR THREE AROMATICS EXTRACTION PROCESSES
Condition
Udex
Process
Sulfolane
Tetra
Stripping Steam
Ratio, wt/wt
0.6
0.13
Stripper Bottom
Temper a t u re, ° F
290
375
Extractor Top
T emp e r a t u r e, °F
290
212
Extractor Pressure,
psig
110
15
Feed Temperature, °F
240
240
Utilities, per barrel
of feed
Steam, Ib
400
2.5
125
Fuel, 103 btu
190
Cooling Water, gal
1,200
530
650
Electricity, kWh
1.3
0.8
0.3
256
-------
TABLE 7-7. ESTIMATED FUGITIVE NONMETHANE HYDROCARBON EMISSIONS
FROM A TYPICAL AROMATIC EXTRACTION UNIT
ro
Ln
—l
Emissions
Source Type
Valves
Open-End
(Sample)
Valviia
1'uiopa (Pump
Seals)
Drains
Flmigiia 61
Fittings
Relief Vnlvea
Compressors
(Compressor
Seals)
Counted from
Ear 1 mated
Stream Service
Classification
Gas/Vapor
Light Liquid
(vr > o. i psin C' IOU'F)
Heavy !Ji|uUl
(VP < 0.1 pala a IflO'F)
Hydrogen Service
Total
All
Light Liquid
(VV > 0.1 pals t* 100'F)
Heavy Liquid
(VF < 0.1 poia e IQO'K)
Totul
All
All
All
Hydrocarbon
Hydrogen
Total
Flow Diagrams
Number of Sources In
Countb or Kutlmateu
From Radian Study
60
486
54
o.
600b
-
16(23)
2( 3)
18(25)k
2142b
6b
0
0
0
Process Unit
Count u or R^Llrautua
From PES Study
206
1370
4B3
0
20591*
29a
17(24)
6( 8)
23(32)a
-
6815L
-
0
0
0
Emission
Factor, Ib/hr
0.0b9
0.024
0.0005
0.018
0.005
0.25
0.046
0.070
0.00056
0.19
1.4
0.11
Einlsulouu,
Ib/hr
3.54 - 12.
11.7 - 32.
0.027 - 0.
0.0
15.3 - 45.
0.145
• 5.75 - 6.
0.138 - 0.
5.89 - 6.
3.29
1.20 - 3.
1.14
0.0
0.0
0.0
27.0 - 59.
2
9
242
y~
00
368
37
B2
6
CKeferenc<: 49,
-------
TABLE 7-8. ESTIMATED COMPOSITION OF FUGITIVE EMISSIONS
FROM AN AROMATICS EXTRACTION UNITa
r-o
OT
CO
Scream
Reformats
Solvent
Aromatic
Extract
Raf flnate
Totals
Estimated percentage oC emissions
attributed to each stream - %
12
0
44
44
1002
Weighted contribution of. each
component to unit emissions - pprnw^
Benzene
Toluene
Ethylbenzene
Xylcncis
Other Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Other Polynuclear Aromatics
n-Hexane
Othar Alkanes
OlefJ.ns
Cyclo Alkanes
648
9324
4020
20508
38923
858
0
0
84
2380
42/20
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
7850
112948
48695
248420 '
21120
44
0
0
44
44
836
0
0
22
330
132
660
1012
22
0
0
22
27720
410080
0
0
8520
122602
52847
269588
61060
954
0
0
150
30644
453637
0
0
1000000
3Baseil on GO-MS analysis of liquid stream samples (and some vapor samples).
Estimates based on the assumption that fugitive emission compositions from
sources in liquid stream service is the same composition as that of the
liquid contained in the emission source.
^Compositions are estimated to 2-3 sip.njfic.int figures. Additional significant
figures are a result of calculations! procedures, and they should not be given
any importance.
-------
• Temperature: 85C to 950°F.
• Pressure: 50 to 300 psig.
• Electricity: 0.47 kWh/bbl.
• Steam (300 psig): 8.7 Ib/bbl.
• Fuel: 88 x 103 Btu/bbl.
Atmospheric Er.iissions—Emissions from visbreaking operations
include process heater flue gas and fugitive emissions. A typical vis-
breaking unit will have one heater. Emissions from this heater are
summarized in Table 7-9. Fugitive emissions are summarized in Table 7-10.
7.1.2.2 DelayedCoking
Delayed coking is a semi continuous process in which the heated
charge (heavy gas oil or residuum) is transferred to large coking drums.
The coking drums provide sufficient residence time fur the cracking reac-
tions to proceed to completion. During the reaction, coke is produc.ed and
deposited within the coke drum. Delayed coking is likely to remain an
important refining process since it simultaneously converts low-value
materials to lighter, more valuable products while producing coke as a
valuable by-product.
In many cases, the coker is mounted over a railroad track so that
the coke can be discharged directly into railroad cars. The coke is
retained in the cars while water and coke fines drain off and flow to a
sump. Alternatively, the coke can be directed to a concrete apron or pit.
1'rocess Conditions—Temperature and pressure influence the rate
of cracking and coking reactions. At higher heater outlet temperatures
259
-------
TABLE 7-9. TYPICAL EMISSIONS FROM VISBREAKTNG
UNIT PROCESS HEATERS
a
EPA Emission Factor
(lb/103.gal-oil fired)
(lb/106 scf-gas fired)
Total Emissions
(lb/103 bbl of
fresh feed)
Oil Fired Heaters
Particulates
- Distillate oil
- Residual oil
Grade A
Grade 5
Grade 6
Sulfur Dioxide
- Distillate oil
- Residual oil
Sulfur Trioxide0
Carbon Monoxide
Hydrocarbons (as CHi,)
Nitrogen Oxides
(as N02)
- Distillate oil
- Residual oil6
Gas Fired Beaters
Particulates
Sujfur Oxides (as S02)
Carbon Monoxide
Hydrocarbons (as CHi,)
Nitrogen Oxides (as N02)
2
7
10
10(S)+3
1A2(S)
157(S)
2(S)
5
1
22
22+400 (Mr
5-15
0.6
17
3
120-230
1.3
A. 5
6. A
6.4(S)+1.9
91.3(S)
101 (S)
1.3(S)
3.2
0.6A
1A
1!<.5) nitr
gen content. For oil with liigher nitrogen content (N-'O^S), use cciission
factor of 120 lb/103 gal
Based on sulfur content of 2000 £r/106 scf
260
-------
TABLE 7-10. ESTIMATED FUGITIVE NONMETHAflE HYDROCARBON EMISSIONS
FROM A TYPICAL VISBREAKING UNIT
Source Type
Valves
Open-End
(Sample)
Vulvea
Piiiipu (Pump
iiuals)
Dralna
Plunges &
Fittings
Relief Valvea
Compressors
(Compressor
Seals)
Process
SLreaiE Service
Classification
Gaa/Vu|ior
Light Liquid
(V? > 0.1 (isla (f 100'C)
Heavy Liquid
0.1 pslJ « 100'F)
Heavy LlquLJ
(VP < 0.1 pil» 8 100'K)
Total
All
All
All
Hydrocarbon
Hydrogen
Tocal
Number of Suurceu in Process Unit
30
46
224
300*
20Q
2C 2)
7(10)
9(12)a
23a
•
1071°
6a
0
0
0
Sunroc
tiuiiseioii
Factor. Ib/hr
0.059
0.024
0.0005
O.Olfa
0.005
0.25
0.046
0.070 '
0.00056
0.19
1.4
0.11
Estimated Total
Emissions,
Ib/hr
1.77
1.10
0.112
0.0
2.98
0.100
0.50
0.46
0.96
1.61
0.60
1.14
0.0
0.0
0^0
7.29
Estimated
-------
and/or increased drum pressure, the yield of gas, naphtha and coke is
increased at the expense of a lower gas oil yield. Typical operating
parameters for delayed coking are shown below. >J">J >J
• Heater outlet temperature: 900 to 975°F.
* Coke drum pressure: 20 to 100 psig.
• Recycle ratio: 0.1 to 1.0.
Atmospheric Emissions—Emissions from delayed coking operations
include emissions from decoking operations, process heater flue gas, and
fugitive emissions.
The steam injected into the drum as part of the decoking operation
is condensed and the remaining vapors usually flared. During the removal of
the coke from the drum, particulates are released, as are hydrocarbon vapors
entrained in the coke. A water quench is often used to minimize particulate
emissions. This water contains sulfur components and it may be a source of
objectionable odors. Emission factors for the decoktng operation were not
available. Process heater and fugitive emissions are summarized in Tables
7-11, 7-12, and 7-13.
7.1.2.3 Fluid _Cg_k_ing
Fluid coking, like delayed coking, was developed to convert
residuals, tars, and resins produced during certain refining operations
to lighter, more valuable liquid products and coke. Yields are similar
to those from delayed coking, except that coke production is significantly
lower. Also, the coke produced is usually of insufficient quality for
- , . , 38,53
industrial use.
262
-------
TABLE 7-11. TYPICAL EMISSIONS FROM DELAYED COKING
UNIT PROCESS HEATERS
EPA Emission Factor
Clb/103 gal-oil fired)
(lb/106 scf-gas fired)
Total Emissions
(lb/103 bbl of
cokcr feed)
Oil Fired Heaters
Particulates
- Distillate oil
- Residual oil
Grade 4
Grade 5
Grade 6
Sulfur Dioxide
- Distillate oil
- Residual oil
Sulfur TrioxideC
Carbon Monoxide
Hydrocarbons (as CK4)'
Nitrogen Oxides
(as. N02)
- Distillate oil
- Residual oile
7
10
10(S) + 3
142(S)
157(S)
2(S)
5
1
22
22+400 (N)'
3.4
12
17
17(S) + 5.1
243(S)
269(S)
3.4(S)
8.6
1.7
38
38+686(N)'
Gas Fired Heaters
Particulates
Sulfur Oxides (as SC^)
Carbon Monoxide
Hydrocarbons (as CH^)
Nitrogen Oxides (as ^02)
5-15
0.6
17
3
120-230
1.1-3.4
0.14
3.9
0.69
27-53
Source: Reference 7«
Based on a heat input of 2.4xlt)s. Btu/bbl of fresh feed v.'ith the following
fuel heating values: Oil - 140,000 Btu/gal; Gas - 1050 Btu/scf,
CS = Wt % sulfur in the fuel oil
laproper coxbustion raay cause a significant increase in emissions
"Use this emissior. factor for residual oils with less than 0.5% (JK.5) nitro-
gen content. For oil with higher ni'trop.en content (K>0,5), use c-caisslon
factor of 120 lb/103 gal
Based on sulfur content of 2000 gr/10G scf
263
-------
TABLE 7-12. ESTIMATED FUGITIVE NONMETHANE HYDROCARBON EMISSIONS
FROM A TYPICAL DELAYED COKING UNIT
Emissions
Source 'i'yi'e
Vulvea
Open-End
(Sample)
Valves
Pumps (Pump
Seals)
Proceisu —
Scream Service C,
Clasuli lent Jon
Gas/Vapor
Light Liquid
(VP > O.l p«u e loa-t)
Heavy Liquid
(VP < U.I pala !_' 100'F)
Hydrogen Service
Total
All
Light Liquid
(VP > 0.1 psU @ lOO'F)
Heavy Liquid
(VP < 0.1 p.la 8 UK)'?)
Drains
Flanges &
Fittings
Relief Valveu
Compressors
(Compressor
Seals)
To Lai
All
All
All
Hydrocarbon
Hydrogen
Total
Niimher of Sourceu
In Hroceaa Unit
ounts or Estimates Counts or Estimates Em
From Radian Study From PES Studyc Fuci
30
57
213
0
300l)
-
2( 3)
mo)
9(13)''
23b
K
1071
6b
0
0
0
17H
1308
291
0
1777b
43a
lfl(25)
4( 6)
22(31)"
-
i,
5B7i
-
3( 6)
0( 0)
3( 6)
a.
0.
0.
0.
0.
0.
0.
0.
a.
0.
i.
0.
jrce Estimated Total
laalon Emisalons.
tor, Ib/lu Ib/hr
059
024
0005
01 b
005
25
046
070
00056
19
4
11
1.
1.
0.
3.
0.
0.
1.
0.
0.
0.
a.
77 -
•37 -
107 -
0.
25 -
0.
750 -
460 -
21 -
1.
60 -
1.
0
0.
0
03 -
10.
31.
0.
[>
5
4
146
42.0
215
6.
0.
6.
61
3.
14
8.
0
a.
63.
25
276
53
29
4
*
5
Counted From Flow Ulagramu
EsrImuiod
Reference 49.
-------
TABLE 7-13. ESTIMATED COMPOSITION OF FUGITIVE EMISSIONS
FROM A DELAYED COKING UNITa
Ui
Stream
Estimated percentage of emissions
attributed to each stream - %
Weighted contribution cf each
component to unit emissions - pprnw*5
Benzene
Toluene.
Ethylbenzene
Xylencs
Other Alkylbenzenes
Naphthalene
Anthracene
ftiphenyl
Other Polynuclear Aromatics
n— Itcxnnc
Other Alkaiies
OlcCins
Cyclo Alkanas
Hydrogen
Vacuum
Re 3 id
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Coke
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Cracked
Naphtha
57
1642
51175
12215
97727
138778
6242
0
0
3694
6743
116340
97322
38122
0
LPG
OleEins
14
0
0
0
0
0
0
0
0
0
0
56000
84000
0
0
Fuel
Gas
29
0
0
0
0
0
0
0
0
0
0
266800
17400
0
5800
Totals
100%
1642
51175
12215
97727
138778
6242
0
0
3694
6743
439140
198722
38122
5600
1000000
Based on GC-MS analysis of liquid stream samples (and some vapor samples).
Estimates based on the .incumption that fugitive emission coirrpositions iron:
sources in liquid stream service is the same composition as that of the
liquid contained in the emission source.
Compositions are estimated to 2-3 significant figures. Additional significant
figures are a result oi calculational procedures, and they should not be given
any Importance.
-------
Flexicoking is a relatively recent integration of conventional
fluid coking and coke gasification. The coke gas produced may be sub-
stituted for refining fuel gas or natural gas. The net coke production is
1-2 weight percent of the feed, as compared to 10-20 percent for con-
ventional fluid coking. No commercial flexicokers have been installed in
the U.S., but extensive commercial experience has been accrued abroad.
Process Conditions—Fluid coking and flexicoking operating condi-
tions are summarized in Table 7-14.
Potentially Hazardous At mo spheric. Em 1s s ions—Emissions from fluid
coking include burner vessel flue gas and fugitive emissions. No process
heaters are needed, because heat is supplied by the coke.
Combustion of the coke produces a flue gas containing substantial
quantities of carbon monoxide with lesser amounts of SO , NO , organics,
and particulates. CO emission rates have been estimated at 30 pounds per
barrel of feed."J CO boilers are used to recover the substantial energy
in this gas and to reduce the concentrations of CO and other combustibles.
However, high combustion temperatures may cause an Increase in N0x emissions.
Both SO, and NO concentrations will increase if auxiliary fuel is used.
X X
Fugitive emissions are summarized in Table 7-15.
7.1.3 C rack ing Ope rations
Cracking operations convert heavy petroleum fractions into lighter,
more valuable products. Two processes, catalytic cracking and hydrocracking,
provide a substantial portion of the cracking capacity in the United States.
Although these processes are similar in that they crack heavy fractions to
produce lighter products, there are considerable differences between them
in both the operating principles and the pollution potential. The choice
of one process over the other is usually an economic one.
266
-------
TABLE 7-14. PROCESS CONDITIONS FOR FLUID COKING
AND FLEXICOKING
Fluid Coking Flexicoking
Temperature, °F
Reactor 950 950
Burner 1,150 1,150
Gasifier — 1,300-1,800
Pressure, psig
Reactor 10 10
Burner 11 11
Gasifier 24-45
Utilities - per barrel feed
Electric Power, kWh 5.5 13
Fuel, MM Btu 0 0
Source: References 38,50,54,56.
267
-------
TABLE 7-15. ESTIMATED FUGITIVE NONMETRANE HYDROCARBON
EMISSIONS FROM A TYPICAL FLUID COKING UNIT
O\
00
Emluaions
Source Type
ViiLvea
Open-End
(Sample)
Valvea
PuiD|ia (Pump
Sealu)
Drains
Flanges &
Fittings
Relief Vulveu
Copipruesora
(Compressor
St;n la)
Process
Stream Service
Clusulf icut Ion
Gas/Vapor
Light Liquid
(VT > 0.1 fata 6 100'F)
Heavy Liquid
(VP < O.L paU e 100'K)
Hydrogen Service
To en I
All
I.lgllC Liquid
(VF > 0.1 psla 0 LOO'F)
Heavy l.i(|nlil
(VP < 0.1 paltt @ LOO*P)
Total
All
All
All
Hydrocarbon
Hydrogen
Total
Number of Sources In Process Unit
30
58
216
0
304 a
-
2( 3)
7(10)
9(13)a
28a
1047a
6b
4(8)
0(0)
4(8)a
Source
Emission
Factor, ib/hr
O.OS9
0.02/1
O.OOOb
0.018
0.005
0.25
0.046
0.070
0.00056
0.19
1.4
0.11
Estimated Total
Emissions.
Ib/hr
1.77
L.39
0.10B
0.0
3.27
~
0.75
0.46
1.21
1.96
0.5B6
1.14
11.2
0.0
11.2
19.4
Physically Counted
'Estimated
-------
7.1.3.1 Catalytic Cracking
Several types of catalytic cracking processes have been developed:
fluid-bed catalytic cracking (FCC) units, and moving bed designs such as
Thermofor (TCC) and HoudrifJow (11CC) cracking units. With the advent of
new catalysts, major design and operational changes have been incorporated
in FCC unit operation. By contrast, no major changes in moving bed type
units have been observed and these, units are being phased out.
In a typical FCC unit the reactor contains a bed of powdered
catalyst which is kept in a fluidized state by the flow of vaporized feed
material and steam.
Thermofor and Koudriflow catalytic cracking units use beaded or
pelleted catalysts.
Process Conditions—Typical operating conditions for a conven-
tional FCC unit and for one with high temperature regeneration (KTR) are
given in Table 7-16.
Atmospheric Etuissions—Emissions from catalytic cracking units
include catalyst regeneration emissions, process heater flue gas emissions,
and fugitive emissions.
Many refiners use a CO-burning waste heat boiler to recover the
energy contained in the flue gas from the regenerator. This boiler also
significantly reduces the emission of CO and other combustible contaminants.
Increased emissions of "thermal NC ." nay occur, however, along with the
X
production of SO,, from sulfur in the auxiliary fuel. Typical emission
A.
levels for regenerator flue gas with and without a CO boiler are given in
Table 7-17. This table also lists results of sampling conducted during
this program. Detailed information on these sampling results is given in
Appendix B (Volume 3 of this report).
269
-------
TABLE 7-16. TYPICAL OPERATING CONDITIONS FOR FLUID
CATALYTIC CRACKING
Reactor Temperature, °F 885 - 1,025
Regenerator Temperature, °F
Conventional Regeneration 1,000 - 1,100
HTR 1,100 - 1,350
Coke Content of Spent Catalyst, Wt %
Conventional Regeneration 6
HTR 5
Coke Content on Regenerated Catalyst, Wt %
Conventional Regeneration 0.2 - 0.3
HTR 0.0.1 - 0.1
Source: References 57,58.
270
-------
TABLE 7-17. EMISSION RATES PROM FCC REGENERATORS,
BEFORE AND AFTER CO BOTLER
Chemical Spccieo
' S02, ppcnv
SOa, ppmv
K0x (33 N02), ppmv
CO, Z Vol.
C02, Z Vol.
Oj, Z Vol.
Nj, Z Vol.
HjO, 7. Vol.
Hydrocarbons, ppmv
Ammonia, ppmv
AldrhydcR, ppmv
Cyanides, ppmv
Participates, gr/SCF
Temperature, °F
Emi9.glons without
.CO Boiler
(Reference 58)
130-3300
HAC
8-394
7.2-12.0
10.5-11-3
0.2-2.4
78.5-80.3
13.9-26.3
98-1213.
0-675
3-130
0.19-0.94
0.08-1.39
1000-1200
Emissions with
CO Boiler
(Reference 58)
Up to 2700
NAC
Up to 500
0-14 ppmv
11.2-14.0
2.0-6.4
82.0-84.2
13.4-23.9
. NAC
KAC
MAC
NAC
0.017-1.03
485-820
Data from ,
Current Program
14.4-371
0.65-13.5
94.1-453
0.0-1.0
13.5-16.1
3.2-7.0
77-82.7
9.2-22.7
0.28-46.2
0.0-15-4
0.0-19.6
0.0-19.1
0.012-0.304
386-727
Total Emissions based on Data frora
Current Program - (lb/1000 bbl feed)
3-332
0.5-9.0
41-193
0.0
-
-
-
1.1-12.0
0.06-1.65
0.0-4.6
0.0-4.S4
7.9-C5.2
—
.All concentrations on dry basis
Based on sampling of 5 otacks
"Hot available
-------
High temperature regeneration or combustion promotion catalysts
can reduce the level of CO in the regenerator flue gas to 200-2,000 ppra,
S 5
usually < 500 ppm." Because the temperatures involved are lower than those
r o
in a CO boiler, thermal NO emissions are somewhat lower. Fugitive, emis-
sions and emissions from process heaters are summarized in Tables 7-18,
7-19 and 7-20.
7.1.3.2 Hydrocracking
Hydrocracking is a high-tenperature, high-pressure process for
converting heavy feedstocks into lighter products in the presence of
hydrogen and a catalyst or series of catalysts. The process is highly
flexible and produces low-sulfur, low-nitrogen products. A hydrocracker
, ., 38.51,59,60
may be single-stage or two stage. ' '
Process Conditions—The severity of the process conditions
required for hydroeracking depends on the type of feedstock and the degree
of cracking desired. The primary reaction variables are the reactor
temperature and pressure and the nitrogen and sulfur content of the feed
and off-gases. A summary of typical operating conditions and utility data
is given below:59,GO
• Pressure: 1,000 to A,000 psig.
• Temperature: 400 to 850°F.
• Hydrogen recycle: 8,000 to 15,000 scf/bbl feed.
• Hydrogen consumption: 1,500 to 2,500 scf/bbl feed.
• Fuel: 100 to 250 x TO3 Btu/bbl feed.
272
-------
TABLE 7-18. TYPICAL EMISSIONS FROM CATALYTIC CRACKING
UNIT PROCESS HEATERS
EPA Emission Factor
(ib/IO3 gal-oil fired)
(lb/10G scf-gas fired)
Total Scissions
(lb/103 bbl of
fresh feed)
Oil Fired Heaters
Participates
- Distillate oil
- Residual oil
Grade 4
Grade 5
Grade 6
Sulfur Dioxide0
- Distillate oil
- Residual oil
Sulfur Trioxide0
Carbon Monoxide
Hydrocarbons (as CHt,)
Nitrogen Oxides
(as N02)
- Distillate oil
- Residual oil6
Gas Fired Heaters
Participates
Sulfur Oxides (as S02)
Carbon Monoxide
Hydro carbons (as CH1+)
Nitrogen Oxides (as N02)
7
10
10(S)+3
142(S)
157(S)
2(S)
5
1
22
22+400(N)'
5-15
0.6
17
3
120-230
10
10(S)+3
160(S)
2(S)
5
1
22
22+409(N)'
0.7-2.0
0.08
2.3
0.41
16-31
Source: Reference 7.
Based on a heat input of 100,000 Btu/bbl of fresh feed vlth the following
fuel heating values: Oil - 140,000 btu/gal; Gas - 1050 Etu/scf
CS = Wt % sulfur in the oil
Improper combustion nay cause a significant increase in emissions
EUsc this emission factor for residual oils vith lass than 0.5% (N<.5)_ nitro-
gen content. For oil with higher nrtrogen content (N>0,5), use emission
factor of 120 lb/103 gal
Based on sulfur content of 2000 gr/106 scf
273
-------
TABLE 7-19. ESTIMATED FUGITIVE NONMETHANE HYDROCARBON EMISSIONS
FROM A TYPICAL CATALYTIC CRACKING UNIT
Em I tin Ions
Source Type
Valves
Open-End
(Sample)
Valves
Purana (Pump
Seals)
Drains
Flangea &
Fittings
Kellei Valves
Compressors
(Compressor
Stream Service
Glaus If leal, ion
Gas/Vapor
Light Liquid
(«p > o.i p»u e loo'K)
Heavy Liquid
0.1 l>sls (J IQO'F)
Heavy Liquid
Total
All
All
All
Hydrocarbon
Hydrogen
Totul
Number of Sources In
Counts or Estimates
From Radian Study
184
400
521
0
1314a
-
13(18)
17(24)
30(42)a
65a
4214a
6C
4(a)
0
4(8)a
Process Unit
Counts or Estimates
FroiD I'KS Study
849
889
1167
0
2905C
67
16(22)
21(29)
37(52)b
-
96:i!.c
-
4(8)
0
4(8)«>
Emission
Factor, Ib/hr
0.059
0.024
0.0005
o.oia
0.005
0.25
0.046
0.070
0.00056
0.1!)
1.4
0.11
Emissions.
Ib/hr
22.7 - 50.1
9.82 - 21.3
0.261 - 0.584
0.0
32.8 - 72.0
0.335
4.5 - 5.50
1.10 - 1.13
5.60 - 6.83
4.55
2.36 - 5.40
1.14
11.2
0.0
11.2
58.0 - 101
Physically Counted
Counted From 1 low Diagrams
r>
Hbtiiunted
Reference 49.
-------
TABLE 7-20. ESTIMATED COMPOSITION OF FUGITIVE EMISSIONS
FROM A FLUID CATALYTIC CRACKING UNIT3
ro
^j
Ln
Estimated percentage of emissions
attributed to each stream - %
Weighted contribution of each
component to unit emissions - ppmw "
Benzene
Toluene
Ethyl-benzene
Xylerics
Other Alkylbenzenes
Naphthalene
Anthracene
Eiphenyl
Other Polynucl.ear Aroroatics
n-Hexane
Other Alkan.es
Olcf Lnsj
Cyclo Alkanes
Hydrogen
Atmospheric
Gas Oil
1
0
0
0
0
1
0
0
0
2
0
9495
0
500
0
S trcam
Fuel
Gas
30
0
0
0
0
0 .
0
0
0
0
0
216000
18000
0
6000
LPG
Olefing
23
0
0
0
0
0
0
0
0
0
0
92000
138000
0
0
Cracked
Naphtha
45
1296
40401
9644
77153
109562
497.8
0 .
0
2916
532-1
91850
76833
30096
0
Lt. Cycle
Gas Oil
1
0
0
0
6
267
590
103
102
6245
0
1906
368
412
0
Hvy. Cycle
Gas Oil
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Totals
100%
1296
40401
9644
77159
109830
5518
103
102
9163
5324
471251
233201
31008
6000
10000CO
8Based on GC-MS analysis of liquid stre.nm samples (and some vapor samples).
Estimates based on the assumption that fugitive emission composition;-; from
sources in liquid stream service is the same composition as that of the
liquid contained in the emission source.
^Compositions are estimated to 2-3 significant ligures. Additional significant
figures are a result of calculational procedures, and they should not be given
any importance.
-------
• Power: 6 to 15 kWh/bbl feed.
• Space velocity: 0.2 to 1.0 v/hr/v.
Atmospheric Emissions—Emissions from hydrocracking include emis-
sions during periodic catalyst regeneration, process heater flue gas emis-
sions, and fugitive emissions.
During regeneration large quantities of carbon monoxide and other
pollutants may be released, but, because regeneration may only be required
after several months or years of operation, total averaged emissions from
this source are generally insignificant.
Process heater and fugitive emissions are summarized in Tables
7-21 and 7-22.
7.1.4 Hydroprocessing
Hydroprocessing refers to those processes in which hydrogen is
mixed with a variety of feedstocks and passed over a catalyst at elevated
temperature and pressure. The hydrogen reacts with .sulfur and nitrogen
containing compounds in the feedstock to form hydrogen sulfi.de and ammonia.
Heavy metals, oxygen and halides are also removed via hydroprocessing.
Hydroprocessing may also be used to stabilize unsaturated hydrocarbons
such as olcfins by converting them to saturated materials.
Hydroprocessing operations may be. divided into three categories,
according to the severity of the process: (1) hydrocracking, in which 50
percent or more of the feed is reduced in molecular weight; (2) hydro-
refining, in which 10 percent or less of the feed is reduced in molecular
weight; and (3) hydrotrcating, in which essentially no reduction in molecu-
lar weight occurs.
276
-------
TABLE 7-21. TYPICAL EMISSIONS FROM HYDROCRACKING
UNIT PROCESS HEATERS
EPA Emission Factor
(lb/103 gal-oil fired)
(lb/106 scf-gas fired)
Total EiaissioDS
(lb/103 bbl of
fresh feed)
Oil Fired Heaters
Particulates
- Distillate oil
- Residual oil
Grade 4
Grade 5
Grade 6
£
Sulfur Dioxide
- Distillate oil
- Residual oil
^
Sulfur Trioxide
Carbon Monoxide
Hydrocarbons (as
Nitrogen Oxides
(as N02)
- Distillate oil
- Residual oile
Gas Fired Heaters
Particulstes
Sulfur Oxides (as S02)
Carbon Monoxide
Hydrocarbons (as CHi^)
Nitrogen Oxides (as N02)
2.9
7
10
10(S)+3
1«(S)
157(S)
2(S)
5
1
22
2 2+400 (N)
5-15
0.6
17
3
120-230
10
lit
14(S)+4.3
203(S)
224(S)
2.9(3)
7.1
1.4
31
31+571 (N)'
0.95-2.9
OJ1
3.2
0.57
22.9-43.8
Source: Reference 7.
Based on a heat input of 200,COO Btu/bbl of fresh feed with the following
fuel heating values: Oil - 1-40,000 Btu/gal; Gas - J050 Btv./scf
:S = Wt•% sulfur in the oil
Improper combustion nay cause a significant increase ir. emissions
e.
Use this emission factor for residual oils with less than 0.5% 0^-5) nitre*
gen content. For oil with higher nitrogen content G^CKS), use emission
factor of 170 lb/103 gal
Based on sulfur content of 2000 gr/10c scf
277
-------
TABLE 7-22. ESTIMATED FUGITIVE NONMETHANK HYDROCARBON EMISSIONS
FROM A TYPICAL HYDROCRACKING UNIT
M
-~J
oo
Emlasloiiu
Source Type
Valves
Open-End
(Sample)
Valves
Pumps (Pump
Seal a)
Uraina
Flanges &
Fittings
Htillef Valveu
Compressors
(CompreBSor
Seals)
Process
Stream Service
Classification Number
Gas /Vapor
Light Li O.L pala $ 100' f)
Heavy Liquid
(VP < 0.1 p»l» S 100*10
llyti IOKKH Service
Total
All
LigliC Liquid
(VP > 0.1 pa 1,1 (! IDO'F)
Heavy Liquid
(VP < 0.1 pala 9 100'F)
Total
All
All
All
Hydrocarbon
Hydrogen
Total
of Sources In Process Unit
175
375
307
75
-------
Hydrocracking is discussed in Section 7.1.3. The. following
sections describe hydrorefining and hydrotreating processes.
