-------
»
S>
2
PJ O
t>
f-< »W
O
,-1 •*
>, «
^ 00
3 OJ
-> 0-
>4
DJ
§
s
CO
c
a,
CO
s°
M
ft
a
\£
l/"1
•
es
f-H
~^
OJ
0
r-< U
c
a<
2 >"
d
o
o
^^
14
UH
^»
- w
m
p-i
*
i-4
•n
— i
-4
—<
eating
H A-
01 >
Su
<~4
• f-l
«
H
x"s
CO &
^^ *>^
i a
*-s a
< w
W
ID
'—• U
« v
~.S
^>.
<
•*^
u
0)
s
M
to
c
•I-*
u
O
$
CO
rt
O
•a
a>
•H
b
(
1
j
c
Current
TU..~..~U
4
C
0
I
\
u
C U
CD O
t-t
a.
<*-<
r-4
3<
»
4 l-l -i •
^WJ:
& 8
•H C
(0 >--
O 0> t)
O to C>
£ °s
to ij
o o o
>^ B
e '->
11 K^
u
w cs^5
>i O O
n u 5:
x_^
u
C
to
-<
Ll
1 8-S
a u> j
-» r^o
S X £
J) »-.
3 O
3 Cu
^ u O
3 g.3
>»
J U
! --J -->
y (> Q
j n u,
•i n. o
555
1 ..
Si
4J
u
a. a 05 co
W 00) 0)
rf J i -• -< t i ^-. i ||
3 w n ! ! 5 ! !
ol •* ° M
< JITOCM; iu^ • i i
™ 1 1 in r- I i esi i ! !
J 1 1 n vo 1 i « i j j
- 1 ! i i ! -13 I i 1
>. . •* O f^.
y 00 CM • p
3 r» S
J ! «*> j ' f o i i i
i •' ! £. i {
: «
» « e
; ii-*oi ii°i it
3 l^>«l 1 ! u | j!
- ' ' i 1 1 QJ 1 II
J 1 ^
ll*oni 1101 ii
i : i^-i ! isi i i
' i i2"! ig I | i
U 18
S3 g
i I to eg i i 03 i i •
! i S d ! ! s . ! i j
in
5 ! os c! i ! e! Si
> 1 OT CO 1 | UJ M g j
I illi ill Ii
I 1 ! ! i i 1 1 i i
o <— * o ***
CO CQ
C^ -H .H
I i ... r-l W f* «9 .
! i i 1 i i : » « i i
O OOO 60
O -H O -H
, m M o M
!!!!! ICMOJCIO!!
i i ! ! ! ! ^ 5 S ! ,'
i i i i i i 1 1 i i
ggggg si 1 ^g
vo oo o o o ( ( S S
o -. cj eo o j j j ^ o
10 o
<"> o o ". vo
o i * o j { j ! ^ i
§§§§§ •§§ § §g
iAvo(^CTso\ as, o-^
fjcMtNc-gc-jcgtMesi « md
r> r*~ r^ r^. r^ r^ r^ r>. r*» r^ i^
^ /•' S
6-61
-------
-------
SMALL SULFUR RECOVERY UNITS
ONSHORE SOUR GAS PRODUCTION FACILITIES
APPENDIX H
-------
SECTION 1
DESIGN BASIS
j-
o
INTRODUCTION
This study was prepared for TRW to assist the U.S. Environmental Protection
Agency in promulgating New Source Performance Standards for Onshore
Production Facilities. Specifically, this study is to provide data to enable
determination of cost-effectiveness for different sizes of small sulfur
recovery units with feed acid gases of low H2S content.
This report provides investment costs, direct operating cost data, process
descriptions, process flow diagrams, and atmospheric emissions for the
following 12 cases:
Case
No.
1
2
3
4
5
6
7
8
9
10
11
12
Sulfur
Feed Rate
(LT/D)
0.5
0.5
0.5
2.0
2.0
2.0
2.0
2.0
2.0
5.0
5.0
5.0
Mol %
H2S in
Acid Gas
2.0
5.0
12.5
2.0
5.0
12.5
2.0
5.0
12.5
2.0
5.0
12.5
Sulfur Recovery Process
Selectox Two-Stage
Recycle Selectox Two-Stage
Recycle Selectox Two-Stage
Selectox Two-Stage
Recycle Selectox Two-Stage
Recycle Selectox Two-Stage
Selectox Three-Stage
Recycle Selectox Three-Stage
Recycle Selectox Three-Stage
Selectox Three-Stage
Recycle Selectox Three-Stage
Recycle Selectox Three-Stage
For explanations of terminology and abbreviations used, refer to
Definitions in this section.
H-2
-------
DESIGN CRITERIA AND ASSUMPTIONS
Listed below are assumptions used for design criteria and cost estimating for
this study:
tr
(1) Barometric pressure is 14.7 psia.
(2) Acid gases are available at 120°F and 24.7 psia, saturated with
water, and contain 0.5 vol% methane (wet basis) maximum.
(3) Investment costs in Table 2-2 are based on February 1983 Gulf Coast
prices and include the complete plants through the catalytic
incinerator and 100-ft-high stack.
(4) The plants use a heating medium for the preheaters and reheaters and
a cooling medium for the sulfur condensers. Excess heat is removed
from the cooling medium by a cooler, but can also be recovered by
circulating it through a reboiler on the regenerator in the adjacent
amine unit. For these small plants, such a reboiler has not been
included as the economics may be marginal.
H-3
-------
DEFINITIONS
The following list provides definitions, terminology, and abbreviations used
in this report:
Acid Gas; The gas containing H2S (and C02> resulting from treating of
sour natural gas. Also contains small amounts of hydrocarbons and water.
Catalytic Incineration; Process by which sulfur compounds are catalytically
oxidized to S02-
Glaus; The name of the gas phase reaction where 2 moles of H2S combine
with 1 mole of S02 to form 3 moles of sulfur and 2 moles of water.
End-of-Run; After a certain period of operation, the activity of a
catalyst declines to a point where it is economical to shut down and replace
it with fresh catalyst. End-of-run is defined as that point when the percent
recovery has declined to a specified value. For this study, average lives of
5 years for the Selectox catalyst and 3 years for the alumina catalyst have
been assumed. The S02 emissions in the tables in this report are based on
end-of-run recoveries. The LT/D of sulfur recovered in Table 4-2 are average
during run, calculated by averaging the start-of-run and end-of-run
recoveries.
Gas Components; H2S Hydrogen Sulfide
S02 Sulfur Dioxide
02 Oxygen
H-4
-------
N£ Nitrogen
C0£ Carbon Dioxide
H20 Water
**
CH4 Methane
Lb mol/hr: The pounds per hour divided by the molecular weight of the
component.
LT/D; Long tons (2,240 pounds) per day.
MM; Millions.
Selectox; A catalyst developed by Onion Oil Company of California which
oxidizes H2S directly to elemental sulfur and in a temperature range
substantially lower than required for uncatalyzed oxidation.
Sour Gas; Natural gas containing H2S. When the H2S and usually the
C02 are absorbed from the hydrocarbons by a suitable solvent in any of the
various treating units, and then stripped from the solvent, the stripped gas
containing the H2S and C02 is called acid gas.
Tail Gas; Exit gases from a sulfur recovery unit.
Vol ppm or ppmv; The parts per million of a component on a volume basis.
H-5
-------
FEED GAS COMPOSITIONS
The feed gas compositions are provided in Table 1-1. The gases are saturated
with water at the conditions stated in Design Criteria and Assumptions. These
are representative, although the water and hydrocarbon contents vary from
plant to plant depending on design and operation of the upstream facilities.
H-6
-------
lf\
m
eo
in
m
CM
00
co
oo
CM
•
NO
in
»
CM
ON
CM
CM
oo
in
CO
CM
CO
in
co
CO
vO
in
m
c
O
CO
ON
CM
ON
vO
O
st
00
m
vD
m
o
CD
a
(0
<§
•o
Q)
Q)
fc,
in
in
CM
m
•
o
o
•
m
CO
«t
m
m
m
CM
oo
•
m
vO
in
in
CM
in
CM
m
m
CM
r-
m
vO
00
m
m
<-4
•
O
•a-
so
m
o
CM
00
co
00
O
»-4
•
CM
CM
in
oo
O
CM
CO
CM
<~l
•
CM
CO
CM
fs.