7.1.4.1 _Hy drorefining
Hydrorefining is used primarily for reducing the sulfur, nitrogen,
or metal content of heavy feedstocks for farther processing, blending, or
direct use. Hydrodesulfurization is particularly important for catalytic
cracking feeds.
The mechanism of the hydrorefining process is essentially the same
as that for one-stage hydrocrackir.g, discussed in Section 7.1.3.2, except
that the emphasis Is on removal of H2S and NH3 and cracking conditions are
much less severe.
Process Conditions—Process conditions lor hydrorefining vary with
the feedstock and the desired products. A range of typical conditions and
utility requirements is given below.
• Temperature: 390 to 800°F.
• Pressure: 500 to 800 psig.
• Electricity: 19 to 365 kWh/bbl.
• Heater Fuel: 0 to 70,000 Btu/bbl.
• Steam: 1 to 10 lb/bb.1 .
• Cooling Water: 160 gal/bbl.
279
-------
Atmospheric Emissions—Emissions from hydrorefining operations
include emissions during catalyst regeneration, process heater flue gas
emissions, and fugitive emissions.
During catalyst regeneration, large quantities of carbon monoxide
and other pollutants may be released. However, regeneration may be required
only after several months or years of operation. Therefore, total averaged
emissions from this source are generally considered insignificant.
Fugitive emissions and those from process heaters are summarized
in Tables 7-23, 7-24 and 7-25.
7.1.4.2 Hy dro t reating
Hydrotreating operations are less severe than hydrorefining
processes. As in hydrorefining, hydrotreating is used to remove sulfur,
nitrogen, and metallic compounds fron the feed. It is also used to saturate
olefins and aromatics and to polish and dewax lube oil stocks.
The mechanism of hydrotreating processes is essentially the same
as that for one-stage hydrocracking, discussed in Section 7.1.3.2, except
that, cracking conditions are. even less severe than those for hydrorefining.
The product may he fractionated or steam-stripped to remove H2S, NH3, and
light hydrocarbons.
Process Conditions—Operating conditions for hydrotreating vary
with the feedstock and with the desired product. Typical operating condi-
tions and utility requirements for three types of hydrotreating are given
in Table 7-26.
Atiuospheric Emissions—Emissions from hydrotreating include emis-
sions during catalyst regeneration, process heater flue gas emissions, and
fugitive emissions.
280
-------
TABLE 7-23. TYPICAL EMISSIONS FROM GAS OIL HYDRO-
DESULFURIZATION UNIT PROCESS HEATERS
EPA Emission Factor
(rb/103 gal-oil fired)
(lb/106 scf-gas fired)
Total Emissions
(lb/103 bbl of
fresh feed)
Oil Fired Beaters
Particulates
- Distillate oil
- Residual oil
Grade A
Grade 5
Grade 6
Sulfur Dioxide
- Distillate oil
- Residual oil
Sulfur Trioxide0
Carbon Monoxide
Hydrocarbons (as
Nitrogen Oxides
(as N02)
- Distillate oil
- Residual oile
Gas Fired Heaters
Particulates
Sulfur OxidP.s (as S02)f
Carbon Monoxide
Hydrocarbons (as CHiJ
Nitrogen Oxides (as N02)
7
10
10(S)+3
142(S)
157(S)
2(S)
5
1
22
22+400(N)
5-15
0.6
17
3
120-230
0.86
3.0
4.3
4.3(S)+1.3
60.9(S)
67.3(S)
0.86(S)
2.1
0.43
9.4
9.4+171 (N)'
0.29-0.86
0.034
0.97
0.17
6.86-13.1
Source: Reference, 7.
Based on a heat input of 60,000 . Btu/bbl of fresh feed with the following
fuel heating values: Oil - 140,000 Btu/gal; Gas - 1050 Btu/scf
S •= vt X sulfur in the oil
Improper combustion ony cause a significant increase in emissions
Use this emission factor for residurl oils with less than 0,5% (N<.5). nitre--
gen content. For oil with higher nitrogen content Q^O^S), use emission
factor of 120 lb/103 gal
Based on sulfur content of 2000 gr/10K scf
281
-------
TABLE 7-24. ESTIMATED FUGITIVE NONMETHANE HYDROCARBON EMISSIONS
FROM A TYPICAL GAS OIL HYDRODESULFURIZATT.ON UNIT
CD
Linlbslonu
Source Type
Valves
Open-End
(Sample)
Valves
Fumpu ({'map
Seals)
Drains
Flanges &
Flttlngu
Process
Stream Service
Classification
Gas/Vapor
Light Liquid
(VP > 0.1 H«!a e lOU'F)
Heavy Liquid
(VH < 0.1 pal. 8 IOO"F)
Hydtogcn Service
Total
All
Light Liquid
(VP > 0.1 psla 8 lOG'F)
llli.ivy 1. lljuLil
(VP < 0.1 pain e 100"F>
Total
All
All
Number of Sources
Coulter or KslJmare;
From Hadlan Study
235
208
102
J01
64 5 a
-
6( 9)
4(_ 5}
10(14)a
24a
2743a
in Process Unit
) Counts or Estimates
from HKS Study
205
244
97
164
" 710^
16
5( 7)
2( 3)
7(10)b
-
2350C
Hiilief Vulvea All 6C
Coinpreasora
(Compressor
Seals)
Physically
Hydrocarbon
Hydrogen
Total
Counted
0(0)
T(6)a
0(0)
3(6)
3(6p
Source
Em Is til on
Factor, Ib/lir
0.059
0.024
0.0005
0.018
0.005
0.25
0.046
0.070
0.00056
0.19
1.4
0.11
Estimated Total
Emissions ,
Ib/l.r
13.9 - 12.1
4.99 - 5.86
0.049- 0.051
1.82 - 2.95
20.8 - 21^0
0.080
1.75 - 2.25
0.14 - 0.23
1.89 - 2.48
1.68
1.44 ~ 1.54
1.14
0.0
0.66
0.66
27.7 - 28.6
Counted Krom Flou Diagrams
Clistlra/Ued
Reference
49.
-------
TABLE 7-25. ESTIMATED COMPOSITION OF FUGITIVE EMISSIONS
FROM A GAS OIL 1IYDRODESULFUR1ZATION UNlTa
ro
CO
OJ
Stream
Estimated percentage of omissions
attributed to each at ream - %
Weighted contribution of each
component to unit emissions - ppmw
Benzene
Toluene
Ethylbenzene
Xyler.es
Other Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Other Polynuclear Aromatics
n-Ik*xnne
Other Alkanes
Olefins
Cycle Alkanes
Hydrogen
Gas Oil
22
0
1
1
5
8 •
6
2
2
146
0
208756
0
11000
0
Dcsulfurizcd
Con Oil
22
0
1
1
5
81
6
2
2
146
0
208756
0
11000
0
HZ Rccyc-lp.
Cos
56
0
0
0
0
0
0
0
0
0
0
364000
0
0
196000
Totals
100%
0
2
2
10
162
12
4
4
292
0
781512
0
22000
196000
1000000
3BasP.d on CO'-MS analysis of liquid stream samples (and some vapor samples).
Estimates based on the assumption that fugitive emission compos j L ion;; from
sources in liquid stream service is the same composition as that of: the
liquid contained in the emission source.
Compositions are estimated to 2-3 significant figures. Additional significant
figures are a result of calculations! procedures, and Limy should not be given
any importance.
-------
TABLE 7-26. TYPICAL OPERATING CONDITIONS FOR THREE HYDROTREATINC OPERATIONS
Condition
Temperature, °F
Pressure, psig
Electricity, kWh/bbl
Heater Fuel, Btu/bbl
Cooling Water, gal/bbl
Steam, Ib/bbl
Light Hydrocarbon
Hydrodesulfurization
600-800
300-1,000
2.6
36,000-75,000
264
30-903
Process
Olei in/Aroma tics
Saturation
480-660
100-1,500
0.5-2.5
1,000
120-680
12-35
Lube and Wax
Hydrotreating
600-750
500-700
2.5
35,000-140,000
15-30
o
30 to 90 Ib/bbl with steam stripper, 5 Ib/bbl without steam stripper.
-------
During regeneration, large quantities of carbon monoxide and
other pollutants may be released. However, regeneration may be required
only after several months or years of operation. Therefore, total averaged
emissions from this .source are generally considered insignificant.
Fugitive emissions and emissions from process heaters are
summarized in Tables 7-27, 7-28 and 7-29.
7.1.5 Conversion Processes
Conversion processes use catalyzed chemical reactions to upgrade
certain refinery streams or to produce valuable products from less valuable-
materials. Conversion processes include alkylation, isoiuerization,
catalytic reforming, and hydrodealkylation.
7.1.5.1 Alkylation
Alkylation is the chemical combination of an olcfin and an
isoparaffln, visually isobutane, to produce higher molecular weight isopar-
affins. The alkylate product is usually used to upgrade the octane rating
of gasoline. Almost all alkylation units use H2SO^ or 1IF as a catalyst.
Process Conditions—The most important variables in alkylation
are reactor temperature, acid strength, isobutane concentration, and, in
sulfuric acid alkylation, the olefin space velocity. Ranges for these
and other variables are included in Table 7-30.
285
-------
TABLE 7-27. TYPICAL EMISSIONS FROM HYDROTREATING
UNIT PROCESS HEATERS
EPA Emission Factor
(lb/103 gal-oil fired)
(lb/106 scf-gas fired)
Total Emissions
(lb/103 bbl of
fresh feed )
Oil Fired Heaters
Participates
- Distillate oil
- Residual oil
Grade A
Grade 5
Grade 6
Sulfur Dioxide0
- Distillate oil
- Residual oil
Sulfur Trioxide0
Carbon Monoxide
Hydrocarbons (as CHi()
Nitrogen Oxides
(as N02)
- Distillate oil
- Residual oile
7
10
10(S)+3
157(S)
2(5)
5
1
22
22+400(N)'
1.1
3.8
5.4
5.4(S)+1.6
76.KS)
84.1(S)
l.l(S)
2.7
0.54
12
12+214(N)'
Gas Fired Heaters
Particulates
Sulfur Oxides (as S02)
Carbon Monoxide
Hydrocarbons (as CKi< )
Nitrogen Oxides (as NC^)
5-15
0.6
17
3
120-230
0.36-1
0.043
1.2
0.21
8.6-16
.1
.4
Source: Reference 7.
Based on a haat input of 75,000 Btu/bbl of fresh feed with the following
fuel heating values: Oil - 140,000 Btu/gal; Gas - 1050 Btu/scf
CS •= wt 7, sulfur in the oil
Improper combustion may cause a significant increase in emissions
n
"Use this emission factor for residual oils with less than 0.5% (N<-5). nitro-
gen conr.enr. For oil with higher nitrogen content (N>0.5), Use emission
factor of 120 lb/103 g«l
Based on sulfur content cf 2000 sr/106 scf
286
-------
TABLE 7-28. ESTIMATED FUGITIVE NONMETHANE HYDROCARBON EMISSIONS
FROM A TYPICAL HYDROTREATING UNIT
Ni
CO
Number of Sources in Process Unit „
Emissions
Source Type
Va) vea
Open-lind
(Sample)
Valves
Puiups (Pump
Seals)
Drulnu
Flangeu &
Fittings
Relief Valvea
Comproaaora
(Comprcatior
Seals)
• L u t< c a u — — — —
Stream Service Counts or Estimates
Classification From Radlun Study
Gas/Vapor
Light Liquid
(vy > 0.1 ii.la « lOO'l?)
Heavy 1. Inn id
(VH < 0.1 |>*U * 100't)
Hydrogen Service
Total
All
Light Liquid
(VP > 0.1 paifl 9 100'f)
Heavy Liquid
(VP < 0.1 ptjla 9 100*F)
Total
AH
All
All
Hydrocarbon
Hydrogen
Total
235
208
102
1"1
~645a
-
6( 9)
4( 5)
10(14)a
24°
2743°
6C
0(0)
3(6)
3(6)a
auui
CounLu or Estimates Euui;
From PES Study Facti
226 - 389 0.
378 - 648 0.
0 0.
1B1 - 312 0.
785 - 1349C
17 - 29b 0.
B(ll)-16<22) 0.
0 0.
8(ll)-16(22f>
0.
2585 - 4465C 0.
0.
0(0) 1.
3(6) 0.
3(6)*
:»:si
iuloil
>r, Ib/hr
059
024
0005
018
005
25
046
070
00056
19
4
11
Estimated Total
13.
4.
0.
1.
20.
0.
2.
0.
2.
1.
27.
3 -
99 -
0 -
82 -
1 -
085-
25 -
0 -
25 -
1.
44 -
1.
0.
0.
0.
4 -
23
15
0
5
44
0
5
0
5
68
2
14
0
66
66
56
.0
.6
.051
.62
.3
.145
.50
.23
.73
.50
.0
thyaically Counted
Counted From Flnu Dlugramu
Estimated
Ktfereuca 49
-------
TABLE 7-29. ESTIMATED COMPOSITION OF FUGITIVE EMISSIONS
FROM A HYDROTREATING UNIT*
00
00
Stream
Estimated percentage of emissions
attributed to each stream - %
VJeightcd contribution, of each
component to unit emissions - pprow
Benzene
Toluene
Ethylbe.nzene
Xylenes
Other Alkylhenzenes
Naphthalene
Anthracene
Biphenyl
Other Polynuclsar Aronatics
n-llexane
Othar Alkanes
Olcfins
Cyr.lo Alkanes
Hydrogen
Straight Run
Naphtha
47
119
1232
417
763
7792
683
2
295
7042
18254
23/i817
0
198579
0
TJesulf urized
Naphtha
47
119
1232
417
763
7792
538
2
295
7042
18254
234817
0
198579
0
Ha Recycle
Gas
6
0
0
0
0
0
0
0
0
0
0
39000
0
0
21000
Totals
100%
238
2464
834
1526
15584
1376
4
590
14084
36508
508634
0
397158
21000
1000000
3Hased on GC-MS analysis of liquid stream samples (and some vapor samples).
Estimates based on the assumption rh.it fugitive emission compositions from
sources in liquid stream service is the same composition a a that of Lhe
liquid contained in the emission sourc.n.
bCorapositions are estimated to 2-3 s iy.nif Jcaut figures. Additional significant
figures ate a result ot calculational procedures, and they should not be given
any importance.
-------
TABLE 7-30. TYPICAL OPERATING CONDITIONS FOR ALKYLATION OPERATIONS
Process
Condition
Reactor Temperature, °F
Acid Strength, Wt. %
Acid in Emulsion, Wt. %
Olefin Space Velocity, v/hr/v
Isobutane Concentration, Vol %
Steam, lb/bbl alkylate
Power, kWh/bbl alkylate
Fuel, 106 Btu/bbl alkylate
Alkylation
35 -
88 -
40 -
0.1 -
40 -
300 -
2.5 -
60
95
60
0.6
80
400
5
HF
Alkylation
60
83
25
30
3
0.3
- 120
- 92
- 80
- 80
- 7
- 1.1
Source: References 38,50,51,61.
Po tentially Hazardous _Atmo_sphe_r_ic___Emisslons—The alkylation process-
is a closed system; therefore, the only emissions are those associated with
process heating and fugitive emissions. These emissions are summarized in
Tables 7-31, 7-32 and 7-33.
7.1.5.2 Isomerization
Isomerization processes convert normal paraffins into isopar-
afflns. In general, octane numbers are much higher for isoparafflns than
for normal paraffins. The process is also used to produce isobutane for
use in alkylation units.
Process Conditions—Temperature is a critical factor in isomeri-
zation reactions. In general, equilibrium concentrations of isoparaffins
are increased by reducing the reaction temperature. Typica.1 process condi-
tions and utility requirements for both the vapor phase-solid catalyst
system described earlier and the liquid phase system are given in Table 7-34.
289
-------
TABLE 7-31. TYPICAL EMISSIONS FROM ALKYLAT10N
UNIT PROCESS HEATERS
EPA Emission Factor
(lb/103 gal-oil fired)
(lb/10E scf-gas fired)
Total Emissions
(lb/103 bbl of
total alkylste)
7
10
10(S)+3
142(S)
157(5)
2(S)
5
1
5.1
18
26
26(S)+7.7
3G5(S)
404 (S)
13
2.6
Oil Fired Heaters
Particulates
- Distillate oil
- Residual oil
Grade 4
Grade 5
Grade 6
Sulfur Dioxide
- Distillate oil
- Residual oil
Sulfur Trioxide0
Carbon Monoxide
Hydrocarbons (as CH^)
Nitrogen Oxides
(as K02)
- Distillate oil
- Residual oil6
Gas Fired Heaters
Particulates
Sulfur Oxides (as S02)
Carbon Monoxide
Hydrocarbons (as CK^)
Nitrogen Oxides (as N02)
Soxirce: Reference 7.
Based on a heat input of 360,000 Btu/bbl of total alkylatc with the following
fuel heating values: Oil - 140,000 Btu/pal; Gas - 1050 Btu/scf
S " wt % eulfur in the oil
Improper combustion may cause a significant increase in emissions
Use this emission factor for residual oils with less than 0,5% 0?<.5) nitro-
gen content. For oil with higher nitrogen content (>!>0,5), use emission
factor of 120 lb/103 gal
Based on sulfxir content of 2000 gr/10G scf
22
22+400 (N)
5-15
0.6
17
3
120-230
57
5 7-1-1030 (N)'
1.7-5.1
0.21
5.8
1.0
41.1-78.9
290
-------
TABLE 7-32. ESTIMATED FUGITIVE NONMET11ANE HYDROCARBON EMISSIONS
FROM A TYPICAL SULFURIC ACID ALKYLATION UNIT
Emiuaioiio
Source Type
Va 1 vea
Open- End
(Sample)
Vulvea
Pumps (Pump
Sea lu)
Drains
Flanges &
Fltlings
Relief Valves
Compressors
(Compressor
Sicily )
Process
Stream Service
Classl Clcatlon
Gae/Vapor
LlgliC Liquid
(Vf > 0.1 pala 9 lUO'F)
Heavy Liquid
(VP < 0.1 pats 9 100'F)
Hydrogen Service
Total
All
Light Liquid
(VF > 0.1 pa It If 100'i)
Heavy Liquid
(VP < 0.1 v,i» it 100'F)
Total
All
All
All
Hydrocarbon
Hydrogen
Total
Number of Sources in
Ciumlti or Estimate;!
From Uadlan Study
274
40!
0
0
~677a
_
13(18)
°L°)
I3(18)a
41"
2407a
6C
0
0
0
Process Unit
Counta or Estimates
From PES Study
429 - 719
636 - 1067
0
0
1065 - 1786C
26 - 30b
13(18)-23(32)
o{ P> o{pi
13(ia)-23(32)"b
-
3525 - 5875C
-
0(0) - 2(4)
0(0) - 0(0)
0(0) - 2(4>1>
Source
Emlotilon
Factor, II) /hr
0.059
0.024
0.0005
0.018
0.005
0.25
0.046
0.070
0.00056
0.19
1.4
0.11
Estimated Total
Eml uuluna,
Ibyiir
16.2 - 42.4
9.67 - 25.6
0.0
0.0
25.9 - 68.0
0.13 - 0.15
4.50 - a. oo
0.0
4.50 - 8. 00
2.87
1.35 - 3.29
1.14
0.0 - 5.60
0.0
0.0 - 5.60
J5.9 - 89.1
i'hyjlcally Counted
Counted From Flow Dlagramu
£
Estimated
' Kuftueuce 49
-------
TABLE 7-33. ESTIMATED COMPOSITION OF FUGITIVE EMISSIONS
FROM AN ALKYLATION UNIT3
Olefinn
S t re am
LPG
H2SOi,
Alky late
Totals
Estimnted percentage of emissions
a
ttributed to each stream - %
24
35
0
41
Weighted contribution of each ,
component to unit emissions — ppinw
Benzene
Toluene
Ethylbetxzene
Xy lanes
Other Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Other Polynuclear Arcmatics
n-Hex?.ne
Other Alkan.es
Olefins
Cvclo Alkar.es
0
0
0
0
0
0
0
0
0
0
96000
144000
0
0
0
0
0
0
0
0
0
0
0
350000
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
0
0
0
1
39
409572
381
5
0
0
0
1
1
0
0
0
1
39
855572
144381
5
1000000
Rased on Cfl-MS analysis of liquid stream samples (and some vapor samples).
Estimates based on the assumption that fugitive emission compositions froTT,
sources in liquid stream service is the same composition as that of the
liquid contained in the emission source.
Compositions are estimated to 2—3 significant figures. Additional significant
figures are a result of calculations! procedures, and they .should not be given
any importance.
-------
TABLE 7-34. OPERATING CONDITIONS AND UTILITY REQUIREMENTS
FOR PARAFFINS ISOMERIZATION PROCESSES
Solid Bed
Systems
Reactor Temperature, °F
Reactor Pressure, psig
Liquid Space Velocity, v/hr/v
Fuel, 10 3 Btu/bbl feed
Electricity, kWh/bbl feed
200
200
1
10
1
- 600
- 1,000
- 4
- 50
- 2
Liquid Phase
Systems
150 - 250
300 - 500
2-3
NA3
NA3
Source: References 38,50,51,61,62,63.
o
NA = not available
Atmospheric Emissions—An isomerization unit is a closed system.
The emission sources for this process are process heater flue gas and fugi-
tive emissions. Emissions from process heaters are summarized in Table
7-35. Fugitive emissions are estimated in Table 7-36.
7 .1.5.3 Catalytic Reforming
Catalytic reforming is one of the most important of all refinery
processes. In catalytic reforming, relatively low octane naphthas are con-
verted to highly aromatic, high octane gasoline blending stocks. The
reforming operation consists basically of contacting oil and hydrogen with
a catalyst in a series of three to six reactors. Because the overall
reaction is endothermic, the mixture must be heated before it is charged to
each reactor.
A number of reactions occur simultaneously during the reforming
process including dehydrogenation, isomerization, and hydrocracking.
Dehydrogenation reactions which result in the formation of aromatics are
the most important.
293
-------
TABLE 7-35. TYPICAL EMISSIONS FROM ISOMERIZATION
UNIT PROCESS HEATERS
EPA Emission Factor
(lb/103 gal-oil fired)
(lb/106 scf-gas fired)
Total Emissions
(lb/103 bbl of
fresh feed)
Oil Fired Heaters
Particulates
- Distillate oil
- Residual oil
Grade A
Grade 5
Grade 6
Sulfur Dioxide
- Distillate oil
- Residual oil
Sulfur Trioxidec
Carbon Monoxide
Hydrocarbons (as CHi,)
Kitrogen Oxides
(as N02)
- Distillate oil
- Residual oile
7
10
10(S)+3
(S)
157 (S)
2(S)
5
1
22
22+400(N)'
0.71
2.5
3.6
3.6(5)41.1
50.7(S)
56.1(S)
0.71(5)
1.8
0.36
7.9
7. 9-KL43 (N)'
Gas Fired Heaters
Particulates
Sulfur Oxides (as S02)
Carbon Monoxide
Hydrocarbons (as CH;t)
Kitrogen Oxides (as N02)
5-15
0.6
17
3
120-230
0.24-0.71
0.029
0.81
0.14
5.71-11.0
Source: Reference 7.
Based on a heat input of 50,000 Btu/bbl of fresh feed with the following
fuel heating values: Oil - 140.000 btu/gal; Gas - 1050 Btu/ccf
°S •= v-t % sulfur in the oil
Improper combustion nay cause a significant increase in emissions
eUse this emission factor for residual oils vvi th .less than 0.5% Q^.5) nitro-
gen content. For oil with higher nitrogen conte.nt (N>C,3)., use emission
factor of 120 lb/103 gal
fBased on sulfur content of 2000 gr/106 scf
294
-------
TABLE 7-36. ESTIMATED FUGITIVE NONMETHANE HYDROCARBON EMISSIONS
FROM A TYPICAL BUTANE ISOMER1ZAT10N UNIT
Emissions
Source Type
Valves
Open- End
(Sample)
Vulvee
Pura|>o (Pump
Seals)
Drains
Flangee &
Fittings
Relief Valvee
Compressors
(Compressor
Seala)
• Proceaa
Stream Service
Classification
Caa/Vapor
Llglit Liquid
Q.I pala 6 100'f)
Heavy Liquid
(VP < 0.1 p»la 4 100'F)
Hydrogen Service
Total
All
Llglit Liquid
(VP > 0.1 pain 8 IQO'F)
lluavy Liquid
(V? < 0.1 t>aln H 100T)
Total
All
All
All
Hydrocarbon
Hydrogen
Total
Number of Sources in Proceoa Unit
238
310
0
102
650a
_
10(14)
0( 0)
10(14)a
26°
2321a
6a
0(0)
2(4)
2<4)a
Source
Einioalan
Factor, Ib/hr
0.059
0.024
O.OOQ5
0.010
0.005
0.25
0.046
0.070
0.00056
0.19
1.4
0.11
Eutimated Total
Kmlualona ,
Ib/hr
14.0
7.44
0.0
1.B4
23.3
-
3.50
0.0
3C f\
. JU
1.82
1.30
1.14
0.0
0.44
0.44
31.5
I'titluvat ed
-------
Catalytic reforming processes are categorized by the method or
frequency of catalyst regeneration. Catalyst beds may be regenerated
continuously, all at once at the end of a 3 to 24-month cycle (semi-
regeneration) , or one at a time while an alternate "swing" reactor is in
use (cyclic regeneration). The method of regeneration affects the choice
of catalyst and the product yie.l ds obtainable.
Process Conditions—A summary of typical operating conditions and
utility requirements for catalytic reforming is given below.3S>5°»5 1
• Reactor temperature: 850 to 1,000°F.
• Reactor pressures
Serai-regeneration: 150 to 500 psig.
Cyclic regeneration: 90 to 200 psig.
Continuous regeneration: 90 to 200 psig.
• Space velocity: 1.5 to 3.0 v/hr/v.
• Power: 5 to 7 kWh/bbl.
• Fuel: 0.15 to 0.32 x 106 Btu/bbl feed.
Atmospheric Emissions—Emissions from catalytic reforming include
emissions from catalyst regeneration, process beater flue gas, and Fugitive
emissions. During the reforming operation, coke is deposited on the
catalyst. The rate of coke formation is a function of the type of feed-
stock and the severity of the operating conditions. During regeneration
a flue gas stream is generated which contains carbon monoxide and low con-
centrations of sulfur and nitrogen oxides.
Total averaged emissions from catalyst regeneration are. quite, low
because only -small, amounts of coke are produced and the frequency of
296
-------
regeneration may be low. These emissions are highest for continuous
operations because more severe operating conditions can be used. Carbon
monoxide emissions from continuous reformers have been estimated at 0.002
to 0.02 pounds per barrel of fresh feed, a relatively small amount.
Emissions from process heaters and fugitive emissions are
summarized in Tables 7-37, 7-38, and 7-39.
7.1.5.4 Hy d r o d e aIky1a t i on
Hydrodealkylation removes alky] groups from aromatic rings at
elevated temperatures in the presence of hydrogen. The reaction can be
conducted either thermally or in the presence of a catalyst.
Since hydrodealkylation is a closed process, the only emissions
are fugitive emissions and emissions from process heaters. These emissions
are summarized in Tables 7-40 and 7-41.
7.1-6 GasJProcessing. <"*,65,66, 67,68,69
Gas processing recovers various hydrocarbons as pure products or
as mixtures of specified compositions. The products of gas processing may
be fuel gas, methane, ethane, propane, propylene, normal and isobutane,
butylencs, normal and isopentane, amylene, and/or a light naphtha.
The feed to gas processing units comes from crude distillation,
catalytic reforming, catalytic cracking, hydrocracking, thermal cracking,
and to a lesser extent, hydrodesulfurination. Major units include acid
gas removal, dehydration, and separation.
297
-------
TABLE 7-37. TYPICAL EMISSIONS FROM CATALYTIC
REFORMING UNIT PROCESS HEATERS
EPA Emission Factor
(lb/103 gal-oil fired)
(lb/106 scf-gas fired)
Total Emissions
(lb/103 bbl of
fresh feed)
Oil Fired Heaters
Participates
- Distillate oil
- Residual oil
Grade 4
Grade 5
Grade 6
Sulfur Dioxide0
- Distillate oil
- Residual oil
Sulfur Trioxide0
Carbon Monoxide
Hydrocarbons (as
Nitrogen Oxides
(as N02)
- Distillate oil
- Residual oile
7
10
10(S)+3
157(S)
2(S)
5
1
22
22+400(N)'
2.9
10
14
14(S)+4.3
203(S)
224(S)
2.9(S)
7.1 .
1.4
31
31+571 (N)'
Gas Fired Heaters
Particulates
Sulfur Oxides (as S02)
Carbon Monoxide
Hydrocarbons (as CHi^)
Nitrogen Oxides (as N02)
5-15
0.6
17
3
120-230
0.95-2.9
0.11
3.2
0.57
22.9-43.8
Source: Reference 7.
Based on a heat input of 200,000 Btu/bbl of fresh feed with the following
fuel heating values: Oil - 140,OCO Btu/gal; Gas - 1050 Btu/scf.
S = wt % sulfur in the oil
Improper combustion may cause a significant increase in emissions
ri
"Use this emission factor for residual oils vith less than 0.5% (N<.5) nitre*-
gen content. For oil with higher nitrogen content 0^0-5), use emission
factor of 120 lb/103 gal
Based on sulfur content of 2000 gr/lO6 scfr
298
-------
TABLE 7-38. ESTIMATED FUGITIVE NONMETHANE HYDROCARBON EMISSIONS
FROM A TYPICAL CATALYTIC REFORMING UNIT
VD
VD
Cuilaslons
Source Type
Valvea
Open-End
(Sample)
Valves
Pump a (Pump
Seals)
Draina
Klangeu &
Fittings
Relief Valvea
Compressors
(Compressor
Seals)
Proceun
Stream Service
Classification
Gas/Vapor
Light Liquid
(VP > 0.1 pala S 100'F)
Heavy Liquid
(Vf < 0.1 pala 8 IQO'1?)
Total
All
I-JgllL Liquid
(VP > 0.1 pala S 100'k')
Heavy Liquid
(VP < 0.1 pale 9 100T)
Total
All
All
All
Hydrocarbon
Hydrogen
Total
Number of Sources in
Count a or Kat inmtea
From Radian Study
100
391
4'J
77
691a
-
13(18)
K 2)
14(20)a
49a .
2961a
fic
0(0)
3(6)
3(6)"
Process Unit
County or Estimates
From PKS Study
15/i - 291
493 - 938
0
139 - 263
786 - 1492C
16 - 30»>
8(11)-17(24)
0
8(ll)-17(24)b
-
2585 - 4935C
-
0(0)
3(6)
3(6)
Source
Emliittion
Factor, Ib/hr
0.059
0.024
0.0005
0.018
0.005
0.25
0.046
0.070
0.00056
0.19
1.4
0.11
Estimated Total
Emissions ,
Ib/lir
9.09 -
9.38 -
11. 2
22.5
0.0
1.39 -
19.9
0.080 -
2.75 -
0.0 -
2.75 -
3.
1.45 -
1.
0.
0.
0.
29.4
4.7i
44.4
0.15
6.00
0.092
6.09
43
2.76
14
0
66
66
58.6
Physically Counted
Counted Front Flow Diagrams
Estimated
^Reference 49
-------
TABLE 7-39. ESTIMATED COMPOSITION OF FUGITIVE EMISSIONS
FROM A CATALYTIC REFORMING UNITa
o
o
Stream
Estimated percentage of emissions
attributed to each stream - 7,
Weighted contribution of each
component to unit emissions - ppmwb
Benzene
Toluene •
Ethylbenrene
J'ylcnes
Other Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Other Po.lynuclear Aroma tics
n-Kexane
Other Alkanes
Olefins
Cycle Alkanes
Kydrogo.n
Desulfurized
Naphtha
47
119
1232
417
763
7792
688
2
295
7042
18254
234817'
0
198579
0
He formate
47
2538
36519
15745
80323
152468
3478
0
0
329
11280
s
167320
0
0
0
H2 Recycle
Gas
6
0
0
0
0
0
0
0
0
0
0
39000
0
0
21000
Totals
100%
2657
37751
16162
81086
160260
4166
2
295
7371
29534
441137
0
198579
21000
1000000'
Based on GC-MS analysis of liquid stream samples (and some vapor samples).
Estimates based on the assumption that fugitive emission compositions irora
sources in liquid stream service is the same composition as that of the
liquid contained in the emission source.
Compositions are estimated to 2-3 significant figures. Additional significant
figures are a result of calcuiational procedures, arid they should not be given
any Importance.
-------
TABLE 7-40. TYPICAL EMISSIONS FROM HYDRODEALKYLATION
UNIT PROCESS HEATERS
EPA Emission Factor
(lb/103 gal-oil fired)
(lb/105 scf-gas fired)
Total Emissions
(lb/103 bbl of
fresh feed)
Oil Fired Heaters
Participates
- Distillate oil
- Residual oil
Grade 4
Grade 5
Grade 6
Sulfur Dioxide0
- Distillate oil
- Residual oil
Sulfur TrioxideC
Carbon Monoxide
Hydrocarbons (as CHt,)
Nitrogen Oxides .....
(as N02)
- Distillate oil
- Residual oile
7
10
10(S)+3
142(S)
157(S)
2(S)
5
1
22
22+40000'
4.1
15
21
21(S)+6.2
294(5)
325(S)
10
2.1
46
46+829(N)"
Gas Fired Heaters
Particulates
Sulfur Oxides (as S02)f
Carbon Monoxide
Hydrocarbons (as CH^)
Nitrogen Oxides (as K02)
5-15
0.6
17
3
120-230
1.4-4.1
0.17
4.7
0.83
33.1-63.5
Source: Reference 7.
Based on a heat input of 290,000 Btu/bbl of fresh feed with the following
fuel heating values: Oil - 140,000 Btu/gal; Gas - 1050 Btu/scf.
CS =• wt 7. sulfur in the oil
j
Improper combustion may cause a significant increase in emissions
2
Use this emission factor for residua] oils with less than 0,5% QJ<.5) nitro-
gen content. For oil with higher nitrogen content (N>0,5)_, use emission
factor of 120 lb/103 gal
Based on sulfur content of 2.000 gr/10G scf
301
-------
TABLE 7-41. ESTIMATED FUGITIVE NONMETHANE HYDROCARBON EMISSIONS
FROM A TYPICAL HYDRODEALKYLATION UNIT
OJ
O
ho
Emlaaionu
Source Type
Vulveu
0|ieii-Knd
(Sample)
Valves
Furapu (Pump
Seals)
Drains
Flanges &
KlLLlngu
Relief Valves
Coniircauura
(Coiup resbur
Seals)
Counted from
Estimated
Strenm Service
Classification
Oas/Vapor
Liylit Liquid
(VP > 0.1 psia « lOO'F)
Heavy Liquid
(vr < o.i p.ia « IOO'F)
Hydrogen Service
Total
All
LiBlit Liquid
(VP > o.i pou g locT)
Heavy Liquid
(VP < 0 1 pal a g lOQ'F)
Total
All
All
All
Hydrocarbon
Hydrogen
Total
Flow Diagrams
Number of Sources in
Conntu or Estimates
From Radian Study
179
391
43
22.
690b
-
.' 13(18)
K 2)
36b
2463*
6b
0(0)
3(6^
3(6)
Procesa Unit
Counts or EaClmatea
From PES Study C
116
352
0
inn
560TJ
10a
6(8)
0(0)
-
18BOh
-
0(0)
2(4)
2(4)a
Emission
Factor, Ib/ltr
0.059
0.024
0.0005
0.010
0.005
0.25
0.046
0.070
0.00056
0.19
1.4
0.11
Emissions ,
Ib/l.i
6.84 - 10.6
8.45 - 9.38
0.0 - 0.022
1.39 - 1.80
16.7 - 21.8
0.05
2.00 - 4.50
0.0 - 0.092
2.00 - 4.59
2.52
1.05 - 1.38
1.14
0.0
0.44 - 0.66
0.44 - 0.66
23.9 - 32.1
C
|teference
-------
7.1.6.1 Acid Gas Removal
The acid gas removal unit removes hydrogen sulfide from hydro-
carbon gases, usually by absorption in an aqueous, regenerative sorbent.
C02 and/or mercaptans may also be removed, depending on the process used.
A number of acid gas removal processes are available, distin-
guished primarily by the regenerative sorbent used. Ainine-based sorbents
are most commonly used.
The. feed to a typical unit is contacted with the sorbent, such
as diethanolamine, in an absorption column to selectively absorb H2S from
the hydrocarbon gases. Hydrogen sulfide is then removed from the sorbent
in a regeneration step. The products are a sweet hydrocarbon gas and a
concentrated hydrogen sulfide stream. The hydrogen sulfide stream is
normally routed to a sulfur plant for recovery of its sulfur content.
Alternatively, the sulfide gas may be flared to produce the less toxic
sulfur oxides.
Process Conditions—A typical absorber operates at a pressure of
about 150 psi and a temperature of about 100°F. Pressure, and temperature
may, in some instances, be significantly higher.
Atrnospheric Emi s s i o n s—If a regenerative sorbent system is used
in conjunction with a sulfur recovery unit, only fugitive emissions are
produced. If the hydrogen sulfide stream is flared, sulfur oxide emissions
are produced.
7.1.6.2 Dehydration
Dehydration removes water from the gas after the acid gas removal
step. Excess water may be removed by refrigeration, absorption, or
303
-------
adsorption. Refrigeration processes decrease the temperature to below the
required dew point; condensed moisture is collected for disposal.
Absorption processes allow the moist gas to flow over a hygro-
scopic material such as di- or triethylene glycol. Solid dissicants such
as silica gel or alumina are used in adsorption processes. Beds are
regenerated with hot gas.
Process Conditio ns—Temperature and pressure are interdependent
in condensation processes. For example, if the required dew point is 50°F
at 135 psig and the best available cooling is 90°F, the pressure will be
460 psig.
For absorption processes using di- or triethylene. glycol, absorp-
tion temperatures must be kept below the glycol's decomposition temperature
(327°F for DEC, 405°F for TEG). Temperatures in the regenerator, where
water is separated from the glycol, usually range from 375° to 400°F.
Regeneration temperatures for solid dessicants are 480° to 500°F.
Utilities—A glycol absorption process requires about 0.1 percent
of the fuel produced.
A tmo sp h e r i c Etn i s s i o n s—An estimated 0.1 gallon of triethylene
glycol per 10 ft3 of gas processed is emitted by a glycol absorption unit
in vented water vapor. Water contaminated with glycol may be vented as
steam or it may be disposed of as a liquid. Hydrocarbons may also be
emitted from fugitive sources.
7.1.6.3 Product Separation/TPG Production
Refinery gas is often separated into its components in a gas
separation plant. This separation is usually accomplished by contacting
304
-------
the gas with an absorber oil. Refrigerated absorption, refrigeration, or
adsorption may be used when a separate methane stream is desired.
In the oil absorption process, the gas is contacted with an
absorber oil in a packed or bubble tray column. Propane and heavier hydro-
carbons are absorbed by the oil while most of the methane and ethane pass
through the absorber. The enriched absorber oil is then taken to a stripper
where the absorbed propane and heavier compounds are stripped Erom the oil.
In the refrigeration process, the gas is first dried with molecu-
lar sieve beds. It is then cooled in a heat exchanger to - 25°F. Condensed
hydrocarbons are removed in a gas-]icuid separator. The gas from this
separator is passed through a second separator at - 135°F. Liquids from
the separators arc fed to a series of distillation columns where methane,
ethane, propane, butane, and other products are recovered.
An activated carbon bed adsorbs all hydrocarbons except methane.
The bed is regenerated with heat and steam; the resulting hydrocarbon vapor
is condensed and the water separated. The resulting hydrocarbon product is
then fractionated into its various components.
Process Conditions—Pressure in an oil absorber may be as high as
400 psi, but is usually lower. Inlet gas and oil temperatures are 90° to
100°F.
Emissions--Fug111ve emissions from leaking pumps, valves, com-
pressors, and other fittings are the only emissions from product separation.
305
-------
7.1.7 Other Processes
7.1.7.1. Asphalt Proc.es sing /Product ion
Asphalt is produced as the bottoms from vacuum distillation,
discussed in Section 7.1.1.2. The removal of lube oil by deasphalting
is discussed in Section 7.1.7.A.
The quality of asphalt is improved by blowing a:i r through it (air-
bHowing) to increase its melting temperature and hardness. Both batch and
continuous processes are used. Catalysts such as ferric chloride or
phosphorus pentoxide arc sometimes used.
Because asphalt is distilled before it reaches the air-blowing
process, hydrocarbon emissions from tVic process are relatively minor.
Available data indicate that uncontrolled emissions from air-blowing of
asphalt are about 60 pounds per ton of asphalt. The operating conditions
are favorable for the production of extremely undesirable polynuclear
aromatics.
In some refineries, air-blown units have been replaced with
vessels packed with solid absorbents. These vessels have no emissions
other than fugitive, emissions.
7.1.7.2 Blending
Products with desired characteristics are often made by the mix-
ing of various components. The most common blending operation in petroleum
refining is the manufacture of gasoline.
Blending may be by batch or in-line. Batch blending takes place
in a blending tank to which components are added individually. Agitation
306
-------
may be either by an external circulation loop or by internal impellers
powered by external motors.
In-line blending may be partial or continuous. Partial blending
involves simultaneous combination of stock components in a mixing manifold.
Final additions are made downstream or in a storage tank. Continuous
blending is the simultaneous blending of all components in a mixing
manifold.
Fugitive emissions from batch blending tanks are often more than
from similar storage tanks because of the agitation. Fugitive emissions
from in-line blending are limited to fugitive leaks from valves, flanges,
and other process equipment.
Control technology for batch blending operations includes float-
ing roofs on blending tanks and replacement of batch operations with in-
line blending operations.
7.1.7.3 Hydrogen Production
A refinery with a large distillate hydrotreater or gas oil hydro-
cracker requires more high-purity hydrogen than is supplied by other
refinery processes. It is estimated that by 1980, slightly less than 40
percent of the hydrogen used in refineries will be manufactured within the
refineries.7'
Steam-hydrocarbon reforming is commonly used for hydrogen pro-
duction, but because it uses valuable light hydrocarbons, it will probably
be gradually replaced by partial oxidation of heavy oils. The choice
between the two processes depends on the cost and availability of raw
materials.72
307
-------
Emissions from steam-hydrocarbon reforming are limited to those
from process heaters and fugitive emissions. No specific, information was
available on emissions from partial oxidation. It is assumed they are con-
fined to process heater emissions and fugitive emissions. Emissions from
.steam-hydrocarbon reforming are summarized in Tables 7-42 and 7-43. These
emissions are more appropriate for units using liquid feedstocks. Those
units utilizing natural gas as feed should have low emissions of nonmethane
hydrocarbons.
7.1.7.4 Lube. Oil Processing/Production
Lube oil stock is produced as the 700 to 1,000°F fraction of the
residuum from vacuum distillation. Procedures for processing the. lube oil
stock into specific products vary greatly, but they can be divided into four
groups: deasphalting, treating, dewaxing, and finishing.
Each of these processes is closed to the atmosphere. Except for
hydrotreating, there are no emissions except for fugitive emissions and
emissions from process heaters. With hydrotreating, there are emissions,
particularly CO, associated with periodic catalyst regeneration.
Deasphalting—A very heavy oil (brightstock) can be produced from
vacuum residues by extraction with propane at temperatures from 104 to "UiO°F.
At these temperatures, paraffins are quite soluble in propane, but high
molecular weight asphaltic and resinous compounds precipitate.
Propane can also be used to separate a lighter oil fraction (SAE
50), a very heavy oil, and hard asphalt by fractionation.
Treating—Several methods are used to improve the viscosity index,
the color, and the carbon residue content of lube oil. The two most common
treating methods arc phase extraction and furfural treating. Hydrotreating
has also been used.
308
-------
TABLE 7-42. ESTIMATED FUGITIVE NONMETTIANE HYDROCARBON EMISSIONS
FROM A TYPICAL HYDROGEN PRODUCTION UNITe
Eraieaiona
Source Typo
Valvea
Open-End
(Sample)
Valvea
Purapfl (Puop
oj Seula)
o
^o
Drains
Flanges &
Fittings
Relief Valvea
Compreaaora
(Compreaaor
Sealu)
Process
Stream Service
Classification
Gaa/Vapor
Light Liquid
(VP > 0.1 p*la 8 tGQ'f)
Heavy Liquid
(VF < 0.1 pals 3 100'F)
Hydrogen Service
Total
All
Light Liquid
(VP > a. I pst" « IUO'K)
Heavy Liquid
(VP < 0.1 pals
-------
TABLE 7-43. ESTIMATED COMPOSITION OF FUGITIVE EMISSIONS FROM A
HYDROGEN PRODUCTION UNIT UTILIZING NAPHTHA AS FEEDSTOCK3
Streams
U)
H-•
o
Fuel
Gas
Straight Run
Naphtha
Hz Recycle
Gas
Estimated percentage of
emissions attributed to each
stream - wt %
Weighted contribution of each
component to unit emissions
ppmw
38
19
19
24
aRased on GC-MS analysis of liquid stream samples (and some vapor samples).
Etttiii'rttes biisad on the. assumption that fugitive £!iiii.r,sion compositions from
sources in liquid stream service is the sane composition as that of the
Jiquid contained in the emission source.
bCouipositior.s are estlmred to 2-3 significant figures. Additional significant:
figures are a result of calculations!, procedures, and they should not be given
any importance.
Totals
100%
Benzene
Toluene
Ethylbenzene
Xylenes
Other Alkylbenzen.es
Naphthalene
Anthracene
Biphenyl
Other Polynuclear Aroma t
n-Hcx.ine
Other Alkanes
Clef in
Cycloalhanes
Hydrogen
0
0
0
0
0
0
0
0
ics 0
0
349600
22800
0
7600
48
498
16S
308
3150
278
i
_i_
119
2847
7379
94926
0
80277
0
0
0
0
0
0
0
0
0
0
0
190000
0
0
0
0
0
0
0
0
0
0
0
0
0
156000
0
0
84000
48
490
169
308
3150
278
1
119
2847
7379
790526
22800
80277
91600
1,000,000
-------
Dewaxing—Dewaxing is the most difficult part of lube oil
manufacture. The oil is contacted with solvent and chilled, causing the
wax to precipitate. The precipitated wax is separated from the mixture
by filtration or centrifugation. The dewaxed oil and solvent are separated
by distillation and steam stripping. The wax is solvent treated again under
different conditions to obtain a deoiled wax product.
Finishing—Finishing processes remove traces of resinous materials
and chemically active, compounds which can deteriorate the color of the
product. The compounds can be absorbed by contacting the oil with various
types of clay, activated earth, or artificial absorbents. Hydrotreating
(hydrofinishing) can also be used to effectively remove nitrogen compounds
which cause the oil to darken and become unstable. Sulfur and oxygen con-
tent are also effectively reduced by hydrofinishing.
7.1.7.5 Sulfur Recovery
A sulfur recovery plant converts hydrogen sulfide to elemental
sulfur. The Clans process is assumed to be used for sulfur recovery by all
major refiners.
Process types and process flow diagrams for the Glaus process are
given in Appendix E (Volume 4). The amount of sulfur reaching the sulfur
recovery unit varies with the percent sulfur in the crude and the extent of
desulfurization. Typically, 60 percent of the sulfur in the crude reaches
the sulfur recovery plant.
Process Conditions—A Glaus plant operates at about 470°F and one
to two atmospheres. About 20 Btu of heat are required per pound of sulfur
produced. However, approximately four pounds of steam per pound of sulfur
are produced in a waste heat boiler. This steam can provide from five to
thirty percent of the total refining steam requirements.
311
-------
Atmospheric Rm1ssions—Process emissions from Glaus plants are
discussed in Appendix E (Volume 4). A 100,000 bpd refinery with a one
percent sulfur crude and a 95 percent efficient sulfur plant will produce
5-6 tons/day of sulfur emissions. Sulfur is emitted as SO?., H2S, COS,
CS2, and mercaptans.
It is estimated that there are 200 valves, 800 flanges, nine
pump seals, 20 drains, and four relief valves on a typical Claus unit.
These can be sources of fugitive emissions of various sulfur compounds
from the Claus unit. However, because sulfur compounds such as H2S are
present in streams, safety practices dictate careful attention to
maintenance.
7.1.8 Waste Treatment
7.1.8.1 Slowdown/Flare
Blowdown/flare systems are common to all crude oil refineries.
A blowdown system consists of pressure relief devices, manual bypass valves,
blowdown headers, knockout vessels, and holding tanks. Compressors and
vapor surge vessels may also be included. A flare is used for final
disposal of noncondensable combustible gases.
A pressure relief valve is an automatic pressure-relieving device
activated by the static pressure upstream of the valve. There are three
types of pressure relief valves: relief valves, safety valves and safety-
relief valves. Relief valves, used primarily for liquid service, open in
proportion to the increase in pressure. Safety valves, used in the
petroleum industry primarily for steam or air service, pop fully open at a
set pressure. Safety-relief valves may be used as either safety valves or
relief valves, depending on application.
312
-------
Another pressure relief device, the rupture disk, consists of a
thin metal diaphragm held between flanges. Rupture disks are sometimes
installed upstream of pressure relief valves to prevent hydrocarbon leakage
from valve seals.
Flares may be. designed for emergency or routine use. These may
be burning pits, elevated flares, or ground-level flares.
Burning pits are normally used only for emergency burning of
large quantities of gases. A typical pit is simply an excavation 4 to 6
feet deep and 30 to 40 feet square with burners mounted on one wall.
These are not commonly used in modern refineries. Elevated flares allow
gases to be burned safely from the top of a stack. Ground flares are
installed in a large open area for safety and fire protection.4
Smoke emissions from flares are avoided whenever possible. For
smokeless operation, three combustion principles are followed: maintenance
of critical combustion temperatures, adequate combustion air, and adequate
mixing of air and fuel. Steam is often injected to provide, turbulence
which promotes mixing. Air and water have also been used. Further dis-
cussion of the use of steam in flares is provided in Appendix E (Volume 4)
and Appendix F (Volume 5). Emissions from blowdown/flares include:
• Combustion products from flares.
• Fugitive emissions.
Emission factors for smokeless flares are given in Table 7-44. It should
be noted that these flare emission factors may not be applicable to specific
flares due to variations in off-gas composition, flow rate, and design
configuration.
313
-------
TABLE 7-44. EMISSIONS FROM SMOKELESS FLARES
Emissions
Component (lb/103 bbl total refinery capacity)
Participates Negligible
SoJ° 26.9
X
CO 4.3
Hydrocarbons 0.8
N0x 18.9
NH3 Negligible
Aldehydes Negligible
o
Source: Reference 7.
Varies with fuel sulfur content.
7.1.8.2 Wastewater Treatment
A tremendous quantity of water is used in a refinery. A substan-
tial portion of this water is reused before discharge. However, it must
normally be treated to remove contaminants before discharge.
Refinery wastewater treatment is of two types: inplant treatment
(pretreatment) and end-of-pipc treatment. Inplant treatment is the use of
procedures which can (1) reduce the amount of pollutants sent to the waste-
water system, (2) reduce the amount of water discharged, and (3) make sub-
sequent end-of-pipe treatment more effective. End-of-pipe treatment
processes are classified as primary, intermediate, secondary, or tertiary
processes, depending on their function.
314
-------
High concentrations of hydrogen sulfide and ammonia are often
reduced by steam-stripping before water is sent to the wastewater system.
Phenol may be removed by using phenolic waters as desalter water: a portion
of the phenol is absorbed by the crude oil.1*6 Any technique which limits
contact between oil and water also reduces the waste load.
A number of procedures have been developed to reduce the amount
of wastewater. Among these are recirculation, use of air coolers and cool-
ing towers to eliminate once-through cooling, and chemical treatment to
prevent corrosion or scaling.
Pretreatment techniques which improve the efficiency of end-of-
pipe treatment include stream segregation, preaeration of the water to meet
immediate, oxygen demand, and surge ponds to smooth the flow of wastewater.
An example of refinery stream segregation in a modern refinery is given in
Appendix F (Volume 5). Older refineries may be able to segregate only
sanitary wast es.
A classification of end-of-pipe wastewater treatment processes is
given in Table 7-45. Each refinery has its own particular scheme based on
the type of refinery, the water use pattern, and applicable pollution
regulations.
Primary treatment is often the only treatment required of a
refinery. API separators remove oil which floats and coalesces on the
surface of the water and sludge which settles to the bottom of the separa-
tor. Parallel plate separators are a relatively new method for removing
oil and sludge which reduce the distance the oil droplets must travel
before collection.
Intermediate treatment removes materials such as emulsions and
suspended or colloidal solids, which neither float nor settle within the
315
-------
TABLE 7-45. CLASSIFICATION OF END-OF-PIPE REFINERY
WASTEWATER TREATMENT PROCESSES
Treatment
Objectives
Processes
Primary
Treatment
Free. Oil and Suspended
Solids Removal
API Separators
Parallel Plate
Separators
Intermediate
Treatment
Emulsified Oil, Suspended
Solids, and Colloidal
Solids Removal
Dissolved Air
Flotation
Coagulation-Flotation
Coagulation-Precipita-
tion
Filtration
Equalization
Secondary
Treatment
Dissolved Organics
Removal Reduction in
BOD and COD
Activated Sludge
Trickling Filters
Aerated Lagoons
Oxidation Ponds
Rotating Biological
Discs
Tertiary
Treatment
Variable. Objectives
Filtration
Air Flotation
Coagulation
Activated Carbon
316
-------
residence time provided in primary treatment. Removal may be by dissolved
air flotation (DAF), chemical coagulation and sedimentation, or filtration.
Secondary treatment involves physical, biological, or chemical
treatment for the removal of dissolved organics. Physical and cherair.al
treatments are considered advanced treatment processes which follow
biological treatment.
All of the biological methods for secondary wastewater treatment
involve oxidative decomposition by micro-organisms. These processes—
activated sludge, trickling filters, aerated lagoons, oxidation ponds, and
rotating biological discs - are discussed in Appendix F (Volume 5).
Some refineries provide additional tertiary treatment downstream
of biological treatment units. This polishing treatment may be necessitated
by changes in refinery effluent water quality or by government regulations
on effluent quality. Tertiary treatment commonly involves the reduction of
suspended solids and carbon adsorption for removal of organic pollutants.
Fugitive emissions are released from all of the above operations.
The extent of these emissions is a function of the amount and volatility
of hydrocarbons entering a unit, emission controls used, and other factors.
The greatest opportunities for emissions are at the front end of the waste-
water system, i.e., severs, open ditches, holding ponds prior to the API
separator, and the APT separator itself. Since the APT separator removes
most of the hydrocarbons with the skimmed oil, units downstream of it
re.lea.se substantially fewer fugitive hydrocarbons. Emission factors for
API separators are given in Table 7-46. Emission rates could not be. deter-
mined accurately enough to warrant the development of emission factors in
this study. Data to update these factors will be collected as part of an
EPA research program on petroleum refinery wastewater system emissions.
317
-------
TABLE 7-46. API SEPARATOR EMISSION FACTORS
Emissions
lb/103 gal lb/103 bbl
Wastewater Refinery Feed
APT separators
(uncontrolled) 5 200
APT separators
(controlled by fixed
or floating roof) 0.2 10
Source: Reference 7.
7.1.8.3 Sludge/Solids Treat ing/Disposal
Many of the solid wastes generated by petroleum refineries con-
tain toxic hydrocarbons or metallic compounds. The wastes may be generated
continuously or intermittently.
Solid wastes have historically been sent directly to landfills
or open pits for disposal. Oily wastes, although sometimes incinerated,
have usually been sent to an oily waste disposal pit.
More stringent solid waste disposal regulations have forced the
adoption of more advanced disposal practices. Landfilling is still the
most commonly used method, but landfills must now be constructed to allow
no direct contact between the waste and surface or groundwater.
Landfarming involves the use of soil bacteria to biodegrade
organic materials in sol:id waste.s. Little is known about the nature of
the degradation products or about the fate of heavy metals or toxic organic
compounds in the waste.
318
-------
Incineration is a relatively expensive method for solid waste-
treatment. Supplemental fuel, pollution controls, and dewatering of the
waste, may be required. And, although the waste volume is reduced, the
incinerator ash must still he disposed.
Chemical fixation involves the addition of certain chemicals to a
waste to form an insoluble solid which can be landfilled. Little leaching
of heavy metals and organic, compounds results from chemically fixed waste.
7 • 2 Con t r o1 Technplog y
Refinery control technology includes all types of equipment,
processes, operating practices, monitoring, maintenance, and raw material/
fuel modifications which result in a net decrease in air emissions within
the reasonable and practical constraints imposed by capital, operating and
energy costs. This section includes discussions of the state-of-the-art of
petroleum refinery fugitive and process emission controls; the need for
additional controls for some sources; emission control technology used in
related industries and its applicability to refining; and the economics
of control.
Detailed descriptions of emission sources and control technologies
are presented in Appendix E (Volume 4). Emissions from transfer facilities/
operations, storage vessels, or other auxiliary processes are not included.
Controls for fugitive emissions are discussed in Section 7.2.1.
Included in this discussion are work practice, and equipment controls.
Equipment controls for process (stack/vent) emissions are described in
Section 7.2.2. Section 7.2.3 includes discussions of process, fuel, and
feedstock controls for process emissions.
Controls for fugitive emission sources are generally applicable
to a particular source type (valve, puir.p, etc..) and are not unicue to any
319
-------
type of process unit. Fugitive emission controls are, therefore, discussed
by source type. Process emission controls are discussed on the. basis of
the type of process unit, because of the differences in emissions and con-
trols between processes.
7.2.1 Control of Fugitive Emissions
In this section the descriptions of fugitive emission control
technology are presented for each type of emission source (valve, pump,
etc.). The order of presentation is such that sources with similar types
of controls are discussed in sequence. The relative contribution of source
types for a hypothetical refinery is presented in Section 2.7.3 of Appendix
B (Volume 3) of this report.
Three levels of control are described for most sources. Existing
controls are those in general refinery use, although the extent of appli-
cation may be variable. Available control technology may be used in some
areas of the refining industry due to regulatory or other requirements.
Control technology transfer includes any types of emission controls that
have been applied to similar types of emission sources in other industries.
7.2.1.1 Valves
Valves can leak hydrocarbons through the junction where the
activating stem penetrates the valve body. Excessive leakage from this
junction is generally prevented by a packing gland or a pressurized grease
seal. If a valve is operated with one side of the valve seat open to the
atmosphere, such as for draining or sampling operations, hydrocarbons may
also leak through the valve seat.
Table 7-47 contains the approximate distribution of refinery
valves screened by Radian within the battery limits of major process units
during the thirteen refinery sampling programs. The distribution of each
320
-------
TABLE 7-47. APPROXIMATE DISTRIBUTION OF REFINERY PROCESS
VALVES3 BY TYPE AND SERVICE
Type
Valve
Gate
Globe
Plug
Butterfly
Diaphragm
Total
Valve Type Distribution
by Service, %
Manual
64
3
5
0
0
74
.7
.8
.7
.6
.0
.8
Control
0
23
0
I
0
25
.0
.3
.0
.8
.1
.2
Total
Type
Distribution, %
64
27
5
2
0
100
.7
.0
.7
. 5
.1
.0
Check and sample system valves excluded. No dry-servir.e slide valves were
surveyed.
321
-------
type of valve is shown for manually operated and automatically controlled
service categories. Approximate]y 88 perc-.ent of all the screened refinery
valves were either manual gate valves (65 percent) or control globe valves
(23 percent).
Existing Controls for Valves—These controls include the. valve
stem seal, inspection and maintenance practices, and closure of the
atmospheric side of open-ended valves.
Valve StemSeals—The valve stem seal is designed to prevent
leakage of the contained fluid and is therefore a fugitive emission control.
All gate, globe, and butterfly valves screened by Radian had a packed gland
stem seal. These packed stem valves represent approximately 94 percent of
all refinery valves. Plug valves typically have a grease-lubricated,
tapered plug to prevent leakage. Grease may be added periodically to pre-
vent leakage and to assure proper operation of the plug valve.
Packed stem seals consist of a stuffing box that surrounds the
stem, rings of compliant packing material in the annular space, and a gland
or follower that is used to compress the packing against the stem to form
a seal. Figure 7-1 is a simplified diagram of the type of packed seal used
in valve stems.
Stuffing
Box
Packing
Gland
Working
Fluid
"\seal facex*
or
Follower
Figure 7-1.
Packing
Simple Packed Seal
~_ Valve
Stem
Possible
Leak
Areas
322
-------
The fluid may be fvirther prevented from diffusing through standard
type packing by dispersion of lubricant through the packing. The lubricant
also alleviates galling, heating, and scoring of Che stem or shaft. In
most cases, a lubricant must be compatible with the packing and the working
fluid. In refining, this lubricant might be a. silicone oil, a petroleum
grease, or a TFE or graphite dispersion in an oil or grease.
Lubricants may be present in the coils or rings of packing as
received. They may also be introduced Into the gland through a "grease"
fitting which passes lubricant into the stuffing box.
Table 7-48 shows the diversity of valve packing materials used
alone or in combination. Most of these materials may be purchased in
coils or in preformed rings. They may be. solid or stranded and may have
a round, square, "U," or chevron cross-section.
All refineries have operating practices that require repair of
any detected leaks. These practices arc primarily aimed at preventing
fires or other safety ha/.ards that could result from large amounts of hydro-
carbon leakage. Visual methods or odor arc generally relied upon to detect
leaks. However, many leaks from valves and other sources may not be.
detected by sight, hearing, or smell. It is also a common refinery
76 77
practice to lubricate valves and tighten packing glands periodically. '
Open-ended valves may be used for draining, venting, or sampling
operations. In addition to fugitive emissions from the stem seal, the
valve seat may be a source of fugitive emissions. To prevent emissions
through the seat, the open-end can be sealed with a cap, plug, blind
flange, or a second valve. Two valves in series (double block and bleed)
can also be installed on sampling connection. This provides a second valve
seat to resist emissions of the process fluid to the atmosphere.