0) 0)
O
•
CM
o
•
CM
CM
00
•
m
m
eo
•
CM
NO
CM
vO
\o
en
o
CM
ON
O
ON
CM
m
*
o
\o
vO
CO
in
NO
-a-
CM
m
CM
a
I
CO
01
00
to
u
en
CM
33
CM
8 g
o
ff
H-7
-------
SECTION 2
SUMMARY OF RESULTS
*-
The compositions of the exit gases at: end-of-run are given in Table 2-1, and
the sulfur recoveries for start-of-run and end-of-run are shown in Table 4-2,
Section 4.
Total installed costs are listed in Table 2-2. It is evident from observing
the investment costs of the 2 LT/l5 sulfur input cases that the differential
between two-stage and three-stage units becomes smaller as the gas gets
richer in H£S.
A discussion of service facilities that might be required is provided in this
section.
Information necessary for calculating operating costs is shown in Section 4.
H-8
-------
c
1
0
4)
c
W
1u
.C
rH
O
"
.0
rH
CO
CO
O
W
•H
JT
U-l
o
e
o
>H
4J
•H
CO
g.
a
5
i
^ *•
CM i
1 CN1
^ rH
gj •"•*
tfl r_.
H C
rH
jj
o
H
a?
."
CD1
2
CM
O
ffi
CM
cn
eu
cu
H
«-l CO
o cu
00
• rt
O 4J
z cn
0 CO
•H CO
0
cn
5C -H
a .u Q
<£ a<;
a c tJ
CO M s~/
cu
CO •
« o
o a
CO Is- rH
t*» m !•»
r-- co in
r- co •-<
^D lO ^D
CO i-l O
O O O
•—i 1-4 ON
•a- -3- CM
^Pi ^^ ^^
vO CM
-H O OO
vO O vO
-a- -a- co
f"» rH 00
•— 4 i— 1 O
O O O
rH CO ON
00 vO CO
vO CO CM
CO CM CM
000
M ^
0 0
4J 4J
y y
cu cu
cu eu
cn cn
X
o cu cu
y y y
•H y y
eu cu cu
CO S& f&
CM CM CM
in
e
CM in CM
t— «
in m m
o o o
-H CM CO
CO ON CO
ON CM 00
o ~> >*>
rH y y
cu eu eu
cn oi cA
CM CM «M
in
41
CM m CM
*-H
O O 0
CM CM CM
•a- m vo
r-t CM U1
ON CO ON
ON CO T-H
O CO vO
CO —<
vO 00 CO
•a- m CM
~4 O O
in in r^
vO vO i^
i— < *—< r^
vO O CO
CM rH
CO ON CM
VO r-l O
i>. in >>>>
rH y y
cu cu eu
co pi oi
CO CO CO
in
•
CM m CM
o o o
CM CM CM
f-» CO ON
OO •-! 'ON
f~» CO 00
st co -a-
r-- co m
C-. CO rH
. >*
rH y y
eu eu cu
cn «! pi
CO CO CO
in
*
CM m CM
O 0 O
in in in
o —< CM
i™4 i—l i-H
H-9
-------
Table H-3 - Total Installed Costs
(Table 2-2)
Case
No.
1
2
4
5
• 7
8
10
11
12
Sulfur
Input
(LT/D)
0.5
0.5
0.5
2.0
2.0
2.0
2.0
2.0
2.0
5.0
5.0
5.0
'% H2S in
Acid Gas
2
5
12.5
2
5
12.5
2
5
12.5
2
5
12.5
No. of
Stages
2
2
2
2
2
2
3
3
3
3
3
3
Type
Selector
Recycle Selectox
Recycle Selectox
Selectox
Recycle Selectox
Recycle Selectox
Selectox
Recycle Selectox
Recycle Selectox
Selectox
Recycle Selectox
Recycle Selectox
^ '•! Ill |ll !•
$MM
~" "
1.71
1.60
1.53
2.17
1.95
1.80
2.51
2.20
1.98
3.32
2.69
2.36
H-10
-------
Table H-4 - Cost of Initial Charge of Catalysts
(Table 2-3)
Case
No.