323
-------
TABLE 7-48. PACKING MATERIALS - PROCESS VALVES
Packing Material
r orm
Use
Temperature
Flexible, all metallic
Flexible metallic packing
(aluminum).
Flexible metallic packing (copper)
ft-f iber puro .nsbof.tos ami fine
lubricating graphite (nonmo.tal.11c).
Closely braided asbestos yarn; top
jacket reinforced with Inconel
wire; core: long fiber asbestos.
Pure asbestos yarn witb an Inconel
wire insert around a resilient
asbestos core impregnated with
graphite.
Twisted long fiber Canadian
asbestos.
Spiral wrapping. Thin
ribbons of soft babbit
foil.
Spiral wrapping. Thin
ribbons of soft annealed
aluminum foil loosely
around a small core of
pure dry asbestos.
Soft annealed copper
foil loosely around a
small core of pure dry
asbestos.
Graphite special loug-
fibor asbestos binder.
Spools, die-formed
rings. .
Spool form, die formed.
Spool form, die formed.
Valve stem
packing
Hot oil valves,
diphenyl valves,
Up to 450°F.
Up to 1000CF.
Hot oil valves, Up to 1000°F.
diphenyl valves.
Extreme
resilience.
High-temperature
valves.
Up to 750°F.
Up to 1200°F.
Valve stem for Stuffing box
air, water, steam temperature up
and mineral oil. to 1200°F.
Valves handling,
high and low
pressure steam.
Up to 500°F.
(Continued)
-------
TABLE 7-48. (Continued)
Packing Material
Form
Use
Temperature
1-0
Ul
Asbestos, graphite and oilproof
binder.
Solid, braided TFE.
Braided asbestos with complete
impregnation of TFE.
Braided of high quality wire-
inserted asbestos over a loose
core of graphite and asbestos.
Braided of high quality wire-
inserted asbestos over a loose
core of graphite.
Braided of long-fiber Canadian
asbestos yarn each strand Impreg-
nated with heat-resistant lubricant
Long-fiber Canadian asbestos yarn,
each strand treated with a synthe-
tic oilproof binder and impreg-
nated with dry graphite.
Spool form, die formed.
Coil, spool, ring.
Coil, spool, ring.
Coils, spools.
Coils, spools.
Coils, spools.
Coils, spools.
Shutoff valves. Up to 550°F.
Valve shaft for 100°F to 500°F.
highly corrosive
service.
g
Valve stems in 100°F to 600°F.
mild chemical or
solvent service.
Valve stems,
steam, air,
mineral oil.
Up to 1200°F.
Stainless-steel Up to 1200"F.
valve stems, air,
steam, water.
Valves for steam, Up to 550°F.
air, gas and mild
chemicals.
Refinery valves. To 750°F.
(Continued)
-------
TABLE 7-48. (Continued)
Packing Material
Braided/overbraided, wire-
inserted, white asbestos packing
impregnated with.a heat-resistant
lubricant.
Braided white asbestos yarn
impregnated with TFE suspensoid.
Braided or bleached TFE multi-
filament yarn.
Braided TFE multifilament yarn
impregnated with TFE suspensoid.
Asbestos jacket, braided over a
dry-lubricated plastic core of
asbestos graphite and elastomers.
Form
Coils, spools.
Coils, spools.
Spools, coils.
Spools, coils.
Spools ana coils,
Use
Temperature
Valve stems, for
valves handling
steam, air, gas,
cresylic acid.
Valve stems.
Up to 750°F.
100°F to 600°F.
Valve stems for 12°F to 500°F.
highly corrosive
liquids.
Valve stems for 120°F to 600°F.
corrosive chemi-
cals, solvents,
gases.
Valve stems, for Up to S50°F.
valves handling
superheated steam,
hot gases.
Source: Preference 75.
-------
Effectiveness of Existing Controls—The overall effectiveness of
existing controls is reflected in the emission factors given in Section 5
of this report. These emission factors were derived from test data collec-
ted from a broad cross-section of thirteen refineries. All levels of the
types of control existing at the time of the field sampling (1977-1979)
were included. The effectiveness of individual types of existing controls
(type of packing, maintenance schedule) could not be determined from the
available data.
Available Control Technology for Valves—Leak detection and repair
programs are the available controls for valves. Programs of this type are
already a regulatory requirement in some areas. They will prohably become
more, common as additional regulatory requirements are promulgated and value
of the products lost as fugitive emissions increases.
Leak detection and leak repair programs consist of strategies to
Identify significant fugitive hydrocarbon emission sources combined with
methods to reduce or eliminate the leakage. At a specified interval, each
valve would be checked with a portable hydrocarbon detector. If a pre-
determined hydrocarbon concentration limit (action level) were exceeded,
the valve would be repaired. The repair could consist of tightening the
packing, injecting grease, replacing the packing, or replacing the valve.
During repairs such as tightening or greasing, the hydrocarbon detector
should be used to permit assessment of the effect of the repair attempt.
This type of repair is called "directed" maintenance.
Effectiveness — In the limited valve, repair study conducted by
Radian, the average weight percent emission reduction immediately after
"directed" maintenance was 91 percent. The detailed results of the main-
tenance study are shown in Section 6 of Appendix B (Volume 3). They are-
summarized in Section 5 of this report. Data on the long-term effects of
maintenance are not available.
327
-------
In some cases injection of sealing fluids into the packing area
of the valve may be used to reduce fugitive emissions. The effects on
emission reduction and valve operability have not been reported. For some
control valves, operating procedures may prohibit excessive in-service
adjustment to prevent malfunction of vital process control valves.
The required frequency of leak detection is dependent on the
rate of recurrence of repaired leaks and the rate of occurrence of new
leaks. The selection of an appropriate action level is dependent on the
demonstrated ability to repair leaks of a given magnitude. Radian test
results indicated that the smaller the initial leak rate, the more likely
it is that repair efforts will be ineffective.
Because of the sparseness of data on long-term effectiveness of
leak repair, frequency of occurrence of leaks, and the fraction of leaking
valves which are unrepairable while in service, no quantitative estimate of
the overall emission reduction can be defined.
The major costs for leak detection and repair are for labor
expenses. The hydrocarbon detector can cost up to $4,250 per instrument,
and if leak surveys were conducted as frequently as once per month each
process unit would probably need one instrument. Actual labor costs are
dependent on the wage rate of the persons performing the leak survey and
leak repairs. Estimates have been made for the time, needed to conduct
leak surveys. One petroleum refining company has estimated that one minute
7 ^
per valve is the average time required for leak detection. " The time
needed to repair a leak will be dependent on the type of repair attempted.
Simple tightening of packing by refinery employees would obviously be much
cheaper than injection of a sealing fluid by leak repair contractors. The
total cost of a leak detection and repair program would be reduced by the
value of the product that was prevented from leaving the process as an
emission. The emission reduction would also represent an energy saving.
326
-------
Control Technology Transfer for Valves—Fugitive emissions of
some process fluids may be hazardous or toxic. In industries with these
constraints, valves with isolated stem seals may be used. The diaphragm
and bellows-sealed valve are two types of these, valves. Because the
process fluid is prevented from contacting the stem/body junction by a
bellows or diaphragm, the potential for fugitive leakage is reduced. These
valves are not generally applicable to refinery use, however, because of
several limitations.
The diaphragm material in the diaphragm valve limits operation to
about 50 psi pressure differential.flu This type valve has definite limita-
tions in refinery use. It can fail catastrophically upon overheating of
the elastomer diaphragm, so it should not be used in hydrocarbon service.
where a fire could be fed by its failure. The bellows-sealed valve,
because of the corrosion and fatigue failure potential of the bellows, is
subject to combined temperature-pressure-corrosivity stress. Its usage is
best defined by the valve manufacturer. Bellows-sealed valves should have
stem seal packing as back-up protection against bellows failure.
Because use of these special valve stem seals will probably be
limited, the impact of their use on emission control should also be limited,
as would any economic impact. No primary energy cost would result from
substitution of a very limited number of packless valves for conventional
packed-stem, bonnet-sealed valves.
Diaphragm and bellows valves are approximately 1.5 to 3.7 times as
a i
expensive as gate valves according to the GARB report. Another source
estimated that bellows valves might cost 10 to 20 times as much as packed-
8 £
stem valves, but would have a lower cost multiple if purchased in volume.
329
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7.2.1.2 Flanges
Flanges are paired junctions between sections of pipe and pieces
of equipment. They are sealed against leakage by the tightening of bolts
or studs which compress a flat gasket between the flat faces of the mating
flanges, or compress an "o" ring set in the grooved faces of special
flanges. The most common flanges have raised faces to accommodate tighten-
ing of the bolt and centering of the gasket. TypJca.l gasket materials are
asbestos composition or spiral, metal strip-reinforced asbestos or TFE.
"0" rings may be made of neoprene, TFE or soft metals, depending upon
temperature and pressure limits.
The results of the refinery sampling program showed that flanges
have a very low emission factor, and even though there are many of them,
their overall contribution is small. The only real controls available for
flanges are leak detection and repair programs. If a leak Is found, the
only repair options are tightening the flange bolts or injection of a seal-
ing fluid, since most flanges cannot be isolated from the process in order
to permit gasket replacement.
A large amount of time would be required to inspect all flanges
with hydrocarbon detectors. The expenditure of this time and manpower dues
not appear justified given the low average emission rate for flanges.
7.2.1.3 Pump Seals
Pump seals prevent the escape of process liquid from the area
between the rotating pump shaft and the stationary pump housing. There are
two basic types of seals, the. packed seal and the mechanical seal. The
packed seal can be used on pumps with reciprocating or rotating shaft
motion, and mechanical seals are applicable only to rotating shafts.
330
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Existing. Control Technology—'This study indicated refinery
pump-seal combinations fall almost exclusively into one of three broad
categories: centrifugal pump - mechanical seal (82.1 percent), centri-
fugal pump - packed seal (11.5 percent), and reciprocating pump - packed
seal (6.4 percent).
The tvjo types of existing controls for pumps are the pump seal
itself, and inspection and maintenance of the pump seal. The packed seal
and mechanical seal resist leakage of the pumped fluid by different
mechanisms, and are described separately.
The packed seal is used to seal both rotary and reciprocating
shafts against leakage of liquid from the "working fluid" end of the shafts
to the atmosphere. Compressed packing in the stuffing box forms a contact
seal against the moving drive shaft. Friction resulting from this contact
requires that either the working fluid be allowed to leak from the stuffing
box housing the packed shaft, or a supplementary liquid be introduced to
remove fractional heat.
Packings for the compression-type packed seals may be solid or
braided, twisted or ribbon-form (the latter form in graphite only). They
may be obtained in continuous rolls or preformed rings. Packing materials
include asbestos/TFE, TFE (lubed), asbestos/graphite, graphite-fiber,
graphite-ribbon, lead, aluminum, and Inc.onel-reinforced asbestos over
resilient case.
Under moderate conditions, the trend in braided backings is away
from asbestos and toward TFE because of the latter's low coefficient of
friction and its chemical inertness.
The mechanical seal in its tr.any forms is the predominant pump seal
today. Contrary to the broader application of packed seals to both rotating
and reciprocating shafts, however, mechanical seals are used only on rotary
331
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shafts. Mechanical seals may be used to seal both pump and compressor
shafts, but are more universally applied to pumps, specifically centrifugal
p ump s.
Mechanical seals are prefabricated assemblies which shift the
point of wear from the drive shaft, as with packed seals, to easily
replaced pairs of rings. One of the. rings is attached to the pump shaft,
and the other to the gland plate or its equivalent. Seal faces are per-
pendicular to the shaft and are typically lapped to a flatness of two light
bands. This precise flatness accounts for their typically low leak rate
when carefully installed and started up.
Single mechanical seals will generally serve to limit emissions
in the majority of applications, but double mechanical seals provide an
added margin of protection against seal failure. Double seals normally
have a barrier liquid circulating between the seals. If the inner seal
should fall, the outer seal will prevent escaping fluid from reaching the
atmosphere.
Mechanical seals are used in the majority of refinery pumps. The
American Petroleum Institute (API) recommends mechanical seals as particu-
larly advantageous for hydrocarbon emission control in the following cases:
(1) ". . .more—or-less continuous pumping of products having a Reid Vapor
Pressure of five pounds [per square inch (author's note)] or greater. . ."
and (2) ". . .when fluids are under substantial pressure and when the pump
or compressor is in continuous service. For pumps operating on stand-by
service either packed or mechanical seals may be used."'6
At the time of the Los Angeles County, California, study twenty
years ago, mechanical seals made up only 42 percent of the seals in the use
H 1
there. In the current refinery stud}7, the percentage was 82 percent.
The Radian survey showed this percentage to be further subdivided into
332
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approximately 67 percent single mechanical seals and 15 percent double
mechanical seals.
Visual inspections are generally used to detect significant pump
emissions. In some cases pressure gauges/alarms are used to detect build-
up of pressure in barrier fluids of double mechanical seals. Such a pres-
sure buildup indicates failure of the inner seal.
Packed seal emissions can generally be reduced by tightening the
packing gland. This can be accomplished while the pump is in service.
Emissions from a mechanical seal, however, indicate a mechanical failure
in the seal assembly. The pump must be taken out of service, and the
mechanical seal can then be replaced.
frequency o_f_ App 1 ication_,^_Ef feetiveness , and Cost of Pump Seals—
Application of the types of pump seals is relatively uniform within the
refining industry. This may be the result of a greater uniformity of
feedstocks and products in the refining industry than in the chemical
industry. The application of standards published by the American Petroleum
Institute (API) has also undoubtedly led to uniformity among devices used
to control fugitive emissions, not only from pumps, but also from some of
the other devices tested in this program.
The frequency of application of types of pump seals that was
observed in the Radian sampling program is shown in Table 7-49. Sufficient
data are not available to compare the relative control effectiveness of
the. various types of seals.
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TABLE 7-49. DISTRIBUTION OP PUMP SEALS IN RADIAN REFINERY STUDY
Percent of
Pump Type Population
A. Centrifugal Pump - Mechanical Seal 82.1
B. Centrifugal Pump - Packed seal 11.5
C. Reciprocating Pump - Packed Seal 6.4
TOTAL 100.0
Table 7-50 presents a cost breakdown of pump system elements for
systems rated at 3 - 200 horsepower. May, 1980 costs were rolled back to
mid-1979. Cost estimates of packed and mechanical seals are shown in part
(5) of the table in mid-1979 dollars, and in part (6) as percentage add-on
costs to bare, uninstailed pump costs [Subtotal (4)]. These add-on costs
for seals range from 1.2 to 3.0 percent for packed seals to 14.2 to 36.4
percent for double mechanical seals for the most common shaft size of
1.875 inches diameter.
Table 7-51 contains a comparison of seal friction losses and
hydrocarbon leak estimates for packed seals and three basic types of
mechanical seals. Friction losses and hydrocarbon losses are known to
vary widely with the fluid properties of the sealed liquid, the seal face
materials, the condition of the seal, bearings and shaft, and seal design,
so these figures are presented only as approximations of expected
performance.
Inspection and Maintenance—All refineries practice inspection
and maintenance of pump seals to prevent fire hazards resulting from
complete seal failure. Pump seals are usually inspected visually once
per day or per shift. Packed seals can be adjusted while in service to
reduce leakage, but mechanical seals usually require, removal for repair.
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TABLE 7-50. CENTRIFUGAL PUMP SEALS - COST CONTRIBUTION TO TOTAL
PUMP COST*
Pump Horsepower 3.0 100. 100. 200.
Shaft Diameter, Inches 1.875 1.875 2.375 2.375
1. Pump, including shaft, coupling,
bore plate, seal/bush hardware as
required. (Installation costs
not included)3 2830 4670 4810 6370
2. Switchgear - Switch, enclosure
3.
4.
5.
lighted push botton."
Driver - Electric
Subtotal
Seal Alternatives
a. Packed Seal
b. Single Mechanical Seal
c. Double Mechanical Seal
620
230
3680
110
860
1340
1940
2850
9460
110
860
1340
1940
2850
9600
130
1000
—
4110
8750
19230
130
1000
—
6. Seal Costs - Percentage of Subtotal (4)
a. Packed Seal 3.0 1.2 1.4 0.68
b. Single Mechanical Seal 23.4 9.1 10.4 5.2
c. Double Mechanical Seal 36.4 14.2
*Mid-1979 Costs = May, 1980 Dollars x 0.921
liases:
a 85
Reference 84. Pump built to API Specification 610, and upon the following
conditions: 1) Low corrosion—steel puir.p casing, cast iron/steel inpeller
2) Seal gland pressure—200 psig (-1/3 of discharge pressure
maximum)
3) Pur.ped Fluid—light gasoline
4) Pu:rpcd Fluid Temperature— £ 350°F
5) Shaft Speed —3500 RPM
Reference 86. Switch gear—explosion-proof, locally-mounted push button
stop-start with red light for "Oji" indication.
Reference 84. Electric Driver—Three phase, 400 volt, explosion proof.
Reference 87. Packed Seal—Cost of packing materials approximate.
Referer.ze 88. Single Mechanical Seal—Crane Packing Co. )?8-B-l with throttle
bushing as hack-up.
Reference 87. Double Mechanical Seal—Chesterton Seal No. 241.
335
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TABLE 7-51. ESTIMATED ENERGY LOSSES - PUMP SEALS
Hydrocarbon Leak Estimates, Ib/hr
Seal Power Open ,
Seal Type Consumption, kW Literature This Study
Packed 1.16 0.264°
Single mechanical,
unbalanced 0.422 X).0044e
Single mechanical,
balanced 0.194 >0.0044e
Double mechanical,
balanced 0.287 =0.00
0.16-0. 37, d
all pumps
Reference 89.
See Appendix B (Volume 3), p. 2-263, pumps, light liquids.
r*
Based upon 60 drops/min of hexane @ 20 drops/mA. Reference 90.
Range based upon 95% confidence interval.
Based upon as little as 1 drop/min. of hexane @ 20 drops/mfc. Reference 91-
Reference 91.
Bases: Pump shaft dia.—1.875 in.; stuffing box pressure—200 psig; barrier
fluid pressure—175 psig (double mechanical seal only); pump speed—
3500 rpm; pump horsepower range (typical)—3-100 h.p.
336
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The effectiveness of these inspection and maintenance programs is reflected
in the emission factors presented in Section 5 of this report.
Available Control Technology for Pumps—Leak detection and repair
strategies are the available controls for pumps. The procedures for find-
ing leaks requiring repair are the sane as those described previously for
valves.
No data are available to quantify the effectiveness or cost of
leak detection and repair for pumps. Effectiveness would be dependent on
initial leak rates, the ability to repair the leaks, and the length of
time before the leaks reoccurred. Costs would be dependent on labor rates,
labor requirements, and the value of the product saved. Average leak
detection time required for pumps has been estimated to be five minutes
per seal, and the average leak repair time has been estimated to be 80
hours per seal.
Technology Transfer for Pumps—Sealless pumps are used in other
industries in cases where the pumped fluid is toxic or otherwise hazardous
and leakage cannot be tolerated. Sealless pumps include diaphragm pumps,
hermetically sealed "canned" pumps, and magnetically coupled pumps. Since
these pumps do not have a shaft/casing seal, their emission potential is
much lower. Emissions may result from diaphragm failure or case failure.
p c
Sealless pumps are not covered by API Standard 610 ' for pumps,
which may explain why no sealless pumps were found in the 13 refinery
survey. If sealless pumps are to be used in the refining industry, they
must be proven performers in terms of leak-tightness, reliability, main-
tainability, useful life and safety.
The original cost of a "canned" pump may be approximately 110 to
o o
.115 percent of the cost, of a centrifugal pump with conventional seals/'
No data are available to discern differences among the other true costs of
3.37
-------
running conventionally-sealed versus sealless pumps. Sealless pumps also
have a more limited range of applicability due to limitations on tempera-
ture, throughput, and horsepower.
7.2.1.4 Compressor Seals
A number of types of compressor seals reduce emissions of the
compressed gas from the. compressor housing. The five basic types are
packed (reciprocating shaft), labyrinth (rotating shaft), restrictive ring
(rotating shaft), liquid film/bushing (rotating shaft), and mechanical
contact (rotating shaft).
The basic principle of packed compressor seals is similar to
packed pump seals. However, cooling of friction-type compressor seals
differs from cooling of pump seals of similar construction in that the
gaseous compressor working fluid provides negligible lubrication and has
a lower heat capacity than does liquid. For these reasons most, but not
all, contact-type compressor seals use some form of liquid seal coolant
which may also serve to reduce gas emissions.
The various types of non.pac.ked seals differ substantially from
each other and from mechanical pump seals. Both the packed and mechanical
types of compressor seals are described in detail in Appendix E (Volume 4).
Existing Control Technology—The five basic types of compressor
seals are applied in refinery service. The API has estimated that 60- 70
percent of refinery compressors have, packed seals, 10 percent have
93 9 '*
mechanical contact seals, and about, five percent have labyrinth seals.
Radian found that approximately 80 percent of the compressors
surveyed in the current study had reciprocating shafts with packed seals.
About 60 percent of the compressors process gas which contains less than
338
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50 percent hydrogen. The remaining 40 percent compress streams which are
predominantly hydrogen.
The various types of compressor seals cannot be universally
applied in any or all refinery operations. Because of lubrication and
cooling limitations, packed seals are rarely used around rotating shafts.
q 5
The labyrinth seal allows some gas to continually escape. Nelson' states
that the loss rate or recycle rate from this type of seal is not generally
acceptable today for energy and environmental reasons. For this reason,
labyrinths are now more often seen in outboard seals in combination with
other sealing devices.
The restrictive ring seal is superior to the labyrinth seal
alone, but is limited to about 200 psi and relatively clean gas service.y3>9
Sealing and scavenging ports may be used for labyrinth seals and for
restrictive ring seals.
The liquid-film seal is relatively simple, and is not subject
to significant wear. It is capable of operating at pressures of up to
5,000 psi in a multiple, seal configuration, but has, in all configurations,
9 5
a relatively complicated piping and control system.
The mechanical contact seal differs significantly from a mechani-
cal pump seal, but utilizes the identical concept of zero clearance at
closely-lapped wear surfaces to limit leakage. This type of seal is
limited to pressures of about 500 psi. Its leak rate is the lowest for
the seals described, but, like mechanical seals for pumps, mechanical
contact seals are subject to catastrophic failure. Their oil supply
systems, where used, are simpler than oil supply systems for liquid-film
9 5
seals. Mechanical contact seals form a nearly perfect seal when at
9 5
rest " in contrast to pump mechanical seals which are believed to seal
better when the faces are rotating.
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Many compressors have enclosed seal areas which are vented to
the atmosphere from "high-point" vents for safety reasons. Compressors
are often housed in semi-enclosed or completely enclosed buildings. Many
handle gases which contain toxic or hazardous components such as hydrogen
sulfide. Venting the seal area to a high-point vent reduces the potential
for a buildup of toxic or explosive gases in the compressor area.
Sealant or lubricating oil is circulated through and around com-
pressor seal mechanisms. This oil is under pressure and will contain the
components of the compressed gas. The oil must be depressured and/or
treated to remove these gases. The vapor from the degassing of the seal
oil is generally vented to a blovdown/flare system.
Gases from the seal enclosures or seal oil degassing are some-
times drawn off by vacuum educators and sent to flare/blowdown systems.
Effectiven&ss of Compressor Seals—Table 7-52 shows a comparison
of seal leakage. The worst, the straight pass labyrinth, is given a gas
leakage index of 1.00. It is not clear from the table, which includes both
dry and lubricated seals, where the oil film seal fits in according to the
gas leakage index. The liquid film seal is shown, however, to lose more
lubricant than the lubricated mechanical contact seal by a factor of 55.
It is not clear if this refers to oil loss into the compressed gas stream
or if it refers to loss of oil (and dissolved gas) to the atmosphere.
The packed seal is the only seal available for a reciprocating
compressor application. The mechanical contact seal, wet or dry depending
upon design needs, would appear to rank the best among centrifugal com-
pressor seals for pressures up to about 500 psi. However, these vseals are
said to be fragile and prone to failure, as well as complex and difficult
to install correctly.
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TABLE 7-52. COMPRESSOR SEAL LEAKAGE
Compressor Seal
Dry Types Gas Leakage Index
Straight Pass Labyrinth 100
Staggered Labyrinth 56
Honeycomb Labyrinth 40
Restrictive Ring 20
Mechanical Contact (Running Dry) 2
Oil Types OilLoss
Mechanical Contact 0.03 gal/hr
63/i» in. Face Diameter
30 psi Differential
500 rpm
Lu b r icajit Lo s s
Liquid Film or Bushing 1.75 gal/hr or
5Vz in. Bore Diameter 55 times the
0.007 in. Clearance contact type
5000 rpm
60°F Oil Rise
Source: Reference 95.
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A more flexible device in terras of broad pressure range
application (to 5,000 psi) and suitability for dirty gas service is the
.liquid film seal. The complexity of its external circulation and control
system would be perhaps its most costly feature. Acid gas stripping from
circulating seal oil is a must with the use of liquid f.i 1m seals if the
working gas is sour. The oil reservoir degassing vent may be a source of
hydrocarbon emissions.
Seal Energy Requirementsand Cost—Compressor seal design is
traditionally an integral part of overall compressor design. As a result,
data are not available, to allow independent seal energy usage and cost
analysis.
Inspection an d Ma int e n am: e—Existing inspection and maintenance
procedures for compressors are similar to those described for pumps. Leak-
age may be more difficult to detect because some compressors have enclosed
seal areas that transport leakage to an elevated vent pipe. The effective-
ness of these procedures is reflected in the emission factors for com-
pressors shown in Section 5 of this report.
Available Controls for Compressors—Closed vent systems and leak
detection and repair programs are the available controls for compressors.
A closed vent system consists of piping and, if necessary, flow inducing
devices that transport compressor seal leakage to a control device. Con-
trol devices could include fired heaters or boilers, incinerators, flares,
or vapor recovery systems. For compressors with seal oil systems, the
closed vent system can be connected to the seal oil reservoir degassing
unit. For other compressor seals, the seal area itself could be enclosed
and connected to the closed vent system.
Leak detection and repair for compressors is similar to the
program described for pumps. A hydrocarbon detector can he used to detect
seal leaks. These areas would include the seal itself (if accessible),
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Lhe seal vent: pipe, and the seal oil reservoir vent depending on the
physical configuration of the compressor. No data are available to
quantify effectiveness of the leak detection and repair for compressors.
Effectiveness and cost would be dependent on the same factors discussed
for pumps. Average leak detection time required for compressors has been
estimated as 10 minutes per seal, and repair time has been estimated as 40
hours per seal.61 One major difference between repair of pump and compressor
seals is that most refinery pumps have spares, but many compressors do not.
Therefore,any repair that required compressor shutdown might also require
shutdown of the process unit. Depending on the type of process unit, the
unit shutdown could cause more emissions than allowing the compressor seal
to leak until repair can be effected during the next turnaround or shutdown.
Technology Transfer for Compressors—No other controls were
identified for compressor seal leakage. Sealless compressors are not
available in the capacity range that would be required in almost any
refinery application.
7.2.1.5 Agitators
Agitators may leak hydrocarbons at the junction of the vessel and
the rotating agitator shaft. The. agitator seal may be in liquid service if
the agitator is located at the side of a storage tank, or the seal may be
in vapor service if the agitator is located at the top of reactor vessels.
In some types of refinery operations, in-line blending has replaced the
use of agitated mixing vessels.
Existing Controls for Agitators—The four basic types of agitator
seals are listed in Table 7-53. Some of the seals are similar to pump seals
(packed and mechanical). The limitations of the four seal types are shown
in Table 7-53. No data are available to establish the magnitude of leakage
from agitator seals. The seals are listed in Table 7-53 in order of
increasing cost.
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TABLE 7-53. BASIC AGITATOR SEALS
Seal Type
Limitations
Comments
a. Hydraulic
b. Lip
c. Packing Gland
d. Mechanical Face
Low pressure and
temperature
2-3 psi;
unlubricated
150 psi
0 psia to 5,000 psia
if housed and
pressured to working
fluid pressure
Least-used agitator seal.
Dust or vapor seal only;
temperature limited by
elastomer lip melting point.
Six packing rings and lantern
ring required for 150 psi
capability.
Externally lubricated so as to
leak in if inboard seal fails
(double seal configuration).
Single seals also used.
Source: Reference 96.
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Available_Controls for Agitators—Leak detection and repair
strategies for agitators should be similar to those described for pumps
and compressors. The time required to detect leaks is probably about the
same as for pumps and compressors. The time requirements for repair are
not quantified.
7.2.1.6 Safety Relief Valves
Safety relief valves (SRV) are installed on any refinery equip-
ment that could be subjected to overpressuring with subsequent safety
hazards and equipment damage. The various types of SRV's in hydrocarbon
service are described in detail in Appendix E (Volume 4). Emissions to
the atmosphere occur through the valve seat due to improper seating, which
can be a result of wear, corrosion, or foreign matter.
Existing Control^ for Safety Rel_i_ef_ Valves—Inspection and main-
tenance is one existing control for SRV's. The main objective of most
inspection and maintenance programs is to make sure the SRV will provide
proper over-pressure protection. Some companies remove and test SRV's
after every over-pressure release.61 This procedure requires that a means
be provided to install a spare SRV while the other one is tested. Although
this testing is primarily to check the set pressure of the SRV, it may
also detect fugitive leakage. The other existing control for SRV's is
discharge header systems that transport over-pressure releases (and fugi-
tive leakage) to a flare.
Available Controls for Pressure Relief Devices—Leak detection
and repair programs and upstream rupture disks are the available controls
for SRV's, Leak detection would require periodic testing of SRV's that
discharge to the atmosphere. A hydrocarbon detector can be used to detect
hydrocarbon concentrations at the exit of the discharge "horn" or at the
weep hole at the bottom of the "horn." Repair of the SRV would probably
require removal of the SRV, and therefore a means of replacing the SRV
345
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while the process unit was operating would be needed. Data on costs and
effectiveness of leak detection and repair for SRV's are not available.
Although most SRV's are. used alone or in pressure-stepped com-
binations, some are used with rupture disks mounted under them (i.e.,
between the. process fluid and the SRV). Rupture disks (RD's) are somewhat
prone to age-induced fatigue or corrosion failure, and therefore are not
ordinarily used alone except where complete loss of process fluid is
acceptable economically and environmentally. Such acceptable cases
probably no longer exist in any organic chemicals or fuels manufacturing
facility.
Alternatively, rupture disks may be positioned downstream of SRV's
to protect working parts from weather or other corrosive atmosphere, as
when connected to a relief header.
Rupture disk leaks may be detected by "tell-tale" bubblers or
pressure gauges, and by excess flow valves connected to the inside piping
space between the RD and the SRV. This arrangement is covered by ASME
n "7
code. If small RD leaks are not monitored, there is a chance that the
pressure between the RD and SRV might build to system pressure. Then,
with a rapid rise in pressure, as in an emergency, working pressure would
almost double before the disk and SRV would release, depending upon the
rate of increase and size of the RD leak.
As long as the integrity of the rupture disk is maintained,
fugitive emissions are completely eliminated. The disk would require
replacement after over-pressure release, and therefore a means for replac-
ing it while the process unit was in service would be needed. Although
there is controversy within the industry concerning the use of rupture
disk-safety relief valve combinations, some feel that the combination may
Q 7
be operated safely. Others consider RD use upstream or downstream of
the SRV only as necessary for either (1) added isolation of particularly
346
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toxic materials from the air, or (2) as a means of isolating the SRV from
a corrosive atmosphere. This atmosphere might be, for example, a header
9 g
with sulfur compounds present, or simply salt air near the ocean.
Costs—The addition of an inlet or outlet side rupture disk to
an SRV adds between three percent and 50 percent to the materials cost of
the SRV, depending on size and service. Materials costs for SRV and RD
assemblies (excluding piping) are shown in Table 7-54. The net cost of
the system would take into account a value for the product saved by
eliminating fugitive emissions.
Technology Transfer for Pressure Relief Devices—Fugitive leakage
caused by improper reseating after over-pressure release may be minimized
by using pilot operated SRV'a with resilient (0-ring) seats. No data are
available to quantify the effectiveness of this type of control. Another
potential improvement in SRV design would be to install parallel SRV's
in all applications. This would allow an SRV to be in service with the
other blocked off as a spare. The SRV could then be removed for testing
and rupture disk replacement after over-pressure releases.
7.2.1.7 _S_ainp_ling Connections
Fugitive emissions from sampling connections are primarily due to
purging the sample line to obtain a representative sample. Atmospheric
exposure of the purged fluid can result, in evaporative hydrocarbon
emissions.
Exj-sting Controls for Samp 1 ing Connections—Existing practices
for obtaining process samples vary considerably. They may range from
draining process fluid onto the ground to collection of the purge in slop
oil systems. All existing practices result in some atmospheric exposure
and emissions, but the magnitude has not been quantified.
347
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TABLE 7-54. SAFETY RELIEF VALVE (SRV) AND RUPTURE
DISK (RD) ASSEMBLY COSTS
System
Inlet x
diameter
1 x
3 x
8 x
Basis :
May 1980 Dollars
Size, SRV RD Assembly
Outlet
, inches 150 psi flanges
2 650
4 1,050
10 5,900
300 psi flanges inlet Outlet
700 320 120
1,150 520 160
7,800 1,100 220a
Materials only; piping excluded. May, 1980 prices.
RD assembly includes cost, of safety head and one disk.
Interpolated from 4 inch and 12 inch diameter RD costs.
Source: Reference 99.
348
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Available Controls for Sampling Connections—Closed loop sampling
systems are the primary control available to reduce sample purge emissions.
A closed loop sampling system consists of a network of piping and valves
that either returns the purged material directly to the process, or that.
transports the purge to a closed collection system for recycle.
Technology Transfer for Sampling Connections—The main innova-
tions that are likely to reduce sample purge emissions are the increasing
availability of on-line continuous analytical instruments that do not
require discrete samples.
7.2.1.8 Wastewater Systems
Refinery wastewater systems have evolved over the years as
awareness of water pollution problems has grown, and as various treatment
systems have been developed. There are four basic treatment steps.100 The
first is primary separation, where oil is removed by gravity separation.
Normally, an API or a CPI-type separator is used. These separators
effectively remove free oil from water, but will not separate substances
10'
in solution or break up emulsions. * The second step is intermediate
separation where suspended solids and additional oil are removed by
chemical sedimentation or air flotation. Secondary treatment is the third
step. It involved the reduction of the biological oxygen demand (BOD)
with some type of biochemical oxidation. Finally, in the tertiary treat-
ment step, dissolved organics which will not degrade with biological
treatment methods arc removed. Carbon adsorption is the most common form
of tertiary treatment.
The treatment processes for these steps are shown below.102
• Primary—API Separators, Tilted-Plate Separators
(CPI.) , Filtration for Oil Removal, pH control,
and Stripping Processes.
349
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• Intermediate—Dissolved Air Flotation, Coagulation-
Precipitation, and Equalization.
• Secondary-Tertiary—Carbon Adsorption, Activated
Sludge, Aerated Lagoons, Trickling Filters,
Waste Stabilization Ponds, Cooling Tower Oxida-
tion, Chemical Oxidation, and Filtration.
In addition, there is a waste-water collection system which consists of
process drains, sewers, holding basin, and pumps.
Existing Controls for Wastewater Systems—Tab]e 7-55 gives an
estimate of the degree of adoption of various wastewater treatment pro-
cesses for 1950, 1963, 1967, 1972, and 1977. While this table utilizes
the. author's judgment, in many areas due to the "dearth of usable informa-
tion," the data on API separators are reliable and confirm that by 1977
nearly all refineries had an oil and water separator of the API or the
CPI type.103 The table also shows an increasing use of intermediate,
secondary and tertiary treatment methods. This trend is a result, in
part, of governmental scrutiny and control in the area of water pollution.
Covered oil/water separators and trapped drain systems are two
types of emission controls used in some refineries. Some state regulations
require covers for separators. As of January 1977, 80 percent of the U.S.
refining capacity was located in states where covers are required.10"* The
extent of application of trapped drain systems is not known. Because, of
the lack of emission data, effectiveness of those controls cannot be
assessed. Costs would vary widely, depending on site specific conditions.
The current AP-42 emission factors for drains and oil/water
separators, uncovered versus covered, imply a 95 percent fugitive hydro-
carbon emission reduction. The original data upon which the AP-42 emis-
sions are based are no longer available. Thus, the validity of the
350
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TABLE 7-55. DEGREE OF ADOPTION OF VARIOUS WASTEWATER
TREATMENT PROCESSES
Processes and Subprocesses
API Separators
Earthen Basin Separators
Evaporation
Air Flotation
Neutralization (Total Wastewater)
Chemical Coagulation and Precipitation
Activated Sludge
Aerated Lagoons
Trickling Filters
Oxidation Ponds
Activated Carbon
Ozonation
Ballast Water Treatment - Physical
Ballast Water Treatment - Chemical
Slop Oil - Vacuua Filtration
Slop Oil - Centrifugation
Slop Oil - Separation
Sour Water - Steam Stripping .
- Flue Gas Strippers
- Natural Gas
Sour Water - Air Oxidation
Sour Water - Vaporization
Sour Water - Incineration3
Neutralization of Spent Caustics
Flue Gas
Spent Acid (including
springing and stripping)
Oxidation
Incineration
Percent of Refineries Using the Processes
1950 1963 1967 1972 1977
40
60
0-1
0-1
0-1
1-5
0
0
1-2
10
0
0
9
1
0
0
100
60
0
1
35-40
20
15
0
25
50
50
0-1
10
0-1
1-5
5
5
7
25
0.5
1
9
1
5
2
93
70
3
1-2
40
30
25
3
40
60
40
1
15
0-1
5-10
10
10
10
25
0.5
1
8
2
7
3
90
85
3-5
1
50
35
30
5
50
70
30
1-2
18
0-1
10-15
40
25
10
25
3
3
5
5
12
10
80
90
7
0
30
20
25
5
20
80
20
2-5
20
0-1
10-15
55
30
10
20
5
5
5
5
15
15
70
90
10
0
20
20
20
5
15
Incineration includes flaring, boiler furnaces, and separate incinerators
uoed <:mly in conjunction with stripping and vaporization.
Source; Reference 103.
351
-------
.Indicated effectiveness cannot be assessed. In a laboratory study using
a simulated API separator, the covered separator provided 89 percent
emission reduction.
The data from Radian's oil-water separator emission measurements
are discussed in Appendix B (Volume 3). The results are poor and cannot be
used to develop emission factors for oil-water separators.
It is evident that further study of evaporative .losses from
oil-water separators is needed and justified. Actual emission rates for
uncovered separators probably fall between 13 and 200 lb/1,000 bbl refinery
feed. Similarly, average losses froir. covered separators can be expected
to be between .1.5 and 20 ]b/l ,000 bbl refinery feed.
Available Controls for the^Wasjie water System—In general, avail-
able controls for reducing fugitive emissions from existing process and
storm sewers and collection systems consist of minor modifications such
as sealing open sewer systems, altering pump bases, recurbing some process
areas, and improving housekeeping.
Changes which involve substantial capital outlays (or which may
be nearly infeasible from a construction standpoint), such as major
revisions to existing underground sewer systems or installation of vapor
recovery systems may not be practical. Techniques which can be used to
reduce emissions from the collection system are listed below.
• Open drains, sewers, or holding basins (which
regularly receive water containing significant
quantities of volatile organic compounds) up-
stream of the oil and water separator should be
eliminated where practical. These sources of
emissions in the U.S. refining industry are now
fairly rare. The evaporation of significant
352
-------
volumes of oil at current world scale prices is
a readily apparent financial burden. Process
drains and sewers should be covered or vented
through liquid seals wherever safe and practical.
• Pump bases which co not drain completely by
gravity should be altered. Many pump bases
are designed so that a slight level of oil
(from a leaking seal) must build up before the
base drains to the sewer. When new pumps are
to be installed, bases should be selected which
allow proper drainage. Existing pump bases
can be modified.
* Segregation of process water from storm water and
minimization of oily water volumes should be
practiced wherever practical. Curbing should
be installed so that only those areas which are
subject to oil spills drain into the oily water
sewer system. Storm sewers should be sized so that
overflow into process sewers during peak runoff is
avoided. in many cases, however, substantial revi-
sions to the sewer systems of older plants can be very
expensive.
• General housekeeping can be improved. An undefined
but, in some cases, significant source of emissions
is the lack of good housekeeping practices concern-
ing oil spills and leaks. A quantitative control
technique in the area of oil spills and leaks could
probably not be formulated, but an awareness of the
problem would be beneficial.
353
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Adequate data are not available for a definitive evaluation of
the effectiveness of covers on oil-water separators for reducing atmospheric
emissions. It seems reasonable to presume that covers will reduce, emissions
to some degree. The cost-effectiveness of this control option can only
be determined after its control efficiency has been defined through test-
ing. There can be safety and operational problems associated with cover-
ing the separators. These must be evaluated on an individual basis.
API separators can be covered by a number of methods including
floating pontoons or double-deck-type covers which are sealed against the
outer walls of each bay. A CPI separator normally has a fixed roof
1 C'f
cover.
Cost, of Controls—The cost of installing covers on API separators
can be substantial. The area of required coverage has been variously
estimated at 0.028 ft2 per bpd wastewater flow and at 0.050 ft2 per bpd
crude oil to the refinery. " ' These same sources have cited costs for
covers of $lA.40/ft2 (mid-1978) and $12.50/ft2 (mid-1977), respectively.
These costs can be escalated to current prices by using the M&S equipment
" f\ p
cost index reported in Chemical Engineering.' The current cost of covers
then becomes $15.8A/ft2 and $14.85/ft2, respectively. If a cost of
$16.00/ft2 and a cover size of 0.050 ft2/bpd crude oil charge are used,
the capital cost alone is $265,000 for covers for the 330,000 bpd hypo-
thetical refinery.
7.2.1.9 Cooling Towers
Hydrocarbons can be found at very low levels in nearly all water
used for refinery process cooling. If significant leaks occur in process
heat exchanges, the level of hydrocarbons present in the circulating
cooling water can increase substantially. Some of these hydrocarbons can
be vaporized and emitted to the atmosphere in the cooling tower.
354
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Existing Control Technology—Existing controls of hydrocarbon
emissions from cooling towers consist primarily of heat exchanger inspec-
tion and maintenance. These practices minimize the .leakage of hydrocarbons
into the cooling water. Monitoring for total organic carbon (TOC) in cool-
ing water is commonly practiced in refineries. This procedure detects
small increases in the hydrocarbon concentration and provides an early
indication of small leaks. These leaks can often be found and repaired
before they become large and while the air emissions are still small.
Emission factors determined, during this study were based on two
analytical methods: Total Organic Carbon (TOC) analysis and a purging
technique. These emission factors are shown in Table 7-56. The emission
factor for uncontrolled cooling tower emissions currently included In
AP-427 is 6 lb/106 gallon of circulating cooling water. In Radian's
study of cooling tower emissions, the purge method of analysis was found
to be much more precise than the TOC technique. Therefore, the emission
factor of O.li Ib. no nine thane hydrocarbons per 10s gallon cooling water
is recommended for controlled emission,
TABLE 7-56. RADIAN-GENERATED COOLING TOWER EMISSION FACTORS
Emission Factor,
Analytical Technique Ib HC/106 gal C.W.
TOC 12.4
Purge 0.11
Available Controls for CoolingTowers—The best control for cool-
ing towers is to minimize the amount of hydrocarbons entering the tower.
One method to achieve this goal is to eliminate the use of contaminated
process water as cooling tower make-up. This may be difficult, since
efforts to reduce water discharges may require the use of process water
355
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for cooling towers. Another control option is to monitor the hydrocarbon
content of the cooling tower input. If elevated concentrations are
detected, a leak in the process equipment is indicated. The problem then
is to identify the specific leak and to repair it.
7.2.1.10 Solid Waste Svstem Alternatives
Petroleum refineries generate numerous solid waste streams.
These streams may contain many substances, including volatile hydrocarbons.
Nonmethane hydrocarbons may be emitted to the air during disposal operations,
Most solid wastes are residuals from wastewater treatment. The
exceptions to this are some spent catalysts which are recovered in segre-
gated containers, spent acids and caustic, and other spills and sediments
which can be segregated. Normally these exceptions arc handled separately
from other solid wastes.
The five general categories of solid waste disposal alternatives
are landfarming, incineration (with landfilling of the ash), landfilling,
deep-well injection, solidification (producing relatively inert sub-
stances which chemically or physically isolate the pollutant), or surround-
ing the pollutant by encapsulation.109 Landfarming, incineration, and
landfilling, which are the most common methods of disposal for refinery
solid wastes, can create emissions to the atmosphere.
Existing Controls and Their Effectiveness—There are no specif-
ically recommended emission control technologies for application in land-
farming and landfilling. The disposal problems are individualized and
depend on the type of solid waste, the solids content, and the properties
of the earth at the disposal sites. In general, solid wastes in landfills
should be dewatered and/or contained if necessary, and covered with a
quantity of earth sufficient to minimize vapor loss and odor problems.
Landfarmed materials should be covered or plowed into the. earth
356
-------
as soon as possible after application. The solid waste loading capacity
of the particular disposal areas should not be exceeded.
A number of types of incineration systems, including multiple-
hearth and fluidized bed systems, are available to burn refinery sludges.
Control devices will generally be required to reduce particulate emissions
from incinerators. Effective part.ir.ulate controls are venturi scrubbers,
impingement scrubbers, bag filters and ESP's, but these devices are much
more expensive than scrubbers.
Landfarming and landfilling are economically attractive alter-
natives to incineration.
7.2.2 Control_of Stack and Other^Process Emissions
In general, the major sources of atmospheric process emissions
are sulfur recovery, fluid catalytic cracking catalyst regeneration, and
process heaters/boilers. Other sources include vacuum distillation, coking,
air blowing, chemical sweetening, acid treating, blowdown systems, and com-
pressor engine exhaust.
7.2.2.1 Sulfur Recovery
Any crude oil with more than 0.5 weight percent sulfur is
generally considered sour and its products are subjected to sulfur removal
processing.51 If not removed, the sulfur can cause corrosion, pollution,
and catalysis problems during refining or when the products are used as
fuel or as petrochemical feedstocks.
Sulfur removal from whole crude is not generally economical.
Various intermediate stock streams are, however, routinely subjected to
sulfur removal. The sulfur components in these streams are converted to
hydrogen sulfide by contact with hydrogen over a nickel-molybdenum catalyst
357
-------
at an elevated temperature. The resulting H2S may be removed from the
stream and concentrated by one of several means, the most common of which
is absorption.
At one time this H2S was simply burned with other light gases as
refinery fuel. In recent years, to minimize SO emissions and to produce
elemental sulfur for sale to other industries, the Glaus process has been
used. The tail gas from a Glaus un.lt is the main source of SO. emissions
in a refinery today; it contains H2S, S02, CS2) COS, S , and also CO formed
from small amounts of hydrocarbons and C02 in the feed stream.
The Glaus Process—Because of its economic advantages, a Glaus
unit for the conversion of H2S to elemental sulfur is often considered as
simply part of normal refining operations. However, because the process
by itself is not totally efficient in producing elemental sulfur, the tail
gas from the unit can be a major source of emissions. But it must be
recognized as a very effective control device.
The Glaus process works best, for gas streams containing greater
than 20 volume percent II2S and less than 5 volume percent hydrocarbons.
There are several flow schemes available according to the H2S content of
the feed stream to the unit. In any case, the overall Glaus reaction is
as follows:
H2S + -^ 02 - - S + H20
2 n n
where n represents the various molecular forms of sulfur vapor.
GS2 and COS are produced in side reactions, and usually pass
unchanged to the tail gas. They can account for 0.25 to 2.5 percent of
the sulfur content of the tail gas. " However, with proper design,
358
-------
including the use of the cobalt molybdenum catalyst and a higher inlet
temperature in the first reactor, the CS2 and the COS concentrations in
1 1 o
the tail gas can be minimized.
A Glaus unit with one catalytic reactor can convert 80 to 86
percent of the H2S to elemental sulfur.51'113 This efficiency can be greatly
enhanced by repeating the catalylic stage one or more times. Conversion
is ultimately limited by the reverse reaction. Recovery rates for various
feed compositions are given in Table 7-57.
These efficiencies, once considered sufficient, do not meet new
regulations. Further treatment of the Glaus unit tail gas is required.
Glaus plant costs are sensitive to the flow rate and composition
of the input stream as well as the sulfur removal efficiency. It Is diffi-
cult to generalize the costs. As an example, however, the capital Invest-
ment costs for a Glaus plant having a capacity of 250 x 106 ft3/day of gas
are $14 x 106 (construction period is 4th quarter 1979 through 4th quarter
1980). This plant has a sulfur removal efficiency of about 95 percent.
Existing Contro1_ Technology for Sulfur Recovery—The tail gas
from the Glaus unit is often incinerated before it passes to the atmosphere.
Some tail gas treating processes require that the tail gas be incinerated
prior to treatment.
More than 70 methods have been proposed for treatment of the
ClaviK unit tail gas.11"* These methods may be continuations of the Glaus
reaction or add-on processes with chemistry quite different from that of
the Glaus reaction. The six tail gas clean-up methods listed in Table
7-58 are those considered the most viable at present in light of energy
demands, economics, and effectiveness. Amoco's CBA Process, the Sulfrccn
Process, and the IFF Process are continuations of the Glaus reaction under
359
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TABLE 7-57. TYPICAL COMPOSITIONS OF FEED STREAM AND
TAIL GAS FOR A 94 PERCENT EFFICIENT
GLAUS UNIT
Component
h
H2S
S02
Sa vapor
SB aerosol
COS
CSZ
CO
CO 2
02
N2
H2
H20
H.C.
Temperature, °F
Pressure, psig
Total Gas Volume
Sour Gas Feed
Volume %
89.9
0.0
0.0
0.0
0.0
0.0
0.0
4.6
0.0
0.0
0.0
5.5
0.0
100.0
104
6.6
—
Glaus Tail Gas
Volume I
0.85
0.42b
0.10 as Si
0.30 as SL
0.05
0.05
0.22
2.37
0.00
61.04
1.60
33.00
0.00
100.00
284
1.5
3.0 x feed
gas volume
Gas volumes compared at standard conditions.
NSPS requires an emission of less than 250 ppmv (0.025%) S02, zero percent
02, dry basis if Glaus Unit Tail Gas is oxidized as the last control step,
or, 300 ppmv S02 equivalent reduced compounds (H2S, COS, CS2) and only
10 ppm HZS as S02, zero percent Oz, dry basis, if the Tail Gas is reduced
as the last control step.
Source: Reference 48.
360
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TABLE 7-58. EXISTING METHODS FOR REMOVAL OF SULFUR FROM GLAUS TAIL GAS
Name
CBA
Sulfreen
IFP-1500
BSRP
SCOT
Wellman-
Lord
Developer
Amoco
SNPA/Lurgi
Ins ti Cut
Francals
du Petrole
Ralph M. Parsons
& Union Oil Co.
of California
Shell
Wellman Power
Gas
Final Tail Gas
Description S Concentration
Claus reaction continued
at low temperature; re-
moval of condensed sul- 1500 ppmv S
fur drives reaction.
Bed regenerated with hot
gas from Claus unit.
Claus reaction continued
at low temperature as in
CBA. Bed regenerated with 1500-2000 ppm S
hot nitrogen.
Claus reaction occurs In 1000-2000 ppm S
a solvent.
All sulfur compounds re- 250 ppm S
duccd to HjS which is Or less
processed in a Stretford
unit.
All sulfur compounds re- 200-500 ppmv HiS
duced to HzS which Is
recycled to Glaus
SO? in incinerator gas <200 ppmv SOj
contacted with HajS03 to
Coit
Product (Z Cost of Clau«)
S. 50-150*
t
S. 50-150Z
So variable
S. 100Z
Feed 75-100Z
to
Claus
NazSOs/NajSOj 130-1501
crystals
form NallSOj. NazSOs regen-
erated in evaporator/
crystallizer.
-------
more favorable conditions, while the Beavon Process, the SCOT Process, and
the Wellman-Lord Process are add-on units with higher efficiencies than the
first three.
Additional tail gas treatment methods are described in detail in
Appendix E (Volume 4).
Alternate Tail-Gas Treatment Methods—An alternate to the Glaus
unit and a modification of the unit are also being tested. The alternate,
the UOP Sulfox Process, would produce no objectionable tail gas stream.
The Mineral and Chemical Resource Company (MCRC) ''is a modified improve-
ment of the Glaus process.
The UOP Sulfox Process '-—The UOP Sulfox process is an alterna-
tive to the Claus process. In this process, aqueous ammonia, instead of
an amine solution, is used to scrub H2S from refinery streams. Ammonia
is then scrubbed from the gas with purified water.
Hydrogen sulfide content, in the treated gas is 10 to 100 ppm. It
is possible, at increased cost, to design a Sulfox unit which can achieve
1 ppm H2S in the tail gas. However, NSPS requires less than 250 ppmv S02
from a final oxidizing step, which in this case would probably be inter-
preted as "S02 or its equivalent as reduced sulfur compounds."
It may be possible to convert an existing Claus system to a
Sulfox System with a minimum of expense. It is probable that the existing
amine absorber could be used as the ammonia absorber and that the existing
amine stripper could be. used in the Sulfox unit proper.
Cost of a Sulfox system is considered about equal to that of a
Claus unit, not including the. cost of tail-gas cleaning. Utility costs
are estimated to be about 60 percent of those of a Claus unit.
362
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The Mineral and Chemical Resource Company (MCRC)'[ --Tine MCRC
Sulfur Recovery process is actually a modified improvement of the Claus
process. A proprietary scrubber is used to improve sulfur recovery and
also to remove any ammonium sulfate which forms in a Glaus unit if the
feed contains ammonia. A 98 percent sulfur recovery efficiency can be
obtained with a three converter design; greater than 99 percent efficiency
can be obtained with four converters. Two MCRC sulfur recovery plants
have been operating since 1976.
Control Technology for S u 1 f u r Re cove r y in Other Indus tries—Some
FGD processes developed by the electric utility industry may be applicable
to the flue gas from a Claus incinerator. These processes are summarized
in Table 7-59.
7.2.2.2 Cat alys t Regoneration
Catalysts are used in several petroleum refining operations,
namely, fluid catalytic cracking (FCC), moving bed catalytic cracking
(TCC), catalytic hydrocracking, reforming, and various oil desulfuriza-
tions. These catalysts become coated with carbon and metals and must be
regenerated to restore their activity. During regeneration, the carbon
is oxidized to CO and C02. Hydrocarbons may be Incompletely burned.
In most applications, a catalyst must be regenerated only a few
times a year. Emissions during these episodes may include, catalyst fumes,
oil mist, hydrocarbons, ammonia, SO,, chlorides, cyanides, NO , CO, and
aerosols. Though there may be significant emissions during the regenera-
tion of some of these catalysts, the total emissions over the course of a
year are probably not significant.
Catalytic cracking catalyst regeneration is a continuous process.
Uncontrolled cracking catalyst regeneration can be a major source of air
363
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TABLE 7-59. FLUE GAS DESULFURIZATION PROCESS
Kane
The r o ugr.br e d
101 Process
Developer
Chiy:>d.u Choir,. F.ng .
and Construction
Description
Tr.il gas incinccrstion
followed by Absorption
Number of
Commercial
Units
9
Efficiency
of SO 2 Removal
or S02
Concentration
in flue gas
oOCpprav SO 2
Approximate
Cost ,
% Coat o£
Product Claus Unit
Gypsum
Citrate Process
Townsend Process
Lurgi-Clans-Abgas-
(LUCAS)
Takahak Process
Company, Ltd.
U.S. Bureau of Mines
P.M. Townsend
Lurgi
of SO2 in dilute sxilfuric
acid.
Absorption of S02 in aqueous Xone
sodium cl.rrf.tc solution.
Absorber liquor is
regenerated with H2S
Claus reaction t.-iucs placp. Mone
in an organic solvent, such
as mcthylcnc p;ylcol, at an
elevated temperature.
Incineration + hot coke to One
convert sulfur compounds to
SO2. SO 2 racicved with
aqueous alkali phosphate
solutior. which is regenerable.
Tail gas contacted with
sodium carbonate and
redox catalyst.
95-99%
99%
(<2CO?T>r. SOZ,
<150pp.T.' COS/CSj)
99.9%
250
75-30
-------
pollution in a petroleum refinery. ?lue gases from catalytic cracker
regenerators contain participates, SO. , carbon monoxide, hydrocarbons,
)\
NO , aldehydes and ammonia,
x
Existing Control Technology for Catalyst Regeneration—The
existing method for controlling CO emissions from catalyst regeneration
in catalytic cracking units is combustion in CO boilers. The CO in the
regenerator flue gas is burned to C02, and the heat is recovered as steam
in a waste heat boiler. Particulate emissions can be controlled by
cyclones followed by either electrostatic precipitators or scrubbers.
The effectiveness of combined CO combustion and particulate
removal in controlling emissions from catalyst regeneration are presented
in Section 7.1. The amount of CO is reduced, of course. However, another
noticeable result is the substantial reduction in emissions of hydrocarbons,
ammonia, and aldehydes. The exiting flue gas temperature is much lower
after passing through the CO boiler.
Control Technology in_Other Industries for Cat aly stReg ene r a t i on—
Several FGD methods used by the utility industry have been proposed for use
on FCC regenerators.117 They are discussed below. In addition, some of the
regenerable processes discussed in this section for treatment of the Claus
unit tail gas may also be applicable. One of the processes described
below simultaneously removes SO and particulates from the flue gas.
The Lime/Limestone FGDJProcess11--L.ime or limestone FGD processes
are the most widely used FGD systems. The systems are very similar; they
consume large quantities of feed material and produce large quantities of
waste sludge, but have relatively low operating costs and are highly
reliable. An SOZ removal efficiency of greater than 90 percent has been
demonstrated.
365
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A major design option is the choice of lime or limestone.
Limestone is less expensive than lime, but it is not used as efficiently
by the process; therefore, there is more feed material consumption and more
waste sludge production. Procedures which improve limestone utilization
also increase capital and operating costs.
Lime systems are usually more expensive to operate, however,
because of the high cost of lime. Lime systems may be preferred where
space is limited for feed material processing and/or waste sludge disposal.
Capital and utility costs are also lower for a lime system. The choice
between lime and limestone is also influenced by the availability of raw
materials.
Costs of raw materials and utilities for lime/limestone systems
are generally lower than for regenerable processes, although more raw
materials are required. Annual operating costs of a lime system are
about seven percent higher than those of a limestone system.
The Dual Alkali FGD Process1l--The dual alkali (or double alkali)
FGD process can be used to overcome the scaling problem inherent in lime/
limestone FGD systems, while retaining the convenience of solid waste
disposal. There are 53 operating dual alkali systems in the United States
and Japan; several more are under construction.
These systems can achieve S02 removal efficiencies of greater
than 90 percent. The. capability for more than 99 percent removal of S02
has been demonstrated. The dual alkali process itself is capable of
greater than 98 percent particle removal.
Absorption of S02 from the flue gas takes place in a tray tower,
or a venturi scrubber if simultaneous particle removal is desired. The
S02 in the flue gas reacts primarily with sodium sulfite (Na2S03) to form
sodium bisulfite (NaHS03). Some sulfite and bisulfite oxidize to sulfate.
366
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The desulfurized flue gas is reheated if necessary and released to a stack.
A bleed stream of the scrubbing liquor is withdrawn continuously from the
absorber and regenerated.
Loss of soluble sodium and nonsulfur calcium salts can create
water pollution problems and also a loss of raw materials. Therefore,
water can be added to the system only to replace that lost through evapor-
ation or in the. solid waste product. Also, retention of soluble salts by
the solid waste must be minimized.
Sludge from the dual alkali process must be fixed chemically to
decrease its permeability and leachability, or it must be disposed of in
well-designed lined ponds. The thixotropic nature of the calcium sulfite
may make land reclamation difficult. A larger disposal area will be
required then for a lime/limestone system.
Dual alkali systems are economically competitive with lime/
limestone systems.
7.2.2.3 B£ilers__and_ Process Heaters12 °
Most refineries use steam boilers to provide steam for direct
use in various processes, for heating and for driving steam turbines.
Process heaters are used extensively in refining operations. They are the
largest combustion source of hydrocarbons in a refinery. Refinery boilers
and heaters are fired with most available fuel.
Control Technology for Heaters and Eoilers—Emissions
from boilers and process heaters depend on the operating parameters of the
unit and the fuel burned. Emission factors for burning natural gas and
residual fuel oil are given in Section 7.1.
367
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In addition to the combustion emissions, there are also emissions
associated with the decoking of the heaters. At intervals of about six
months to three years, each heater must be flushed with a steam-air mixture
to remove interior coke deposits. Emissions are similar to those from
decoking the delayed coking unit, but they are smaller and more infrequent.
Control TechnologiesAvailablein Refineries for Heaters and
Boilers—Emissions of SO from boilers and process heaters can be minimized
by routing the flue gas to an integrated sulfur removal facility such as
Lhe IFP-150 and the Aquaclaus. However, there are substantial problems to
this approach. This is discussed further in Appendix E (Volume 4).
NO Removal—NO emissions can be reduced by several tail-gas
X X
cleaning methods, but this is inherently more difficult than controlling
NO by combustion modification techniques. The principal difficulties are
X
the large amount of hot gas to be handled, the dilute concentration of NO
X
interferences by other pollutants and the high power consumption. Three
methods for removal of NO from stack gases are gas scrubbing, catalytic
reduction and thermal reduction with added ammonia. Because of economic
considerations, only thermal reduction with added ammonia appears promising.
This process is more expensive than combustion modifications but can
supplement these modifications when stricter control of NO is required.
As with SO controls, substantial problems associated with flue
gas collection exist in refineries.