1
2
3
4
7
9
10
11
12
Sulfur
Input:
(LT/D)
0.5
0.5
0.5
2.0
2.0
2.0
2.0
2.0
2.0
5.0
5.0
5.0
% H2S in
Acid Gas
2
5
12.5
2
5
12.5
2
5
12.5
2
5
12.5
No. of
Stages
2
2
2
2
2
2
3
3
3
3
3
3
Type
Selectox
Recycle Selectox
Recycle Selectox
Selectox
Recycle Selectox
Recycle Selectox
Selectox
Recycle Selectox
Recycle Selectox
Selectox
Recycle Selectox
Recycle Selectox
Cost
($)
8,800
4,300
2,600
35,200
17,100
10,200
37,000
17,800
10,500
92,400
44,400
26,000
H-ll
-------
SERVICE FACILITIES
With regard to offsites , only two utilities are required: (1) natural gas,
which is readily available, and (2) electrical power, which is available at
most locations.
For very remote locations where electrical power is not available, gas engine
generators can be used. The small sulfur recovery plants use only 50 to
100 kW, and the entire adjacent facilities would use from 500 to 1,000 kW.
The investment cost and fuel for gas engine generators of this size are as
follows:
Generator Size
Item
Investment Cost ($)
Natural Gas (MMBtu/hr)
500 kW
430,000
5.5
1,000 kW
830,000
11.0
The cost of the natural gas, assuming $5.00/MMBtu, is equivalent to
$0.055/kWh.
Since power generation would have to be installed for the rest of the
facilities, the incremental cost over purchased power for the small amount of
power required for the sulfur recovery unit would not be a significant factor
in the total cost of sulfur recovery.
Molten sulfur can be hauled away in tank trucks for sale, or poured into
blocks and stored indefinitely to be broken up later and hauled away as solid
•ulfur. Costs in this study include a simple sulfur loading rack but no other
transportation facilities.
H-12
-------
RECOMMENDATIONS AND SUGGESTIONS
While this study was based on very weak gases, from 2% to 12.5% H2S, the
Recycle Selectox process, works very well on acid gases containing up to 100%
H2S. The recycle system merely increases in size, but the cost is still
less than Glaus-type sulfur recovery units and does not involve boiler
feedwater treatment and steam boiler operations. It has the additional
advantage of pushbutton operation; in response to a power failure or other
shutdown causes, the plant can be stopped and restarted by pushing the
necessary buttons. These factors are mentioned to emphasize that the process
is practical and economical for gases stronger in H2S than those covered in
this study.
The total installed costs for the sulfur recovery units seem to levfel out as
the plants get smaller.
No suggestions for further study are apparent at this time.
H-13
-------
SECTION 3
PROCESS DESCRIPTION
A catalyst called Selectox is used for sulfur recovery from gas streams
containing H2S. This catalyst selectively oxidizes H2S to sulfur with air at
low temperatures without forming 803 or oxidizing either hydrogen or light
hydrocarbons. The process is entirely catalytic, eliminating the need for a
thermal reaction furnace and resulting in a simplified Claus process.
One-third of the H2S is oxidized catalytically with air to form S02, which
then reacts with the remaining H2S to form elemental sulfur according to the
principal Claus reactions.
H2S + 3/2 02-
2H2S + S02-
•S02 + H20
—3S + 2H20
The once-through process is called Selectox for acid gas feed streams
containing less than 5% H2S. For feed gas streams containing 5% H2& or
greater, a recycle stream lean in H2S is used to limit the temperature rise
from the exothermic reactions to a reasonable maximum considering the Claus
chemical equilibrium and equipment metallurgy. This process is called Recycle
Selectox.
H-14
-------
The Selectox two-stage process illustrated in Figure 3-1 has a Selectox stage
and one Clans stage whereas the Selectox three-stage process in Figure 3-2
has a Selectox stage and two Glaus stages. The Recycle Selectox two-stage and
*•
three-stage processes in Figures 3-3 and 3-4 are identical to Figures 3-1 and
3-2, respectively, except for the addition of a blower to recycle a portion
of Condenser No. 1 effluent back to Reheater No. 1.
H-15
-------
oil
ool
ul
Oil
CD
CO
O)
H-16
-------
REHiATgR
KO. 1
t*
^
k "*
CONVERTER
NO. 1
fSEi-ECTOKS
-ufl
1
i
i§
is
s@
n
il
ie
CD
CO
Q)
CJ
O
CU
w>
ed
I
CU
Q)
H
O
4J
O
CU
,-!