Con fro 1 Technology Avaj 1 abj.e_in_ Other Industries for Heaters and
Boilers—Processes described previously in Section 7.2.2.2 for control of
S02 emissions from FCCU regenerators may also be applicable to the flue
gases from boilers and process heaters. Another process, the Shell Flue
Gas Uesulfurization process (SFGD) can be used to simultaneously remove
SO and NO. from process heater flue gas, fluid catalytic cracking regenera-
XX
tion, and Glaus units. However, these flue gases would have to be
368
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collected and sent to one or two SFGD units. There are serious safety and
economic obstacles to such a collection system.
The SFGD process has demonstrated S02 and NO removal efficiencies
X
of greater than 90 percent. The efficiency of the system is not affected
by variations in the S02 or NO concentration. The primary product, of the
X
process is S02, which may be. sold, processed into elemental sulfur or
sulfuric acid, or routed to the front of the Glaus unit. The primary waste
from the process is water generated during the recycle step. It generally
contains 30 to 50 ppm dissolved S02. The SFGD process requires approxi-
mately two moles of hydrogen per mole of SO-2 removed and one mole of
ammonia per mole of NO removed. A heat credit may be realized by the
X
process. Actual costs for an integrated SFGD system are not available.
because such a system has not yet been built at a U.S. installation. Due
to the complexity of the process, space requirements are expected to be
high. Retrofit application of the SFGD process might be difficult because
of the duct work required.
7.2.2.4 Vacuum Gistiliation
Certain control methods can virtually eliminate the process
emissions from vacuum distillation. Emissions of noncondensable vapors
are controlled by venting into a blowdown system or by incineration. The
vapors may be used as supplemental fuel in process heaters and boilers.
Oi]y condensate emissions can be eliminated by the use of mechanical
vacuum pumps or surface condensers which discharge to a closed drainage
system. Both noncondensable and condensable emissions can be minimized
by the installation of a lean-oil absorption unit between the vacuum tower
and the first stage vacuum jet.
369
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7.2.2.5 Coking
There are two accepted methods for coking: f]uid coking and
delayed coking. Delayed coking is the more widely used method.
In the delayed coking process, the feed stream is heated and
transferred to a coke drum which provides the proper residence time,
pressure, and temperature for coking. When the coke drum has been filled
to capacity, the coke is cut from the walls with high-pressure water;
hydrocarbons and particulates are emitted when coke is removed.
Particulate emissions from the delayed coking process can be
minimized by wetting down the coke during the removal procedure. Hydro-
carbon emissions can be minimized by venting the quenching steam to a
vapor recovery or blowdown system. Once the drum has cooled to 212°F,
the steam purge can be replaced by a water flood. Further cooling will
minimize steam and hydrocarbon vaporization when the drum is opened.
Fluid coking is a continuous process in which the feed is
injected into a fluidized bed of hot coke particles. Approximately 30
pounds of carbon monoxide and about 520 pounds of particulates per 1,000
barrels of feed are emitted from an uncontrolled fluid coking unit.7'121
There arc often additional pollutants from coke combustion. Emissions
can be controlled by the use of a scrubber or electrostatic precipitator
and a CO boiler (either a separate one or the boiler which serves the
catalytic cracking unit).
Significant particulate emissions often occur during the loading
of coke into rail cars or trucks. An induced draft particulate control
system using bag filters could reduce these, emissions, but would be expen-
sive to design, install, and maintain. A more reasonable approach is to
spray the coke with a small amount of heavy crude oil or coker gas oil as
it leaves the coker.
370
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7.2.2.6 Air Blowing
Blowing air through a material may serve to oxidize, remove
moisture, strip spent chemicals or mix the material. The amount of emis-
sions produced by air blowing depends on the amount of air used per ton
of charge, the volatility of the charge, and the temperature of the
operation. In all of its uses, uncontrolled air blowing produces noxious
odors.
Air is sometimes blown through asphalt to oxidize it and there-
fore increase its melting temperature and its hardness. Emissions from
asphalt blowing are lessened by the fact that asphalt material is distilled
at high temperatures before it is subjected to asphalt blowing. Available
data indicate uncontrolled emissions from asphalt blowing to be 40 to 80
7 0
pounds of hydrocarbons per ton of asphalt treated.
Emissions from asphalt blowing can be reduced by vapor scrubbing,
incineration, or a combination of both. Vapor scrubbers condense steam,
aerosols, and essentially all of the hydrocarbon vapors. Incineration may
be accomplished in process heaters, boilers, or flares. Hydrocarbon
1 22
emissions from a controlled asphalt-blowing unit are negligible.
Air blowing of gas oil products to remove moisture takes place
in a packed tower or vessel. The exhausted air does contain some lighter
hydrocarbon components of the gas oil.
In many refineries, air-blown brightening units have been replaced
d vessels containing solid adsorbei
potential for process hydrocarbon emissions.
with packed vessels containing solid adsorbents.'" These units have slight
371
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7.2.2.7 Chcmica1 Swect en ing
Chemical sweetening rids hydrocarbons of odorous mercaptans.
Only low-sulfur (sweet) materials are subjected to this treatment; more
drastic sulfur removal methods such as hydrodesulfurization are used for
high sulfur (sour) materials.
In extractive sweetening, an aqueous NaOH or K.OH solution
extracts the sulfur. Before disposal, hydrocarbons are removed from the
aqueous solution by inert-gas stripping, which may be a source of hydro-
carbon emissions.
Catalysts are used to promote oxidative sweetening. Air is the
oxidizing agent and is also used to regenerate the catalyst. Hydrocarbon
emissions may result from both the oxidation and the. regeneration steps.
Emissions from the inert gas stripping of spent caustic can be
prevented by venting the gases to a flare or a furnace firebox.
Emissions from air blowing regeneration of spent oxidative
sweetening solutions can be reduced by steam-stripping the spent solutions
to recover hydrocarbons before air-blowing. The gaseouvs effluent from air
blowing can then be incinerated to dispose of residual hydrocarbons.
7.2.2.8 AcidTreating
Hydrocarbon streams may be treated with acid to remove or dis-
solve undesirable materials. The use of sulfuric acid results in a
hydrocarbon/acid sludge which is removed by clay filtration. To recover
the acid, the sludge may be incinerated and the resultant S02 used to
produce more sulfuric acid. Alternatively the hydrolysis-concentration
process may be used; hot gases from the combustion of oil or gas are
372
-------
bubbled through the sludge to volatilize the hydrocarbon diluent and to
concentrate the acid. Off-gases pass through a mist eliminator to the
atmosphere. These gases may contain hydrocarbons and S02.
If the acid concentration process is used, the off-gases from
the mist eliminator can be vented to caustic scrubbers for S02 and odorant
removal, and then to an incinerator or a flare.
Hydrocarbons escaping from acid recovery operations can be
eliminated by using acid regeneration. Regeneration involves sludge
incineration to produce S02, which can be converted to H2SOz.. Control
methods are available for control of S02 emissions from acid sludge
incineration.
7.2.2.9 Slowdown Systems
All units and equipment subject to shutdowns, upsets, emergency
venting, or purging are manifolded into a multi-pressure collection system.
Because the blowdown system receives materials from all processing units
within the plant, any volatile material found in any process stream may
be emitted frotn an uncontrolled blowdown system. It is estimated that 580
pounds of hydrocarbons per 1,000 barrels of refinery feed are emitted from
an uncontrolled blowdown system.
Blowdown emissions can be effectively controlled by venting into
an integrated vapor-liquid recovery system. A series of flash drums and
condensers arranged in descending operating pressures separate the blowdown
into vapor pressure cuts. The liquid cuts are recycled to the refinery;
the gaseous cuts are recycled or flared.
Emissions from a controlled blowdown system have been estimated
to be 0.8 Ib per 1,000 barrels of refinery feed, compared to 580 Ib per
373
-------
1,000 barrels for uncontrolled. The control is estimated to be 99.9
percent effective.
7.2.2.10 Co mp res s o r E ng i ne s
Reciprocating and gas turbine engines fired with natural gas or
refinery fuel gas are often used in older refineries to run high-pressure
compressors. Their use is expected to dec.line.120
The exhaust emissions from these engines include carbon monoxide,
hydrocarbons, nitrogen oxides, aldehydes, and depending on the sulfur con-
tent of the fuel, sulfur compounds. Emission factors for reciprocating and
gas turbine compressor engines fired with natural gas are given in Table
7-60. Particulate values were not available.
No pollution control devices for refinery compressor engines are
in current use. Combustion modification is discussed in the following
section.
7.2.3 Emission Reduction Through Process Modifi cation
A reduction in emissions can sometimes be achieved as a result of
process modifications made in the refinery. Changes in operating practices,
the use of alternate fuels, and the hydroprocessn'ng of refinery feedstocks
can result in net reductions in emissions.
7.2.3.1 A1_Le_rnatiye_ Operating ^Practices and Conditions
£„,.,,,. „ , 123 1 2 it 125 126 127
Regeneration of Catalytic Cracking Catalysts » ' ' '
Older FCC regenerators were designed for operation at temperatures up to
1150°F; the introduction of newer, more coke-sensitive catalysts necessi-
tated higher temperatures. By 1976, 30 percent of all FCC regenerators
were operating at 1300°F. High-temperature conversion of CO to C02
374
-------
TABLE 7-60. EMISSION FACTORS FOR RECIPROCATING AND GAS TURBINE
COMPRESSOR FUELED WITH NATURAL CAS
Engine Type
Reciprocating
Gas Turbine
NOX as N02a
3.4
0.3
Pollutant,
CO
0.43
0.12
lb/10s ft3 gas
HC as cb
1.4
0.02
burned
SOX as S02C
2S
2S
At rated load. In general, NO emissions increase with increasing load and
intake air temperature. They generally decrease with increasing air-fuel
ratios and absolute humidity.
Overall less than one percent by weight is methane.
cS=Refinery gas sulfur content (lb/1000 SCF): factors based on 100% combus-
tion of
Source: Reference 1 27.
-------
generally occurs at 1,400 to 1,500°F. With high-temperature regeneration,
the CO level in the exit gas from the regenerator can be reduced to well
below 500 ppm. Thus, a CO boiler is no longer necessary for CO emission
control.
Complete combustion of CO within the regenerator offers other
emissions benefits in addition to reducing CO to less than 500 ppni: for
example, elimination of the need for CO boiler reduces other emissions
since auxiliary fuel burning is not required and NO -producing CO boiler
X
temperatures are avoided. Recovery of additional heat in the regenerator
reduces (and in some cases eliminates) the need for a FCC preheater and
its associated emissions.
Several new catalysts, or promoters, have been introduced in the
last several years to promote the combustion of CO to C02. A promoter may
be chosen to promote complete combustion or partial combustion where
metallurgy cannot withstand the higher temperatures.
Tn 1975, the cost of converting a relatively modern FCCU with
stainless steel cyclones to high-temperature regeneration was 350,000 to
$300,000. Cost of a CO boiler for the unit was perhaps S2 million to $3
million.
Other FCC operations which affect regenerator emissions are the
amount of recycle and the stripping steam rate. Higher recycle rates
produce more flue gas, but the net effect is negligible when compared to
the impact of recycle on yields and operating costs. Similarly, insuffi-
cient stripping steam allows hydrocarbons to enter the regenerator to pro-
duce more flue gas and possible unstable operation. In this case, the
impact of stripping steam rate on the entire unit's performance provides
incentives for the reduction of emissions.
376
-------
SO Removal in_ the FCC Regenerators18 >11--Amoco has developed a
catalyst wh.ich reduces the amount of sulfur leaving the regenerator as S02 ,
The catalyst holds the sulfur until it is returned to the reactor, where.
it is released and converted to K2S. The H2S leaves the reactor with the
cracked product and is later converted to sulfur in the Glaus plant; the
regenerated catalyst returns to the regenerator.
Cost for the 60 to 75 percent reduction in SO emissions with
X
this method in a new facility is estimated at 3c/bbl, compared to 22c to
24c/bbl for stack-gas scrubbing and up to 27c/bbl for feed hydrosulfuriza-
tion. The use of the catalyst for SO control is also less expensive than
other methods of retrofit applications.
Combustion Modification for Control of NO > ' > ;—In combus-
tion sources, KO may be produced either by the fixation of atmospheric
nitrogen in the flame (thermal NOX) or by the oxidation of a portion of
the nitrogen in the fuel (fuel NO ). N02 from combustion sources is pro-
duced as the NO combines with oxygen in the atmosphere.
Boi_le_rs_1_ Furnaces, and Process Heaters—Combustion modifications
for N0x control on boilers, furnaces, and process heaters are of three
general types: lowering the flame temperature, limiting the amount of
excess air, and limiting the residence time within the flame. Control of
N0x is often counter to a high thermal efficiency and contributes to the
emission of other undesirable substances. As a result, compromises must
often be made.
A number of specific combustion modifications for NO control
have been devised. The effectiveness of some of the individual methods
and some combinations at different boiler loads are shown in Table 7-61.
Internal Combustion Engines—There are several modifications for
controlling NO emissions from internal combustion engines. The percent
X
377
-------
TABLE 7-61. REDUCTIONS OF NOX EMISSIONS WITH COMBUSTION MODIFICATIONS AT
VARIOUS BOILER LOADS
OJ
•^j
oo
PERCENT REDUCTION IB NO^ EMISSIOHS WITH
Conbuatlon
Modification
Lov Exceaa Air Staging
(Percent
Full
Fired
Csi
Oil
Full Load) 85/105 60/85 50/60 85/105 60/85
Burner
Arrangement
Front Wall 13 24 7 37 30
Horizontally
Opposed 17 15 32 54 35
Tangential -
Average IS 19 26 45 31
Front vail 27 20 2B 29 20
Horizontally
Opposed 10 E6 12 34 34
Tangential 28 22 - - 17
Average 19 19 18 30 . 22
Loo Exeeta Air Flue Gas Possible* Combined
and Staging Reclrculatlon Hodlf icatlona
50/60 85/105 60/85 50/60 85/105 60/85 50/60 85/105 60/85 50/60
30 4B (2 3S 43 42 35
59 61 48 68 - 20 73 52 72
- - 60 - 66 65
52 54 44 52 - 60 20 64 51 60
20 39 32 21 4ft 31 - 50 SI 21
47 35 44 42 - - 38 35 55
- - 45 - 10 13 59 -
34 38 37 37 28 23 - 47 41 38
•Possible combination of nod If lection* on the boiler* tetted.
Source: Reference 46.
-------
NO reduction and the limitations for each of these modifications are given
in Table 7-62. These methods are described in more detail in Appendix E
(Volume 4).
7.2.3.2 Alternative Fuels 7
Refiners traditionally have had a choice of natural gas, refinery
gas, or distillate or residual fuel oils as- fuel for refinery boilers and
process heaters. The present trend is toward Lhe heavier oils, both for
economic reasons and because lighter oils are being reserved for smaller
consumers with fewer emissions controls. This trend, however, results in
higher emissions from refinery boilers and heaters.
Emissions factors for the use of natural gas and fuel oils in
industrial boilers have been presented previously in Section 7.1. Accord-
ing to these factors, particulate emissions from natural gas and No. 2 oil
are independent of sulfur content, but increased with sulfur content for
No. 4 oil and heavier oil. Sulfur dioxide emissions are, of course,
directly related to sulfur content of the fuel gas or oil.
Table 7-63 presents comparative emissions Tor natural gas and
fuel oils for Id6 Btu heat release. The AP-42-based "average" natural
gas contains only about 22 percent of the sulfur equivalent allowed by
NSPS (0.10 grain/10 ft3 gas) (Column 1). Fuel oils containing 0.3 to 2.0
weight percent sulfur, which represent the broad range of sulfur levels
in fuels, emit from 500 to 3,600 times as much SO as the "average" natural
gas.
Overall, the substitution of fuel oils for natural gas without
instituting additional controls will have a detrimental impact on the
envi ronment.
379
-------
TABLE 7-62. ENGINE MODIFICATIONS WHICH REDUCE NOX EMISSIONS EKOM INTERNAL
COMBUSTION ENGINES
CO
o
DIESELS SPARK IGNITION
ENGINE
MODIFICATION
Combustion chamber
design
Fuel propertied
Air/fuel ratio
Exhaust recycle
Fuel injection
timing
Stenm or wnter
injection
Variable compression
ratio
NOx NOX
REDUCTION PENALTIES i REDUCTION
(Percent) LIMITATIONS (Percent)
40 Increased first -
cost
Variable Availability of Variable
low nitrogen
fuels; higher
operating cost
Not applicable 30
50 Increased fuel; 50
decreased power
40 Increased fuel;
decreased power
50 Corrosion ' 50
problems
Under development -
PENALTIES (,
LIMITATIONS
Not applicable
Availability of
low nitrogen fuels;
higher operating
costs
Backfiring; reduced
power
Increased fuel;
decreased power
Not applicable
Corrosion
problems
Not applicable
CAS TURBINES
NOX
REDUCTION PENALTIES &
(Percent) LIMITATIONS
Under development
Variable Availability o£
low nitrogen fuels;
higher operating
costs
50 Increased fuel;
decreased power
Under development
- Not applicable
71 Need delonlzed
water; costly
- Not npplicable
Source: Reference 45.
-------
TABLE 7-63. REFINERY FUEL EMISSIONS AT EQUIVALENT
HEAT RELEASE
Fuel Type
Natural Gas'
#2 F.O.
#6 F.O.
Gross Heating Value
Specific Gravity
Amount Equivalent to
IO6 Btu heat release
Emissions Ib per
Btu:
S02: NSPS
S0?: (av)
Particulat
CO
HC
NO (av)
1
Sulfur Wt% I
(oils only)|
1012 Btu/ft3°
0.55/Air
988 ft3
19,460 Btu/lb'
0.856/water
7.20 gal
Reference 7.
Accepted value for pure methane.
0.1 gr H2S
18,200 Btu/lb'
0.972/watera
6.78 gal
2.66 x 10 d
5.9 x IQ~^
(av) 9.9 x IO"3
1.68 x 10~3
3.0 x 1Q~3
0.17
0.306
0.014
0.036
7.2 x ].0~3
0.16
0,3
(typical)
2.13
0.16
0.034
6.8 x io~3
0.41
2.0 ,
(high)
emission limit of SO2 =
x 64 Ib S02 1 Ib
10 ft3 nat. gas 34 Ib H2S~ X 7000 gr
= 2.69 x 10
Ib S02
ft3 nat. gas
Tlesidual fuel oil sulfur levels range from 0.3 Wt. percent (N.Y. City)
to 2.0 percent (Midwest) according to sales data as regularly published
iu Oil and Gas Journal
381
-------
7.2.3.3 Hydroprocessing as Fe_edstock_ Pretreatment
Hydroprocessing includes those processes in which hydrogen is
combined with a feedstock and passed over a catalyst at elevated tempera-
ture and pressure. Some examples are:
• Eydrodesulfurization of residual feedstock to
be used in fuel oil production or catalytic
cracking.
• Hydrodesulfurization of heavy gas oils and middle
distillates to be used in the production of jet
fuels, diesel fuels, and heating oils.
• Hydrodesulfurization of heavy gas oils to be used
as high-quality catalytic cracking feed.
• Hydrodesulfurization and hydrodenitrogenation of
naphtha and straight-run crude distillate streams to
be used as primary feeds for the isomerization and
catalytic reforming units.
These and other uses of hydroprocessing are discussed more thoroughly in
Section 4.4 of Appendix F (volume 5).
Hydroprocessing removes sulfur and nitrogen-containing compounds,
the heavy metals, oxygen, and halides. Hydrotreating also stabilizes
unsaturated hydrocarbons by saturating the double bonds.
The overall impact of hydroprocessing is generally beneficial
for reducing emissions. Removal of objectionable materials, besides reduc-
ing emissions from subsequent processes, can significantly reduce catalyst
382
-------
poisoning and equipment corrosion and can also increase yields. Hydro-
desulfurization of catalytic cracking unit feeds is a very effective method
for reducing sulfur emissions from catalytic cracking catalyst regeneration.
383
-------
8.0 ENVIRONMENTAL ASSESSMENT
An environmental assessment was performed to examine the effects
of refinery emissions on the surrounding atmosphere. The large volumes
of emission rate data generated in this program were used to predict
ambient pollutant levels. Environmental and public health effects of the
predicted pollutant concentrations were also examined. Finally, a brief
survey of the effects of existing and potential regulatory policies and
developing technology was made.
The primary objective of the environmental assessment is to
provide guidance in identifying potential problem areas. For instance,
it can provide insight into which sources and which pollutants appear to
pose potential hazards. The results are semi-quantitative in nature, which
allows a relative ranking of such problem areas. This can help to focus
attention on those areas needing further research. The environmental
assessment is only a tool to aid in the relative evaluation of potential
environmental impacts, not a method for making precise and accurate
predictions of such impacts. The results should not be regarded as an
absolute value which can be used to predict violations of standards,
public health hazards, requirements for additional pollution control
technology, or regulatory requirements.
The complete environmental assessment of petroleum refineries is
presented in Appendix D (Volume 4) of this report. The methodology used in
performing the environmental assessment is described in Sections 8.1
through 8.3. Section 8.1 describes the hypothetical refinery model used
in the assessment. The calculations used are shown in Section 8.2. The
workings of the atmospheric dispersion model are described in Section 8.3.
Section 8.4 conveys the predictive results of the model applied to the air
quality surrounding the hypothetical refinery. Effects of existing and
potential environmental regulations and policies on refineries and their
surrounding environments are discussed in Section 8.5.
-------
The environmental assessment performed in this study included
the following steps:
• Definition of a model refinery.
• Calculation of emissions from the model refinery.
• Calculation of ground level concentrations outside the
boundaries of the refinery using atmospheric dispersion
modeling.
• Comparison of those ground level concentrations to some.
acceptable concentration.
The parameter which is used to quantify environmental impacts is
called source severity. This concept was developed by Monsanto Research
Corporation under contract to the EPA.
A source severity factor is defined as the ratio of the maximum
ground level concentration of a pollutant in a "standard receiving
atmosphere" to the "acceptable pollutant concentration," as shown below:
S -
where
S = the source severity factor,
Y = the maximum ground level concentration of the
max
pollutant, and
F = the acceptable pollutant concentration.
385
-------
This acceptable concentration is derived from either National Ambient Air
Quality Standards (NAAQS) or from Threshold Limit Values (TLV's). If the
resulting ratio is greater than 1.0, then emission reduction is probably
needed. If the ratio is below about 0.01, then further reduction is
probably not needed. Emission reduction requirements for pollutants with
source severity factors between 0.01 and 1.0 are uncertain.
8.1 Definition of the Refinery Model
The first element to be examined is the development of the
model refinery. Both the refinery processing arrangement and its physical
configuration must be characterized. There is ample documentation of the
difficulties involved in trying to synthesize a "typical representative
refinery." Refineries are very diverse, and only a very rough approxi-
mation can be achieved with a single model. Therefore, it should be noted
throughout this discussion that this is not a model that attempts to
represent the total industry, but rather a model of one hypothetical
refinery that reflects the "real world" as much as possible.
The source for the model refinery is an EPA report prepared by
Pacific Environmental Services. 9 The "Large Existing Refinery" case
was chosen as the model for this study because it is essentially a worst
case. If the results show minimal environmental impact for this type
of refinery, then smaller, less complex, or more efficient grass roots
refineries should create, an even lesser impact.
8.1.1 Refinery Process Configuration
Figure 8-1 shows the basic processing configuration of the
model refinery. All of the normal refinery unit operations are represented.
Approximately 350,000 barrels per day of crude can be processed in the model
refinery. It is a reasonable example of a modern fuels refinery supplying
low sulfur products.
386
-------
Fuel Caa and LPG
CO
ITC and Cns
Aroma tj.ce
Extraction
Middle Distillates
Fuels
Diesels
Heavy Atm. Gas Oil
Cycle Gas Oils
Treating |
4 1
llcntlng Oils
To
llydrotrenters
Petrochemical
Feedstocks
Vac. Cos OIL
Fuels
Refinery
Gasoline. Naphtha, Middle Distillates ..
Figure 8-1. Block Flow Diagram of Model Refinery
-------
8.1.2 Refinery Layout
The plot plan of the refinery is shown in Figure 8-2. The
functions of the various refinery modules arc detailed in Table 8-1.
This environmental assessment does not include the effects of emissions
from storage tanks (This is discussed further in Section 8.4.3). It
includes only emissions from the refinery processes. The process areas
tend to form two clusters, probably the result of a stage-wise expansion
over a period of many years. Considerable detail has been included in
the physical model. All of the appropriate vital functions have been
accounted for and distributed in a realistic manner.
8.2 Emission Calculations
This section describes the estimation of losses using emission
factors and fitting counts. Also included are the hydrocarbon emissions
broken down into their component compounds.
8.2.1 Emission Factors and Fitting Counts
The emission factors required for the calculations were derived
primarily from the results of testing on this program, but they were
supplemented by emission factors from other sources (such as AP-42') as
needed. Fugitive emission factors for valves, pumps, compressors, flanges,
relief valves, drains, and cooling towers were developed in this program.
Estimated fitting counts and emission factors for fugitive sources in
the model refinery are presented in Table 8-2. Emission factors for
process sources and the corresponding source capacities are given in
Table 8-3.
The estimate of the population of each type of fitting is as
important as the emission factor in determining total emissions. The
PES model contained estimates of fitting populations, but they were not
388
-------
LARGE CAPACITY
W - 1865 m
e
u-i
ts
22,
z:
24
20
25
30
45
46
58
5C
26
31
47
60
68
32
51
33
62
10
36
39
38
40
41 42
6364.
69
70
71
72
65
G6
67
73
54
11
13
14
15
12
16
17
IB
21 .
43
55
T4
76
44
56
57
75
N
126
Figure 8-2. Model Refinery Layout
389
-------
TABU1". 8-1. LARGE CAPACITY EXISTING REFINERY /MODULE KEY
Module No.
LI
L2
13
IA
L5
It
17
IB
19
L10
L1I
112
L13
114
115
L16
U7
U8
LI 9
L20
L21
122
L23
124
L25
L26
L27
L28
L29
L3D
L31
L32
133
134
L35
Lsa
169
L70
171
L72
173
L74
L75
176
Description
Buffer Zone
Feedstock Storage
Crude Oil Storage
feedstock Storage
Feedstock. Storage
Crude Oil Storage
Feedstock .and Product
Storage
Crude, Feedstock, and
Product Storage
Crude, Feedstock, and
Product Storage
Oil-Water Separator
Produce Storage
Product Storage
Distillation and Gas
Recovery Unit
Jet Hydrofiner/Catalytic
Reformer
Naphtha Hydrotreater
Hydrotreater (It Cycle
Oil)
Hydrogen Manufacturing
Partial Oxidation Unit
Future Expansion
Cooling lover
Flares
Feedstock and Product
' " Storage
Naphtha Bydrotreater
Vacuum Gas Oil licit
Benzene Fractlonation
St*ui Rerun Stills
Future Expansion
Crude Distillation
Catalytic Refoner
Vacuum Residua De-
sulfurizer
Hydrogen Manufacturing
AlkylaticD
Distillate Hydrodesul-
forlzatlon (Hvy Cat
Oil)
Sulfur Recovery
Tanks /Cooling lovers
Vapor Recovery/Gasoline
Rectifier /Tanks
Main Pumy House
Produce Storage
Uaetevacer Tre^cicenC
Building
Product Storage
Shops and Warehouse
Crude Oil Storage
Crude, Feedstock, and
Product Storage
Module No.
L36
L37
L38
L39
L60
L41
L42
L43
L44
L45
U6
L47
L4S
L49
L50
L51
L52
L53
L54
L55
L56
L57
L58
L59
L60
L61
162
L63
164
165
L66
167
Description
Catalytic Reformer
Aromatic 6 Extraction
Catalytic Cracking
Para-Xylene Plant
Delayed Coker
Sorrel Storage
Barrel Reconditioning
Feedstock Storage
Stern Water Impound
Basin
Warehouse ''
Cas Hclder/Blcvcovn
Stack
Cas Holder/Slowdown
Stack
Fire Prevention Train-
ing Facility
Oil-Water Separator
Asphalt Plant
Solvent Treating Plant/
Boiler House
SO; Treating Plaat/
Tanks
lube Oil Packaging
Coke Storage
Crude Oil Storage
Feedstock. Storage.
Tanks/Impound Basin
Adaiais t rat ion
Oil-l'ater Separator
Gasoline Sweetener/
Crude Distillation
Crude Distillation/
Crude D*£aicer
Specialty Crude
Distillation
Speciality Crude Dis-
tillation/Condenser
Box
Gasoline Fractionating
unit
Tank loading/Truck
loading/Vapor Re
covery
Buildings
LFG Storage and Blending
The oil/vater separator In hodule 110 treats aqueous discharge from
Modules L1-L21.
The c-parator located In Module 159 treats aqueous streams from Modules
L58-L60, L70, 171, and L73-L76.
The vastevater separator in Module 149 treats discharges from the remain-
ing nodulei.
390
-------
TABLE 8-2, FUGITIVE SOURCES AND EMISSION FACTORS
SOURCE
Pumo Seals1
Valves '
Compressor Seals
Flanges1
Relief Valves1
Process Drains1
Cooling Towers1
Oil/Water Separators2
Dissolved Air
Flotation1
ESTIMATED POPULATION
(OR CAPACITY)
313
340
1714
4198
7422
8442
82
48
84346
171
1105
(10,668 x 103 gal/hr)
(160.3 x 103 gal/hr)
(1719 x 1C3 gal/hr)
(220.5 x 1C3 gal/hr)
SERVICE
CATEGORY
Light Liquid
Heavy Liquid
Hydrogen
HC Gas
Light Liquid
Heavy Liquid
Hydrogen
HC Gas
NA
HA
NA
NA
Uncontrolled
Controlled
NA
NOfi-METKANE HYDROCARBON
(NMHC) EMISSION FACTORS
0.25 Ib/hr. /source
0.046
0.018
0.059
0.024
0.0005
0.11
1.40
0.00056
0.19
\
0.070 |
t
0.006 lb/103 gal.
5.0 lb/103 gal.
0.2 lb/103 gal.
(0.01 lb/103 gal)3
Emission factors based on Radian testing.
2 Emission factors based on AP-42.
3
This value is a rough average of a very few test results.
It should not be construed as an emission factor for broad application.
391
-------
TABLE 8-3, PROCESS SOURCES AND EMISSION F'ACTORS
SOURCE
CAPACITY
PAKTICULATES
EMISSION FACTORS
SO,
NOV
CO
KM HYDROCARBONS
Proceaa Heatera/Boilera
- oil fired
- gas -fired'
36.7 x 103 gal/hr 6 lb/101 gal 47.7 lb/101 gal 60 lb/10J Kal 5 lb/10J gal 1 lb/101 gal
2.27 x 10' Et'/hr 5 lb/10' ft1 0.6 lb/106 £tj 120 lb/10' ft3 17 Ib/lO6 ft3 3 lb/10*- ft'
Fluid Cncnlytic
Cracker CO Boiler'
2.086 x 103Dbl/hr 45 lb/103Bbl. 493 lb/103Bbl. 71 lb/105Bbl . Negligible 13.3 lb/lo'Bbl.
LJ
sO
M
Sulfur Recovery Complex1*
- Clans plants plua
Wellman-Lord Tall
Gaa Treating Unit
long tons/day
(l.TPD)
- Sulfurlc Acid Plant 179 LTPD
3.6 Ib/LT
U.6 Ib/LT
Flarcu5
350 x 103Bbl/day Negligible
26.9 lb/10!Bbl 18.9 lb/10Jbbl /..3 lb/10JUbl 0.6 Ib/lO'bbl
1 Based on AP-427 faccors for No. 6 fuel Oil with 0.3 wt . X sulfur.
Based on AP-A2 factors for natural gaa.
1 Baaed on AP-42 factors for a Fluid Catalytic Cracker with un El uct roaLat ic Precipl tator and n CO Boiler,
except the NKHC taccor was taken from Radian tenting.
11 Based on sulfur recovery «f f icleiiclea taken from Hydrocarbon Procenulng;'' 2-scngc Glaus - 92X, Wcllman-Lord
TGTU - 99X, SulfurJc Acid Plant - 99Z
Based un AF
(acturu for blowHown flyutema with vapor recovery and vents to flares,
-------
broken down into the service categories corresponding to the emission
factors. Radian data on fitting counts were generated during the field
testing phase (see Tables 5-16 and 5-17 in Section 5). These unit
configurations did not necessarily match those from the model refinery.
The detailed procedure developed to generate fitting counts compatible
with emission factor service classes and to represent the model refinery
as closely as possible is described in Appendix D (Volume 4).
Although emissions from storage tanks were not within the scope
of this study, they were estimated to provide a basis of comparison to
other hydrocarbon emission sources. The PES report " contained a detailed
breakdown of the storage facilities, their service, capacities, and
annual turnover. Emission factors were taken from AP-42 and applied to
these facilities to estimate total emissions. The PES data indicated
the use of floating roofs to control emissions on all tanks containing
liquids with Reid vapor pressures greater than 0.5 psia.
8.2.2 Emissions of Criteria Pollutants and Total Hydrocarbons
Applying all of these factors, a slate of refinery emissions
was generated. Table 8-4 is a summary of those emissions by pollutant type.
8.2.3 Emissions ^f Selected Hydrocarbon Components
The emissions estimates given in Table 8-4 are sufficient to
estimate the ambient concentrations of criteria pollutants, but a species
breakdown is necessary to evaluate individual hydrocarbon concentrations.
Analyses of the components in various process streams were made in this
program and supplemented by literature sources. The application of these
stream analyses is not straightforward, however, since the emissions were
393
-------
TABLE 8-4. SUMMARY OF EMISSIONS FROM THE MODEL REFINERY
Pollutant
Particulatcs
SO
X
CO
NO
X
Norune thane
Hydrocarbons
Emissions in Tons/Year
Point Sources1 Fugitives2 Storage
1,425
14,650
1,247
12,693
364 8,767 3,308
Total
1,425
14,650
1,247
12,693
12,439
1 Includes combustion sources, fluid catalytic cracker, CO boiler,
sulfur recovery complex, and flares.
2 Includes process fittings (pumps, valves, flanges, compressors,
drains, and relief valves), cooling towers, oil/water separators, and
other wastewater treating units.
394
-------
calculated on a unit basis. The necessary approach involves three
steps:
(1) Identification of the major product and intermediate
streams in each unit. Total unit emissions were
distributed among each stream.
(2) Application of stream analyses to estimate component
emissions for each stream. Component analyses were
obtained from samples taken during this program and were
supplemented where necessary with data from a previous
Radian literature survey,13'an API medical research
report1,32 and engineering estimates.
(3) Summation of the stream component emissions to get unit
component emissions. In this assessment, some components
were consolidated into groups if either discrete con-
centration data or quantifiable toxicity data were
unavailable.
An example of the distribution of emissions between each process
stream for valves in an FCC unit is given in Table 8-5. The estimated
percentage of fittings on each stream is multiplied by the weighted
average emission factor for fittings in that service. The result is the
percentage of the total unit fugitive emissions attributed to each process
stream. The weighted average emissions factor used in Table 8-5 may be
a combination of the gas-light liquid, or the gas-heavy liquid emission
factors if the particular process stream is present in the unit as both
a gas and a liquid.
A summary of stream quality data is given in Table 8-6. This
table shows the estimated component analysis for numerous refinery
streams.
395
-------
TABLE 8-5. DISTRIBUTION OF UNIT FUGITIVE EMISSIONS BY STREAM
MD
-------
TABLE 8-6, SUMMARY OF STREAM QUALITY DATA (PPMWJ
Conpound or
Funct tonal Family
Benzene
Toluenp'
tthylbentcnt
Xyleiies
Other Alkylbenzenes
Naphthalene
Anthracene
Bipheuy 1
Other PNA's
n-Hexane
Other Alkalies
Olcf Ins
Cyuloalkanes
Other Compounds
Indicated Present
Cnidt
Oil
60
680
220
880
3,739
PSO
140
320
7.8HU
18,000
87/.240
0
58,300
Carbonyl
~ 500 ppm
Thlols
~ 25,000 ppm
Sulf Ides
~ 6,000 ppra
Qulnollnes
~ 200 ppm
Pyrldln*s
Straight
Rim
Naphtlia
253
2,621
887
1,623
•16.578
1,463
5
628
14,983
38,838
499,613
0
422,508
Pyrldines
Thlola
Sulfldes
Middle
Distillate
0
5
9
52
835
100
56
0
5,507
0
842,536
0
100,000
Pyrldlr.es
Thiols
Snlfldea
~ 51,000 ppra
Qulnollnes
Atmospheric
Gas & Oil
0
8
6
16
61
4
3
0
220
0
949,573
0
50,000
Pyrldlnes
Thioln
Snl fides
Qulnollnes
^ 9 pirn
Vacuum
Gas & Oil
0
5
6
22
36S
28
12
9
663
0
948,887
0
50,000
Pyrldlnea
Thlols
Suicides
Qulnolines
Refornate
5 , 400
77,700
33,500
170,900
324,400
7,400
0
0
700
24,000
356,000
0
0
Hj
Hi Recycle
Gas
0
0
0
0
0
0
0
0
0
0
650,000
0
0
~ 350,000
Deaulfurized
Naphtha
253
2,621
887
1,623
16,578
1,463
5
628
14,983
38,838
499,613
0
422,508
Continued
-------
TABLE 8-6. (Continued.)
VO
03
Compound or
Functional Family
Benzene
loluene
EChy Ibenzene
Xylenes
Othrr Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Other FNA'a
n-llex«no
Other Alkanes
Olefins
Cycloalkanes
Other Compound*!
Indicated Present
Hydrotrca ted
Mtdillo
Distillate
0
3
9
52
835
100
56
0
5,507
0
887, 436
0
IDO.WXI
Siilfldcs
t 6,000 ppm
Refinery
Fuel
CaE
0
0
0
0
0
0
0
0
0
0
920,000
60,000
0
HJ : 20,000
Thlola
Sulfldei
Liquefied
Petrolcura
Gas (L?C)
0
0
0
0
0
0
0
0
0
0
1,000,000
0
0
Thiols
SulElde*
Raffinate
30
750
300
1,500
2,300
50
0
0
50
63,000
932,000
0
0
Aroma tics
Extract
17, 840
256,700
110,670
564,590
48,000
100
0
0
100
100
1,900
0
0
Benzene
993,000
2,000
0
0
0
0
0
0
0
5,000
0
0
0
Toluene
1,000
992,800
4,000
1,000
0
0
0
0
0
0
1,200
0
0
Xylcncs
0
1,000
162,420
828,580
5,000
100
0
C
100
0
2,800
0
0
(Continued)
-------
TABLE 8-6. (Continued)
Compound or
Functional Family
Benzene
Toluene
Ethylbenzene
Xylenes
Other Aikylbenzenes
Naphthalene
Anthracene
Blphenyl
Other PKA's
n-Hcxane
Other Alkane8
Oleflns
Cycloalkanes
Other Compounds
Indicated Present
LPC
Oleflns
0
0
0
0
0
f)
0
0
0
0
400,000
600,000
0
ThiolB
Alkylate
0.1
0,3
C.I
1.1
3.3
0.3
0
0
2.2
96
998,956
930
11
Cracked
Naphtha
2,880
89,780
21,430
171,450
243,470
10,950
0
0
6,480
11,830
204,110
170,740
68,880
PyrlUlnee
ThiolB
Sulfldes
Qulnaltnes
FCC
Light Cycle
Gas & Oil
0
40
0
610
26,670
59,000
10,270
10,180
624.480
0
190,800
36.750
41,200
Phenols
Carbonyla
Pyrldlnes
Thlola
Sulfldea
Qul no lines
FCC
Heavy Cycle
Gas & Clt
740
10,000
1,200
11,800
38,200
14.000
0
0
22,500
0
701,560
50.000
150,000
Pyrldinea
Csrbonyls
Thiols
Sul Fid en
Qulnolln«a
Heavy
Aromatica
Extract
(SOj Plant)
0
0
0
0
750.000
0
0
0
200,000
0
45,000
0
5,000
Asphalt
0
0
0
0
•ch
0
2
0
200
0
999,798
i.
i
API
Separator
Skin Oil
87
1,713
661
2,510
12,751
990
457
2,351
29,700
4.
948,780
i.
i
Vacuum
Resld
0
0
0
0
i
0
2
0
200
0
999,798
1 Compositions are estimated to 2 or 3 significant figures. Additional
significant figures are a result of calculational procedures, and they
should not be given any importance.
The symbol -L means that the component has been indicated to be present, but
the exact concentration is unknown.
-------
The stream breakdown is combined with the stream analyses to
get a component analysis of unit emissions. An example of this process
is shown for an estimate of fugitive emissions from an FCC unit in
Table 8-7.
A similar operation was performed separately on relief valves,
since they arc not distributed uniformly across the streams. Relief
valves are usually placed at the top of a fractionating column or
reactor vessel, and, thus, are exposed primarily to lighter streams.
Table 8-8 shows the allocation of relief valves for the Aromatics
Fractionation unit. The number of relief valves in each stream service
was totaled, and the stream analyses were applied to the emissions,
as shown in Table 8-9. All relief valves in the model refinery were
assumed to vent to the atmosphere.
Still a different procedure was required to characterize the
hydrocarbons emitted from the API separators. Analyses were available
for the inlet oil to the separator and for the recovered oil. A hydro-
carbon material balance was made to estimate the composition of the
evaporative emissions from the separator, as shown in Table 8-10. The
available analyses showed only the aromatics components, so the balance
of the oil was assumed to fall in the alkane family.
This material balance approach assumes that any component lost
from the oil phase, is lost as evaporative emissions. This neglects the
slight solubility of certain components which could result in mass transfer
to the water phase (or eventually even the sludge phase). Thus, this
approach results in a conservatively high, worst case assumption of the
emission rate of individual species from the API separators.
Summary of Hydrocarbon Species Emissions—The emissions of
selected hydrocarbon species were calculated by the above methods. The
results are summarized in Table 8-11. These figures represent only
400
-------
TABLE 8-7. FLUID CATALYTIC CRACKING - FUGITIVE EMISSION CHARACTERIZATION
Stream
LPC Olcfliis
Crocked Naphtha
Lt. Cycle Can Oil
Hvy. Cycle Uas Oil
7
Weighted Contribution of each Component to Unit Emissions, III ]>pmu
Aluus. Gas Oil
Fuel Cos
1
30
0
0
0
0
0
0
0
0
1
0
0
0
'.5
1
0
Kate
Ib/hr
0
1296
0
000
9644 77153
006
9644
7715*
0
J.09562
267
109830
0
0
0 0
4928
590 103
5518
103
102
102
0
0
2916
6245
9163
0
0
5324
0
5324
9'.95
276000
92000
9185(1
1906
'•71251
18000
138000
76833
368
233201
0
0
31)09 b
412
H !
0
fiOOO
0
0
0
31008 6000
59.8
.078
2.42
.577
4.6)
6.57
.31
.006
.OOfi
.54B
.118
28.18
13.95
1.85
.359
-------
TABLE 8-8. RELIEF VALVE DISTRIBUTION
Example: Aromatics Fractionation Unit
Total Relief Valves = 6
Steam No. of Relief Valves
Benzene 4
Toluene 2
Xylenes 0
402
-------
•P-
O
TABLE 8-9. RELIEF VALVE SUMMARY - FUGITIVE EMISSION CHARACTERIZATION
Weighted Contribution of mch Conponirit to Unit Enlaslons, In ppav
II, Recycle Cos
Fuel Gas
LFG
LFG Olefins
S.R. Naphtha
Cracked Naphtha
Reformate
Extract
Rafflnate
0 9828
9^99 663492
TOTALS
Normalized
Total.
1.1 0
100.0 2253J
23040
24421
4439
2A458
35247
1345
113
3256
9713 678416
29703
1100 0
80143 S0050
81946 81850
-------
TABLE 8-10. ESTIMATED COMPOSITION OF INLET OIL,
HYDROCARBON VAPOR, AND OUTLET OIL
STREAMS AROUND AN API SEPARATOR
Component
Benzene
Toluene
Ethylbenzene
Xylen.es
Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Polyrmclear Aroraatics (PNA's)
Alkanes
Estimated
Inlet
Oil
0.03
0.22
0.06
0.21
0.80
0.29
0.04
0.18
2.04
96.13
100.00
Composition of
Vapor
Fro-
Separacor
0.07
0.22
0.06
0.21
0.80
0.29
0.04
0.18
0.15
97.98
100.00
Streams (Wt %)
Outlet
(Skinned)
Oil
0.01
0.22
0.06
0.21
0.80
0.29
0.04
0.18
2.98
9.5.21
100.00
Skimmed Oil Rate = 667 Ib./lOOO Ib. inlet oil
Vapor Lost from Separator = 333 Ib./lOOQ Ib. inlet oil
404
-------
TABLE 8-11, SUMMARY OF HYDROCARBON SPECIES EMISSIONS FROM
FUGITIVE SOURCES
Source
Component
Benzene
Tolurnc
Ethy Ibcnzene
Xyleneo
Other Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Other PNA's
n-Hexane
Other Alkanea
OlefJns
Cycloalkanes
Hydrogen
TOTALS
V, P. C, F,
ppmu
7,200
21.000
5.600
31,000
42,000
1,700
20
230
7,700
16,000
654,000
'i6,000
135,000
31 ,000
D, CT*
kg/hr
2.8
8.2
2.2
12.1
16.6
0.7
0.01
O.i
3.0
6.3
255.9
18.1
52.9
12.3
391.2
Relief Valvofl
ppmu
23,000
2 '.,000
4,500
26,000
35,000
1,400
1
110
3,300
9,700
676,000
30,000
82,000
82,000
kg/hr
0.4
0.4
0.1
0.4
0.6
0.02
0.0
0.0
0.05
0.2
11.3
0.5
1.4
1.4
16.8
APT Scpnrntarti
ppnrw kg/hr
700 0.4
2,200 1.1
590 0.3
2,100 1.1
7,900 4.1
2,900 1.5
390 0.2
1,800 0.9
1,500 0.8
•i.** 4,.
980,000 502.4
•i -i
•i 4.
•i i.
512.8
Totals
ppmu
3,900
11, GOO
2,800
15,000
23,000
2.400
220
1,100
4,200
7,100
640,000
20,000
59,000
15.000
kg/hr
3.6
9.7
2.6
13.6
21.3
2.2
0.2
1.0
3.9
6.5
769.6
18.6
54.3
13.7
920.8
* Kl
• fugitive emissions from valves, pumps, compressors, flanges, drains, and cooling towers.
Components marked with "•£" are indicated present, but no quantifiable concentration data
were available.
-------
fugitive hydrocarbon emissions and not the point source emissions from
sources such as process heaters and fluid catalytic cracking regeneration.
The stack hydrocarbon emissions did not significantly affect any of the
critical emission points for hydrocarbon species because of the effects
of height of release and plume rise.
8.3 Atmospheric Dispersion Modeling
Ground level concentrations of the various pollutants can be
estimated using any one of a large variety of computer modeling techniques.
The choice of the model and the details of its application to the refinery
model are discussed in the following sections.
8.3.1 Choice of the Dispersion Model
There were several guidelines considered in choosing a model.
First it should be an established, well accepted model. It should have
the capacity to handle a large number of both point sources and area
sources. It must be able to give not only the total concentration of the
pollutant at any given point, but also the relative contribution of each
source to that total.
Although not alone in satisfying these requirements, the EPA
guideline model RAM ' is certainly the most well-known. It has been
extensively used and, at the time of this study, was accepted by regulatory
agencies for flat terrain modeling. There are two versions of RAM, the
rural and urban versions. The urban version has slightly higher dispersion
coefficients to account for the numerous heat sources typical of an urban
environment. As with other unconstrained choices, the worst case was
chosen, which means the. rural version of RAM.
The RAM model was not calibrated in this study. Raw predictions
were used in evaluating the refinery impact. The use of raw predictions
406
-------
can result in ambient concentrations that arc overestimated by as much
as a factor of two.
8.3.2 Application of the Dispersion Model to the Hypothetical Refinery
The RAM dispersion model133 is capable of predicting a 1- to
24-hour average concentration of relatively unreactive pollutants.
A maximum of 250 point and 100 area sources can be modeled. Concentrations
are predicted at a maximum of 150 selected locations (receptors).
RAM uses Gaussian steady-state dispersion algorithms for areas
where one wind vector for each hour is a good approximation. Concentrations
are calculated hour by hour as if the atmosphere had achieved a steady-
state condition.
Meteorological parameters utilized by the model include wind
speed, wind direction, temperature, atmospheric stability class, and
mixing height. The parameters are set by the "standard receiving
atmosphere" as defined by Monsanto in their source severity work.130
The worst case wind direction was determined by comparing the results of
modeling for wind blowing for one hour from each of 16 different directions.
After determining the worst case wind direction, a repeating sequence
of 3 wind directions (1 hour from the worst case direction and 1 hour
each from 5 degrees on either side of the worst case direction) was used
to obtain mean concentrations for short averaging times. It is
recognized that the persistance of these conditions for a 24-hour period
is quite improbable. This assumption again results in a worst case
approximation of "real world" conditions. The source severity methodology
is specific in requiring that these conditions be used, and no provisions
are given to incorporate variations when modeling for longer averaging
times.
407
-------
Annual concentrations (for comparison with N02 NAAQS) can be
134
predicted with Larsen statistics. Using empirically determined ratios,
the maximum annual concentration can be determined from mean concentrations
for shorter averaging times. These ratios are functions of the standard
geometric means (SGM) of the shorter averaging times.
The dispersion coefficients are empirically-determined as
functions of atmospheric turbulence, distance from the source and the
concentration averaging time. Thus, the spread of the plume is dependent
on these three factors. The atmospheric turbulence is defined by stability
classes. These classes, which range from very unstable to neutral to
very stable atmospheres, are determined by wind speed and insolation
during the day, or wind speed and cloud cover during the night. The most
unstable class is A. Class F the most stable. The C stability class
used here is considered neutral.
RAM can accept both point source and area source inputs. The
data required to characterize a point source includes source coordinate,
emission rate, physical height, stack diameter, stack gas exit velocity,
and stack gas temperature. Area source parameters consist of coordinates
of the southwest corner, side length, total area emission rate, and
effective height.
Stacks, flares, etc., were modeled as point sources. Fugitive
emissions were modeled by three different methods.
(1) As a. single point source originating in the center
of the process unit plot.
(2) As a pseudo-area source (where the single point source
was divided into three point sources distributed across
the unit in a plane perpendicular to the worst-case
wind direction).
408
-------
(3) As area sources.
The point source approach gave very unrealistic boundary line conditions
with large concentration peaks directly downwind of the unit centerlines
and very low concentrations elsewhere. The pseudo-area approach had
some smoothing effect, but only the rigorous area source approach gave
satisfactory results.
Concentrations from the point sources are a function of the
distance downwind and crosswind from the source to the receptor.
Concentrations due to area sources are calculated using the narrow
plume approximation. This neglects diffusion in the crosswind direction
and assumes that an area source consists of many narrow plumed point
sources. As a result, any receptor that has no area sources directly
upwind receives no contribution to its predicted concentration from area
sources. This approximation is good when modeling large urban area
sources.136 The five degree variation in wind persistence did add some
dispersion outside the worst-case wind direction streamline.
The locations of a series of permanent receptor sites were also
input to the model. The locations consisted of a grid placed in the area
of greatest impact as predicted by the worst case wind direction. The
model then calculated the 24-hour average concentration at each receptor.
From these data, maximum concentrations were determined. Also, isopleths
(lines of equal concentration) were plotted. Not only were the total
ambient concentrations displayed for each receptor, but these concentrations
were broken up into their component contributions from each of the sources.
409
-------
8.4 Impacts on Ambient Air Quality
8.4.1 Criteria Pollutants and Total Hydrocarbons
The modeling results for criteria pollutants and total hydro-
carbons are summarized In Table 8-12. Four of the predicted pollutant
concentrations do not exceed the NAAQS, those being particulatcs, oxides
of sulfur, oxides of nitrogen, and carbon monoxide. The maximum
ground level concentration of particulates was 68 yg/m3 as compared to
the NAAQS of 260 yg/m3. These values include only process particulates
which result primarily from the FCC and oil fired heaters, and do not
include fugitive dust from unpaved roads, construction activities, or
coke handling. The point of maximum concentration occurred due west of
the refinery center at a distance of 1.5 kilometers from the fence line.
The maximum concentrations of GO was found to be 233 yg/m3 as
compared to the NAAQS of 365 yg/m3. The maximum point was due west of
the sulfur recovery complex and occurred at one-half kilometer from the
refinery boundary.
The maximum 1-hour concentration of CO was predicted to be
17 yg/in3 as compared to an NAAQS of 10,000 yg/m3. The maximum point
occurred due west of the refinery center and at a distance of 1.25
kilometers from the boundary line.
The maximum 24-hour average N02 concentration was estimated to
be 269 jjg/m3. By applying Larsen statistics as discussed in Appendix D
(Volume 4), the. predicted annual average N02 concentration at the point of
maximum concentration was estimated to be 55 /Jg/m3. This figure is well
below the NAAQS value of 100 /Jg/m3 as a maximum annual average. This pre-
dictive estimate has been based on the assumption that all of the NO is
X
emitted as N02. Actual N02 concentrations are likely to be significantly
lower than the predicted value.
410
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TABLE 8-12. SOURCE SEVERITY FACTORS FOR CRITERIA
POLLUTANTS
Pollutant
Particulates
S02
CO
NO 2
Nonme thane hydro-
V -i-
max
ug/m3
68
288
16
55
9644
Ftf
yg/m3
260
365
10,000
100
160
s+tt
0.26
0.78
0.0016
0.55
60.3
carbons*
X is the maximum ground level concentration.
max
'F is the acceptable pollutant concentration (which is the NAAQS for
criteria pollutants).
-!•-;•-j-
S is the source severity, with the following decision levels.
if S >_ 1: Additional Emission Reduction Probably Required
if 0.1** <. S < 1.0: May or May Not Require Additional Emission Reduction
if S < 0.1**: Additional Emission Reduction Probably Not Required
* The nonmethanc hydrocarbon standard is a guideline standard based on the
estimated contributions of hydrocarbons to oxidant formation.
** The lower critical value may need to be as low as 0.01 where large
uncertainties arc involved.
411
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An analysis of the source severity factors indicates that none
of the criteria pollutants has a high probability of causing a public
hazard (as indicated by S > 1). On the other hand, only CO has a source
severity factor low enough to have confidence that it does not create a
hazard. The others are in the area of uncertainty where no clear decision
can be made.
The total hydrocarbon concentration was found to exceed the
federal guideline for 3-hour maximum (6-9 AM) nonmethane hydrocarbon
concentration of 160 pg/m3, with a maximum concentration of 9644 yg/m3.
The point of maximum concentration was located on the refinery boundary,
due west of the main processing area. Although the concentrations fell
off rapidly from the maximum, the 160 yg/m3 isopleth extends about 3.5
kilometers downwind and encompasses about four square kilometers, as
shown in Figure 8-3. The source severity factor for total hydrocarbons
is quite high. However, the NAAQS guideline for hydrocarbons is based
on the prevention of the formation of photochemical oxidants rather than
on primary toxicity data. It should be noted that this guideline is
no longer widely accepted or used because the relationship between ozone
formation and ambient hydrocarbon concentrations is not adequately defined.
8.4.2 Selected Hydrocarbon Components
The ambient concentration of any given hydrocarbon species can
be determined by summing the contribution of the component from all
modeled sources. The RAM model is capable of performing this analysis
with the assumption that all species will disperse at the same rate; that
is, atmospheric turbulence outweighs any differences in molecular diffusion
between species.
The first point of interest is the receptor showing the largest
total hydrocarbon concentration. Table 8-13 shows the component breakdown
at that point. This maximum point is located directly downwind of the. API
412
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Pollutant: HC
NAAQS Guidelines: .160
Aroa in Excess of NAAQS Guidelines: 4.05 km2 (1.57 mi2)
Figure 8-3. Hydrocarbon Isopleth
East
South
-------
TABLE 8-13. HYDROCARBON SPECIES AMBIENT CONCENTRATION AT THE
POINT OF MAXIMUM TOTAL HYDROCARBON CONCENTRATION
Location: On the west boundary line at a point 1650 meters from the north-
west corner; directly downwind of source L49 (an API separator).
Component
Concentration, yg/m;
Concentration, ppmv
Benzene
Toluene
Ethylbenzene
Xylenes
Other Alkylbenzenes
6.6
21.2
5.7
19.8
102.2
0.0019
0.0051
0.0012
0.004
0.017
Naphthalene
Anthracene
Biphenyl
Other Polynuclear Aromatics
27.5
3.6
16.5
22.7
0.0047
0.0005
0.0025
0.0030
n-Hexane
Other Alkanes
2.8
9380.0
0.0007
1.876
Olefins
Cycloalkanes
H2
0.0
33.7
1.8
0.0
0.009
0.020
Total Hydrocarbons
9644.0 yg/m:
1.95 ppmv
414
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separator (Source L-49), and 97.8 percent of the hydrocarbon species at
that point came from the separator. The bulk of the hydrocarbons are
from the alkane family (9380 Pg/m3 or 1.9 ppmv), but both the aromatics
and polynuclear aromatics species are present at the part per billion
level (PPB).
It is also desirable to find the point of maximum concentration
Tor each hazardous component. A limited search was carried out to find
these species maximum points by finding the maximum points for units
with high concentrations of the subject species. Resulting maximum
concentrations are summarized in Table 8-14.
All of the species maximum concentrations were found at the
two points having the highest concentration of total hydrocarbons. Five
species (including benzene, naphthalene, anthracene, biphenyl, and the
general polynuclear aromatics family) had maximum concentrations adjacent
to the API separator. The maximum concentrations of other species were
found at a receptor on the west boundary about 1380 meters from the
northwest corner. The largest contributor to this point was the crude
distillation unit (L28-1). Other significant contributing units included
the two catalytic reformers (L36-1 and 29-1), aromatics extraction (L37-1),
alkylation (L32-1), fluid catalytic cracking (L38-1), delayed coking
(L40-1), hydrogen plant (L31-1), and resid hydrodesulfurization (L30-1).
The largest concentration for any single component examined was found to
be hexane at a concentration of 15 ppbv.
To assess the impact of a given concentration of a pollutant
species, quantifiable toxicity data must be available. The Monsanto
approach uses the term "acceptable pollutant concentration" as the level
at which there is a very low probability of adverse impacts on the general
public. For criteria pollutants, the Primary Ambient Air Quality
Standards (PAAQS) were used as the acceptable pollutant concentrations.
415
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TABLE 8-14. MAXIMUM AMBIENT CONCENTRATION OF SELECTED HYDROCARBON SPECIES
Ambient Concentration
Component
Benzene
Toluene
Ethylbenzene
Xylenes
Other Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Other Polynuclear Aromatics
ug/m3
6.6
26.3
10.7
53.6
105.5
27.5
3.6
16.5
22.7
ppmv
0.0019
0.0063
0.0022
0.0092
0.0179
0.0047
0.0005
0.0025
0.0030
Location
On the West Boundary,
XXXX meters from the
Northwest Corner
1650
1380
1380
1380
1380
1650
1650
1650
1650
n-Hexane
58.5
0.0152
1380
Olefins
37.6
0.010
1380
Cycloalkanes
365.8
0.099
1380
-------
For other species, the acceptable concentration can be defined from the
Threshold Limit Value (TLV) as shown below:
F = TLV(G)
where
G = (8/24) (1/100) = 1/300,
so
F = TLV/300.
The factor "G" is defined as a conversion factor to express TLV values as
"equivalent PAAQS." G is defined as 1/300. This comes from two factors:
• The ratio (8/24) converts the TLV from an 8-hour per day
basis to a 24-hour basis.
• The factor (1/100) is a safety factor to account for the
fact that the general public is more susceptible to illness
than the industrial work force (for whom the TLV was set).
Table 8-15 shows a summary of the acceptable pollutant
concentrations that result from this operation. The values in parentheses
are values arbitrarily assigned to a family of chemicals, some of whose
members have TLV's that average out to the assigned value. These values
should be used with caution. Not all of the members of such a family are
equally toxic, nor is it certain that their effects would be additive.
If the source severity factors based on these values are low, then it can
be said with some confidence that no damage will be done by those com-
pounds. If the values are high, however, no conclusions can be drawn.
417
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TABLE 8-15. SUMMARY OF "F" VALUES
Pollutant
Benzene
Toluene
Ethylbenzene
Xy.lenes
Other Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Other Polynuclcar Aromatics
n-Hexane
Other Alkanes
Olefins
Cyloalkanes
F yg/m3
114
1,388
1,586
1,586
(488)**
194
0.66
4.4
(25)
1,281
(16,665)
(12,344)
(.4,937)
Based on
TLV =
TLV =
TLV =
TLV =
TLV =
TLV =
TLV =
TLV =
TLV =
TLV =
TLV =
TLV =
TLV =
10 PPM
100 PPM
100 PPM
100 PPM
(25 PPM)
10 PPM
200 yg/m3*
0.2 PPM
(1 PPM)
100 PPM
(1,000 PPM)
(1,000 PPM)
(400 PPM)
* Based on "Coal Tar Pitch Volatiles" which anthracene is a major component.
" TLV values arbitrarily assigned to a family of chemicals.
418
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The whole process of basing an acceptable pollutant concentration
on TLV's should be critically appraised. These values were set for use
in industrial hygiene studies within plant boundaries, and the American
Conference of Governmental Industrial Hygienists (ACGIH) specifically
warns against their use:
• as a relative index of hazard or toxicity,
• in the evaluation of community air pollution, or
* in estimating the toxic potential of continuous,
uninterrupted exposure.
While such usage is discouraged, the fact remains that no other source of
quantifiable toxicity levels is available. Therefore, the use of TLV's
to estimate acceptable pollutant concentrations is used here in accordance
with the source severity methodology. It is felt that this comparison,
however tenuous it might be, is better than ignoring the problem. This is
especially true as long as the proper qualifications and limitations on
the results are explicitly stated.
Taking the maximum ambient concentrations presented in Table 8-14
and the acceptable pollutant concentrations shown in Table 8-15, it is
straightforward to calculate source severity factors for each component.
These factors are shown in Table 8-16.
Using Monsanto1s recommended decision levels, it can be said that
there is a significant probability that anthracene and biphenyl need
further application of control technology. Several things should be noted
in the context:
• The high concentrations of these species were contributed
by a covered API separator.
419
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TABLE 8-16. SOURCE SEVERITY FACTORS FOR SELECTED
HYDROCARBON SPECIES
Component
Benzene
Toluene
Ethylbenzene
Xylenes
Other Alkylbenzenes
Naphthalene
Anthracene
Blphenyl
Other Polynuclear Aromatics
X
max
yg/ma
6.6
26.3
10.7
53.6
105.5
27.5
3.6
16.5
22.7
F
Vg/m3
114
1388
1586
1586
(488)*
194
(0.66)
4.4
(25)
S
0.06
0.02
0.007
0.03
(0.22)
0.14
(5.5)
3.8
(0.9)
n-Hexane
58.5
1281
0.05
Olefins
37.6
(12344)
(0.003)
Cycloalkanes
365.8
(4937)
(0.07)
^Values in parentheses are an average of the F values for several selected
members of the family group, and are not true F values for the entire
family.
420
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• That separator was located right on the plant boundary
line, which is quite unusual.
• There is a great deal of uncertainty in the emission factor
for separators. No conclusive results were obtained from
limited testing of separators on this program, so AP-427
factors were used in this analysis. The EPA has since
begun a program to improve these factors.
• The emissions from an API separator are highly variable in
component breakdown (much more so than process unit emissions),
and the species breakdown for that unit is based on several
grab samples which may well not be reflective of "typical"
operation.
• These component emissions (calculated by an oil-phase volatile
hydrocarbon balance) may be overstated due to solubility
effects.
It can also be stated that there is a very low probability of
the need for further control of ethylbenzene and the olefin family. All
other species fall into the range where no clear decision can be made.
The uncertainties involved in the calculation of these source severity
factors make it impossible to make clean cut decisions for the range
from. 0.01 to 0.99.
It should also be noted here that all of the quoted hydrocarbon
species maximum points occurred on the refinery boundary. Because they are
released close to the ground and with little velocity or thermal buoyancy,
the vapors tend to stay at ground level. Dispersion does proceed at a
relatively rapid pace when moving downwind. This establishes two inter-
esting points:
421
-------
• The sphere of influence for hydrocarbon species that were
noted as potential problems at the boundary line does not
extend more than a few hundred -meters.
• This further suggests that buffering areas with a high
potential for fugitive emissions could be effective in
reducing or eliminating high source severities.
8.4.3 Discussion of Re suits
The sensitivity of the source severity values to a number of
variables was estimated. The most significant variables include refinery
processing configuration, refinery layout, calculated emissions, type of
atmospheric dispersion model, meteorological conditions, hydrocarbon
component breakdown, and toxicity values.
Several of these variables can be considered in a group. A
change in the calculated emission rates will produce a proportional change
in the predicted maximum concentrations. These emissions will vary with
a change in refinery processing configuration, emission factors, or fitting
count.
Another point of uncertainty is the potential contribution of
storage emissions to the impacts predicted for the refinery process area.
Total storage tank emissions were estimated to contribute about 27 percent
of all nonmethane hydrocarbon emissions. Since no layout information
within the module was available, each storage module was treated as an
area source. The specific emission rates (lb/hr/ft2) were calculated for
each module and compared to the API separator and the process area which
contributed to the two highest points of nonmethane hydrocarbon concentra-
tion. The following conclusions can be drawn:
422
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• The worst storage tank module (L-22) had a specific emission
rate of 85.4 lb/hr/106 ft2. This figure is much lower than
either the covered API separator (L-49) with 1169 lb/hr/106 ft2
or the worst process area (near L-28) with 320 lb/hr/106 ft2.
• Since all of these sources are directly adjacent to the west
boundary line, the predicted impacts should be roughly
proportional to the specific emission rates. This is
actually somewhat conservative, since the height of release
of the storage tank emissions would be considerably higher
than for a separator or for process fugitives. Therefore,
it can be concluded that the specific impact of the worst
storage module would be significantly less severe than the
two worst points cited in this assessment.
• By examining the relative contributions of adjacent process
sources to the predicted maximum and applying similar ratios
to adjacent storage modules, it was determined that the :
inclusion of storage emissions in the modeling would not
have, significantly increased the estimated maximum concentra-
tion. It would, however, have greatly increased the area of
impact in which relatively high concentrations of nonraethane
hydrocarbons would occur.
The refinery layout may be even more critical than the complexity
and the resulting overall emission rate, especially for the predicted
hydrocarbon species. Fugitive emissions are released near ground level,
and, thus, are subject to much less dispersion than stack emissions. A
refinery layout with process units right on the boundary line (such as the
model used here) will show much higher hydrocarbon concentrations outside
the refinery boundaries than one with a buffer zone around the processing
area.
423
-------
The choice of dispersion model type could affect the predicted
pollutant concentrations significantly. None of the available models is
perfect, and predicted maximum concentrations may vary from half to
ten times (or more) the actual concentrations measured from a source. The
use of the rural version of RAM to model a refinery is a conservative
choice since the heat island effect of a refinery will tend to increase
atmospheric diffusion.
The predicted impacts will vary with meteorological conditions
as illustrated by sensitivity runs on the model. A 22 percent decrease
in wind speed resulted in a 28 percent increase in predicted maximum
ground level concentrations for total hydrocarbons. Use of the more
stable atmospheric stability class D resulted in 3 percent higher predicted
concentrations.
The hydrocarbon component breakdown is quite critical. Individual
component source severity factors will vary in direct proportion with the
predicted concentration of that component in the emitting source. There
are fairly wide confidence intervals that should be applied to those
component breakdowns. Component concentrations will vary from day to
day with changes in such things as feedstocks and operating conditions.
This effect is amplified by several orders of magnitude when discussing
API separator emissions. The small number of samples on which the
component analyses are based is insufficient to confidently average out
such process variations.
There is a shortage of quantifiable toxicity data for the many
organic compounds present in refinery processing. This makes it
difficult to prepare a comprehensive environmental assessment. The
accuracy of existing toxicity data is also questionable, and this effect
is compounded by the transformation from TLV to an "acceptable pollutant
concentration." Dividing the TLV by three to account for the difference
between eight hours per day and continuous exposure assumes that the
424
-------
toxic effects are cumulative. For some compounds that is certainly
true, but others require some critical concentration to be harmful and
are easily assimilated by the body below that concentration. The safety
factor of one hundred used to account for the greater susceptibility
of the general public is obviously arbitrary and therefore questionable.
Any of these changes in the acceptable pollutant concentration will
produce an inversely proportional change in the calculated source severity.
Recognizing the high degree of uncertainty in the results, the
following conclusions can be drawn:
• There is no certainty of public hazard resulting from the
emissions of this hypothetical refinery.
• Conversely, there is no certainty that it does not create
a hazard.
• If any hazard exists due to hydrocarbon species, the most
likely species to cause problems would be the polynuclear
aromatics.
• This approach to an environmental assessment of a generalized
source is of limited value in providing specific information
on whether steps need to be taken to further reduce emissions
of a given pollutant.
• The results can be useful in indicating the relative impacts
of various emission sources and species. For instance, API
separators appear to pose more of a potential hazard than
fluid catalytic crackers; polynuclear aromatics emissions
appear to be more troublesome than benzene. Such relative
ranking of emission sources and species can be useful in
directing emphasis towards potential problem areas.
425
-------
• If this approach were used to assess the impact of a
specific plant, it might yield more useful results. The
range of uncertainty would be much narrower because the input
factors could be more firmly defined.
8.5 Effects of Existing and Potential Regulations and Policies
This section contains an examination of the effects of environ-
mental regulations and permit policies on the emissions from petroleum
refining. The first two subsections deal with state and federal regula-
tions, respectively. The final section addresses the effects of potential
new regulations.
8.5.1 State Regulations
Existing refineries are regulated by the states, rather than
by federal standards. Standards for the South Coast and Bay Area
regions of California are considered here with the state regulations.
Though some state regulations were amended as late as 1979, most were
adopted in the early 1970's.
There is disparity among the regulations in some categories;
the general trends which could be discerned are presented here along
with notable exceptions. No attempt is made to describe the regulations
of the individual states per ^e.
All states are included even if they presently have no refineries,
This should not be interpreted, however, to mean that all. states have
specific regulations for all the pollutant categories included here. Some
states have regulations only for specific existing facilities; others have
no regulations except those supporting federal standards.
426
-------
jParticulate and Visible Emissions—Most states have specific
standards for the maximum opacity and darkness of emissions. The
strictest standard, and by far the most common, calls for a maximum
opacity of 20 percent and a maximum darkness of No. 1 on the Ringlemann
Chart. In some states these stricter standards apply only to new sources,
while existing sources are allowed an opacity of 40 percent and a darkness
of No. 2 Ringlemann. In other states these more lenient standards
apply to new and existing sources. One state allows 40 percent opacity
for new sources and 60 percent for existing sources.
Some state standards specify either opacity or darkness, but
not both. Exception to the above standards is sometimes allowed for the
flue gases from catalytic cracking catalyst regeneration and fluid
coking: these gases may be allowed 25 to 40 percent opacity where other
gases are limited to 20 percent. In all states with visibility standards,
provision is made for varying amounts of upset time.
Participates are generally regulated by source. For process
emissions in general, many state regulations incorporate a chart with
pounds per hour allowable emissions versus tons per hour process weight,
with all stacks being considered collectively.
Again, catalytic cracking catalyst regeneration is sometimes
considered separately, although no exact comparison of the various
regulations can be made because of widely varying formats. A one pound
per ton of coke burn-off regulation found in two states appears to be
the most stringent. When a CO boiler is installed on the regenerator,
an allowance is usually made for the added emissions from fuel-burning.
Particulate emissions from fuel-burning are also often considered
separately. The stipulation is generally made that all fuel-burning at
the facility is considered collectively. Regulations range from 0.1 to
2.5 pounds of particulates per million Btu of heat input; many of the
427
-------
regulations stipulate a maximum of 0.6 lb/106 Btu or less. Some
regulations have varying maximums for different size units. One state
regulation specifies that afterburners must be used.
Sulfur Emissions — Several states limit S02 emissions from any
source in a refinery to 500 ppmv; a common maximum is 2000 ppmv. One
state limits total S02 emissions from the refinery to 10 percent of the
sulfur in the crude; another limits total S02 emissions to 0.3 pounds per
barrel of oil processed. Many states, however, consider separately the
sulfur emissions from fuel burning and sulfur recovery. One state limits
emissions of mercaptans specifically to 0.25 pounds per hour.
Most regulations for S02 emissions from fuel burning are of
two types. Some states limit the sulfur content of the fuel burned
while others specify a maximum amount of S02 that may be emitted per
million Btu of heat input. When the sulfur content of the fuel is limited,
allowance is usually made for equivalent alternate means of SO^ emission
control.
Where the sulfur content of the fuel is limited, state
regulations stipulate maximums of up to 2.5 weight percent sulfur.
Most maximums are 1.0 weight percent sulfur or less. Sulfur content
of gaseous fuels (often specifically fuel gas) is expressed in grains of
H2S per dry standard cubic fool (gr/dscf ) . In this case the common
maximum is 0.1 gr/dscf.
Allowable SOp emissions from sulfur recovery units are some-
times expressed in pounds of 862 per pound of sulfur processed. These
allowances range from 0.004 to 0.12 lb S02/lb S. Several state
regulations contain a chart of allowable emissions versus sulfur
input. One state allows up to 1000 pounds of SO? per hour. Limits of
500 to 2000 ppmv S02 are in some instances set specifically for sulfur
recovery units.
428
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Hydrogen sulfide emissions from sulfur recovery units are
addressed by a few states. One state allows 0.3 pounds of H?S per hour.
One state allows 0.1 ppm I^S and two others allow 10 ppra
NO Emissions — State regulations for the control of NO emissions
from fuel burning arc quite consistent. These regulations, which normally
apply only to units larger than 250 million Btu, allow gas-fueled units
to emit 0.20 pounds per million Btu and liquid-fueled units to emit 0.3
pounds per million Btu. Solid-fueled units are allowed 0.7 pounds per
million Btu. When different fuels are burned simultaneously, the
applicable regulation is determined by proration.
Carbon Monoxide Emissions — One state limits carbon monoxide
to 200 ppmv in fuel-burning units larger than 107 Btu. All other CO
regulations are for catalytic cracking catalyst regeneration and for
fluid coking. Some states limit CO emissions from these sources to
500 ppmv; in some instances this limit applies only to new sources. One
state allows existing sources to emit 20,000 ppmv CO; another allows the
emission of 5 tons of CO per year.
The control method for CO emissions from catalyst regeneration
and fluid coking is expressed specifically in several regulations as
combustion at 1300°F for 0.3 second in a direct flame afterburner or
boiler with an indicating pyrometer located at eye level. Some, but
not all, states with this stipulation allow the use of equivalent control
measures. One state allows alternative control methods which remove at
least 93 percent of the GO in the exiting gas.
Hydrocarbon Mmis sions — Some regulations stipulate, that
oil-water separators must be pressurized, have floating or double-deck
roofs, have vapor recovery, or have an equivalent vapor control method.
One state regulation specified 85 percent control for wastewater
separators, another 95 percent.
429
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Most standards for pumps and compressors state simply that these
must be equipped with mechanical seals or an equivalent control. Several
states specify mechanical seals for rotating pumps and compressors and
packing glands for reciprocating. Two states limit emissions from each
pump and compressor to 2 cubic inches of liquid per 15 minutes; one limits
leakage to 3 drops per minute.
A number of states specify that hydrocarbon waste from the vapor
blowdown system be smokelessly flared or disposed of in an equivalent
manner. One state specifies that these emissions be controlled if they
are more than 10 percent equivalent methane; another state sets a limit
of 50 pounds per day.
Hydrocarbon emissions from catalytic crackers and fluid cokers
are required by several states to be incinerated in a direct flame after-
burner or boiler. One state allows 100 ppra equivalent methane or 8 pounds
of hydrocarbons per hour before controls must be applied; another state
allows 5 tons of hydrocarbons per year.
Other sources of hydrocarbon emissions are mentioned infrequently
in state regulations. Several regulations specify that hydrocarbon
emissions from condensers, hot wells and accumulators be incinerated,
compressed, or equivalently controlled. One standard allows no hydro-
carbon emissions from fuel burning; another specifies 95 percent control
of hydrocarbons from vacuum systems and from process unit turnarounds.
One regulation states that relief valves in pipes over one inch in
diameter must be vented to vapor recovery or disposal, be protected by a
rupture disc, or be maintained by an approved inspection system. In one
regulation, emissions from air blowing must be incinerated at 1400°F for
0.3 second or equivalently controlled.
Effects of State Regulations on the Environmental Impacts of
Refineries—It is difficult to assess the effects of state regulations
430
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because of this great variety. There is no doubt that significant
emission reductions have been achieved over the last ten to fifteen
years by virtue of these regulations. The model refinery used in this
environmental assessment, however, already reflects the control technology
required by the consensus of regulations for existing sources. Some
reduction of the impacts could be expected if the refinery was located
in one of the stricter states.
8.5.2 Federal Regulations and Policies
Federal regulations apply primarily to new or modified sources.
These take the form of New Source Performance Standards (NSPS) and New
Source Reviews required for permitting.
New Source Performance Standards—NSPS specific to refineries are
contained in 40 CFR Part 60, Subpart J. These standards apply to fluid
catalytic cracking unit regenerators, fluid cokers, sulfur recovery units,
and fuel sulfur levels. Subpart D contains standards for fossil-fuel fired
steam generators with a heat input greater than 250 million Btu.
Subpart K includes standards for storage vessels containing petroleum
liquids, but these are outside the scope of this study.
Particulate and Visible Emissions—Federal standards state that
gases from fossil-fuel fired steam generators may not exhibit more than
20 percent opacity except for one 20-Tninute period per hour of not more
than 27 percent opacity. These gases also may not contain more than 0.1
pound of particulate matter per million Btu of heat input from the
fossil-fuel.
Gases from fluid catalytic cracking catalyst regeneration may
not exhibit more than 30 percent opacity, except for one six-minute
average reading per hour. These gases also may not contain more than
1.0 pound of particulate matter per 1000 pounds of coke burn off.
431
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If the gases from the regenerator pass through an incinerator
or waste heat boiler in which auxiliary or supplemental liquid or solid
fuel is burned, excess particulatc emissions may be allowed. These
excess emissions may be 0.1 pound or less per million Btu of heat input
attributable to the added fuel.
Sulfur Emissions—When liquid fuels are used for steam generation,
sulfur dioxide emissions must be no more than 0.8 pounds per million Btu
of heat input. Any fuel gas which is burned in a combustion device must
contain no more than 0.10 grain of l^S per dry standard cubic foot or the
sulfur dioxide emissions from the combustion device must be controlled
in an equivalent manner. Flares for the combustion of process upset
gas or fuel gas from relief valve, leakage are exempt from this standard.
Sulfur dioxide emissions from Claus plants must be limited to 0.025
percent (250 ppm) by volume on a dry basis at zero percent oxygen if
emissions are controlled by an oxidation system (one which converts
emissions to hydrogen sulfide) followed by incineration. If emissions
are controlled by a reduction system not followed by incineration,
emissions from the unit may be 0.030 percent (300 ppm) reduced sulfur
compounds and 0.0010 percent (10 ppm) hydrogen sulfide calculated
as sulfur dioxide at zero percent oxygen on a dry basis. Reduced sulfur
compounds include hydrogen sulfide, carbonyl sulfide, and carbon disulfide.
Carbon Monoxide Emissions—The standards for carbon monoxide
states simply that no gases which contain more than 0.050 percent by volume
(500 ppmv) carbon monoxide may be discharged to the atmosphere from a
fluid catalytic cracking catalyst regenerator.
!*••'
NO Emissions—Allowable NO emissions from fossil-fueled steam
x x
generators vary with the type of fuel used. When gaseous fuel is used,
emissions are limited to 0.2 pounds per million Btu of heat input. For
liquid fuels the limit is 0.3 lb/106 Btu and for solid fuels 0.7 lb/106 Btu.
432
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When different fuels are burned simultaneously, the applicable standard is
determined by proration.
New Source Review—The 1977 Amendments to the Clean Air Act
emphasize the control of atmospheric pollutants from new or modified
facilities by establishing a New Source Review (NSR) process. This is
essentially a federal permit to construct any major emission source. The
review process can take one of two paths depending on whether or not the
source is to be built in an area in attainment of the National Ambient
Air Quality Standards GMAAQS). If so, the Prevention of Significant
Deterioration (PSD) regulations apply. If not, then nonattainment
regulations apply. Frequently both paths must be followed, since attain-
ment is judged on a pollutant-by-pollutant basis.
prevention of Significant Deterioratiori—The PSD review process
is a multilevel examination of the emission levels and air impacts of the
new source. The overall process can best be illustrated by the flowchart
shown in Figure 8-4. It would not be pertinent here to examine in detail
the many applicability criteria which determine the level of review
required. Suffice it to say that if a new or modified refinery (which
is one of the 28 major industry categories) has the potential to emit
more than 100 tons per year of any given atmospheric pollutant, and that
represents a net increase in emissions since 8/7/77, the new or modified
section must demonstrate the use of Best Available Control Technology (BACT)
BACT is defined as the level of emission control which gives the
lowest emissions while taking into consideration the cost of control,
energy efficiency, and technical feasibility. BACT must, therefore, be
determined on a case-by-case basis to evaluate these effects. When an
NSPS is available, this usually forms the minimum criteria for BACT. When
no NSPS exists, then all possible methods of emission reduction must be
catalogued. When one of these methods has been proposed as BACT for the
433
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WES D*Mnnln«liflri
Modified Stationary Sources in PSD Areas
According to Alabama Power Decision
Modfilcntioji
56 Ion E*empi ois
AHHKCVI&flOISi CODE
IU£! - M
olvfl-v
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-------
new source, all methods giving lower emissions must be shown to be
inappropriate in terms of cost, energy impact, or technical feasibility.
Nonattainment Requirements—The requirements for permitting a
source which will emit significant levels of a pollutant for which the
area Is not in attainment of the NAAQS are quite stringent. First, the
source must use the Lowest Achievable Emission Rate (LAER). It must then
offset the resulting emissions by reducing emissions from another source
in the area by a more than equivalent amount. There are additional
requirements relating to the other sources owned by the applicant and to
assuring a net positive air quality improvement, but these are not
pertinent to this discussion.
LAER is defined as the strictest control technology required
for this type of source by any State Implementation Plan (SIP), or the
lowest emissions achieved by any operating source of the same type,
whichever is more stringent unless the owner or operator of the proposed
source demonstrates that such limitations are not achievable. This does
not take cost or any other side effects into account. It also recognizes
the transfer of control technology from one type of source to another, if
technically feasible.
The resulting emissions after LAER must be offset on a
pollutant-by-pollutant basis by reducing emissions from other sources in
the area. For nonreactive pollutants the offset must be from another
source in the immediate vicinity. For NO and hydrocarbons, however,
offsets can be obtained over a broader area. The offsetting emission
reduction must be greater than the emissions from the new source, thus
causing a net positive air quality improvement.
Effects of New Source Reviews on the Environmental Impacts of
Refineries—The effects of the New Source Review process on the environ-
mental impacts of refineries should be significant. Any new refinery
435
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permitted under this system should have much lower emissions than existing
refineries. This would be particularly true in the area of hydrocarbon
emissions, but it would also occur for NO and SC^.
The NSR process will also discourage expansion in nonattainment
areas, where the combined impacts of a heavily industrialized area have
already caused a deterioration in air quality. If an expansion were to
be made in such an area, it could only be done by achieving a greater
than equivalent offset. Thus, the impetus to build new facilities can
provide the impetus to clean up older facilities. The net effect of
these policies should be an improvement in existing air quality.
8.5.3 Potential Regulations and Policies
There are many standards and regulations currently under
consideration that would have a significant impact on refinery emissions.
It would be quite difficult to document all of these since many have not
even been published as proposals at this time. Several examples will be
discussed in this section to illustrate regulatory trends. Caution should
be used in interpreting or applying these regulations since they are only
proposed at this point, and they may be significantly -modified before
being adopted.
State Regulations — Only the new and developing standards for
the Bay Area (San Francisco) and the South Coast (Los Angeles) regions of
California are summarized here. Other regulatory agencies may be similarly
updating their standards. Most of these new and proposed standards are
concerned with the emission of hydrocarbons from refineries.
Two levels of control for SO emissions from catalytic cracker
X "
catalyst regeneration are being considered by the South Coast Region, one
of which is expected to become a standard by .1982. One proposed standard
436
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calls for replacement of the conventional catalyst with a newly developed
catalyst which can reduce SO emissions by 80 percent without additional
controls; the other proposed the addition of alkaline scrubbers for 90
percent control of SO . The South Coast Region also proposes that the
allowable sulfur content of fuels be halved by 1982.
Many of the proposed standards for the Bay Area and South Coast
Regions are concerned with fugitive emissions, an area not emphasized by
present standards. The South Coast Region proposes that by 1980, leak
rates, maintenance schedules, etc. for random hydrocarbon emissions be
established. Pumps and compressors within 3 miles of the control center
would be inspected every eight hours, all others every 24 hours.
The South Coast Region also proposes that natural, gas-fired
control devices such as afterburners must have a stand-by fuel system for
use during natural gas curtailment. By 1980, all relief valves would be
vented to vapor recovery or disposal. By 1982, combustion modification
and/or ammonia injection for control of NO would be required on heaters
and boilers.
A Bay Area Region standard which went into effect in December 1979,
limits valve leakage to 10,000 ppm VOC measured one centimeter from the
leak. It is proposed that this standard be applied also to flanges.
By March 1980, emissions from condensers or vacuum-producing
systems must be incinerated, compressed and added to fuel gas, or controlled
equivalently. It is proposed that emissions from steam ejectors be
similarly controlled.
Also by March 1980, hot wells and/or accumulators associated
with contact (barometric) condensers must be covered and the organic vapors
either incinerated or contained and treated. It is proposed that this stan-
dard apply to the hot wells and/or accumulators associated with all condensers.
437
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Emissions from process vessel depressurizing must, by 1980, be
passed through a knockout pot to remove condensable hydrocarbons, then
incinerated, flared, or compressed and added to the fuel gas. It is
proposed that emissions from process vessel purging be similarly controlled.
Another Bay Area Region standard effective March 1980, is similar
to those in several other states: oil/water separators must have a
solid cover, a floating pontoon or double-deck cover, 90 percent effective
vapor recovery, or other approved control equipment.
Federal Standards—Petroleum refineries are among those
industries for which New Source Performance Standards (NSPS) will be
formulated or updated in the near future. It is expected that within
2-3 years additional standards will be added to Subpart J of 40 CFR
Part 60 and parts of the existing Subpart J may be revised. Additional
standards may concern such emissions as SO from catalytic cracking
A
catalyst regeneration and fugitive emissions.
Effects of Potential Regulations and Policies on the Environmental
Impacts of Refineries—These proposed regulations will tend to bring more
uniformity to the determination of BACT. They do not generally increase
the stringency of measures already required through the New Source Review
process. If other states follow California lead in upgrading their
SIP's, however, the allowable emissions from existing refineries could be
greatly reduced, with a corresponding reduction in the environmental
impacts of those refineries. Such stringency in state regulations may
or may not be warranted, depending on the magnitude of any air quality
problems in the specific state.
438
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8.6 Effects of New and Developing Technology
Although petroleum refining is considered a mature technology
area, it is constantly undergoing a process of improvements. The
environmental impacts of refineries will be reduced in the future through
new developments in both process technology and emission control technology.
8.6.1 Process Technology
Process technology in petroleum refining has continually evolved
to meet the demands of the end-use sector. Some of the current evolutionary
trends in refining include the shift to produce lead-free gasoline,
increased use of hydrodesulfurization to achieve lower fuel sulfur
contents, and a push for greater energy efficiency. Some of these trends
will tend to aggravate emissions while others will reduce them.
The production of lead-free gasoline requires significantly
more processing in units like catalytic reformers, alkylation units, and
isoincrization units. While the units are not major emitters, they do
contribute to fugitive emissions and emissions from combustion sources.
Since there is a decrease in gasoline range yields with this type of
processing, more crude must be charged to maintain the same gasoline
production. This will cause slight increases in emissions across the
board. Much of this effect is now behind us, but a phase-down of gaso.l Ine
pool lead content will cause continued emissions increases.
Sulfur levels in many fuels are being regulated downward. This
will require an increased use of hydrodesulfurization to achieve these low
sulfur levels, which will, in turn, increase the load on Glaus plants and
tail gas treating units. The hydrogen demand will also begin to exceed
that provided by catalytic reforming, and thus require construction of
hydrogen plants. Both of these effects will tend to cause an Increase in
refinery emissions unless countered by more effective control technology.
439
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The trend toward greater use of energy conservation will tend
to reduce the emissions from combustion sources. The recovery of process
heat and the use of intrinsically more efficient processes will reduce the
heat required from process heaters and steam boilers. Since the emissions
from combustion equipment are proportional to the fuel burning rate, this
should result in an emission reduction.
8.6,2 Emission Control Technology
New and improved emission control technology will continue to
appear in petroleum refining. Significant reductions may be achieved by
application of technology, such as covers for API separators, scrubbers
for flue gas from fluid catalytic cracking, and combustion modifications
to reduce NO . These effects could be complemented by progress on
developing technologies like the fluid cracking catalyst which adsorbs
SO, from the regenerator.
X
One area with great potential for improved technology is in
fugitive emission control. The manufacturers of seals, packing, and
gaskets for process equipment have designed their products to meet the
users needs. Up until now, those needs have been to limit product loss
and maintain safe operation. No one was aware or concerned about "low
level" fugitive vapor leaks which could not be detected visibly. Fugitive
emission regulations will provide the incentive to develop more effective
seals, packing, etc., and will result In lower emissions and lower costs
for monitoring and maintenance programs.
440
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455
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10.0
CONVERSION FACTORS
To Convert From
Btu
bbl
gal
ton
Ihs
cm
ft3
psi
g/gal
Btu/bbl
kWh/bbl
]b/bbl
lb/10G Btu
grain/ft3
gal/1.0Gft3
gpm
lb/100n gal
To
kcal
I
I
kg
kg
in
m3
kg/cm?
8 ^
kcal/il
kWh/£
kg/£
g/Mcal
g/IT.3
Jt/106m3
raVhr
mg/£
Multiple By
0.252
159.0
3.785
907.2
0.454
0.394
0.0283
14.223
0.264
0.0016
0.0063
0.0285
18.0
2.29
133.7
0.227
119.8
456
-------
TECHNICAL REPORT DATA
(Please read Instruction! on the reverse before completing!
1. REPORT NO.
EPA-600/2-80-075a
3. RECIPIENT'S ACCESSION-NO.
22525 3
4. TITLE AND SUBTITLE
Assessment of Atmospheric Emissions from
Petroleum Refining: Volume 1. Technical Report
B. REPORT DATE
April 1980
6. PERFORMING ORGANIZATION CODE
7. AUTHOFttS)
R.G.Wetherold and D. D. Rosebrook
B. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORGANIZATION NAME AND ADDRESS
10. PROGRAM ELEMENT NO.
Radian Corporation
P.O. Box 9948
Austin, Texas 78766
1AB604
11. CONTRACT/GRANT NO.
68-02-2147, Exhibit B
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; 3/76-6/79
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES IERL_RTP project officer is Bruce A. Tichenor, Mail Drop 62,
919/541-2547.
6. ABSTRACT
rep0rt gives results of a 3-year program to assess the environmental
impact of petroleum refining atmospheric emissions. Fugitive and process emissions
were extensively sampled at 13 refineries in the U.S. Nonmethane hydrocarbon
emission rates were measured from valves, flanges, pump and compressor seals,
process drains, relief valves, cooling towers, and wastewater treating units. Flue
gases were sampled from fluid catalytic cracking units, sulfur recovery processes,
process heaters, and other process units. Their compositions were determined. .
Organic species in liquid streams and emitted vapor were identified and quantified.
Sampling and analytical methods are described. Emission factors for major fugitive
emission sources were calculated. Nomographs were developed showing the relation-
ship of hydrocarbon concentrations at leaking sources (screening values) with the
leak rates from the sources. Existing and available emission control technologies
for refinery emissions sources are evaluated. Control methodologies are recommen-
ded for individual emission sources. The impact of refineries on the surrounding
atmosphere and population is estimated.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b. IDENTIFIERS/OPEN ENDED TERMS
c. COSATi Field/Group
Pollution
Petroleum Refining
Assessments
Hydrocarbons
Organic Compounds
Sampling
Analyzing
Pollution Control
Stationary Sources
Nonmethane Hydro-
carbons
13B
13H
14B
07C
3, DISTRIBUTION STATEMENT
Release to Public
19 SECURITY CLASS (TMs Report)
Unclassified
21. NO. OF PAGES
20 SECURITY CLASS
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