0)
CO
OJ
M
3
M
•H
Pm
-------
— *•
>i|
8
mmmm^mmmmmmm
— —
EC
IU
»- (M '
ii
Ul
E
tT
K
IU
ii
Ul
c
1
4
a. s
u, X
•• C
fT
w
w
0)
o
o
I
o
£
O
Q)
01
t-f
o
o
OJ
3
00
•H
en
I
(U
3
•H
k'
>z3
i I
tT
5
ee
S
Ul
Ul
£
TT
Off
itfO
Y>
i
s
ec
ui
1
Is
55
IU UJ
£S
O (9
zz
-------
RSHEATEH
NO. 1
t*
i
km
e s
S-I
SS in
» * J
§ 1
ess
I
ie
CO
CO
01
o
o
cn
to
-M
CO
OJ
OJ
JC
I—
X
o
+J
X
O)
to
eu
r— -
U
>5
U
OJ
1
s
,
C7>
H-19
-------
SECTION 4
' DIRECT OPERATING COST DATA
The utilities requirements and the annual catalyst costs are provided in
Table 4-1.
The sulfur recoveries as a percentage at the start-of-run and end-of-run and
as average LT/D are shown in Table 4-2.
H-20
-------
CO
AJ
CO
8
AJ
CO
>N
n
CO
1
CO
•H
AJ
•H
•H
S
1
LO '-<
1 I
3T
* CM
w TO
O AJ
2 co
C CO
•H «
CO
tr^S
y
IM x-s
JW ^^
*is e »j
CO M v
0)
CO «
<3 S
ooo
CM 00 CM
oo oo m
•H
f^ r^« r^^
vO CM -H
ooo
•* \£> m
X X
0 0
> t XJ
O 0
d)
Selectox
Recycle Sel
Recycle Se]
CM CM CM
m
e
CM in CM
(•H
ooo
CM CM CM
« CO '-4
ON vO CO
ON 00 ON
X X
AJ °
y y
0) 0)
Selectox
Recycle Sel
Recycle Sel
co co to
"7
CM in CM
ooo
m m m
O •-« CM
1— 1 "H •*
H-21
-------
05
0)
M
O
>
o
w
J5J
PS
3
UH
i— 1
3
CO
1
CM
VO I
It
(U
S?S
0) H
us
(3
S
0 p
•o ^
c
w
i
o /"N
^p
4J v«x
CO
0)
a
£4
in oo
O 0)
bp
• to
O *J
SB CO
C ca
•H A
«
CO
O
X <
3 J-» S
3 C n4
CO M ^
(U
09 •
0) O
U SS
ON CM in
en <»• •*
000
en m \o
OO vo vo
-3- I-H m
r-. oo oo
00 O vO
vo ON en
O I-- CM
OO OO ON
X X
0 0
•U JJ
a u
0) 0)
T-l rH
(1) (U
CO CO
X
O QJ
U O O
i-l O O
0) OJ 0)
w ps erf
CM CM CM
in
0
CM in CM
m m m
o o o
— H CM en
vO O 00
in r-. r~-
en in vo
00 vO vO
-sr i-i in
r**> OD oo
«0 0 VO
vo ON en
CO ^^ CM
OO OD ON
X X
0 0
0 0
03 > >N
i-l O O
0) m 01
CO Cri tA
CM CM CM
in
•
CM in CM
000
CM CM CM
*^ iO ^D
.-i in en
VD !•«- 00
CM O O
ON CD vO
vo -* r*.
r- oo oo
^ O CM
VO ^* v*H
en ~* in
OO ON ON
X X
0 0
AJ 4J
y y
N >-.
i-i y y
a) o> a>
CO Cd K
en en en
'*,
m
»
CM in CM
O O O
CM CM CM
t-. 00 ON
-H ON f.
o en m
^^ ^J" ^^
CM O O
ON O vO
vO , >N
i-i y y
0) 0) 0)
en en en
in
•
CM m CM
^•H
o o o
in m in
O ~* CM
H-22
-------
OPERATING LABOR AND MAINTENANCE
For operating labor, assume 0.75 of an operator's time per shift and
0.25 of a supervisor's time per shift. The actual requirement will be
somewhat less because these units need little operator attention.
Annual maintenance will be on the order of 3-1/2% of investment, including
1-1/2% for labor and 2% for investment.
Table H-7 presents annualized costs for 12 cases of sulfur feed rate/acid
gas ELS concentration/Recycle Selectox process combinations.
H-23
-------
CO
3
M
*-- to
g§
PR E~*
PL, CO
5 tS
10 O
O
O PH
CO X
w o
3S
O W
I_J
CM ra
••H CO
yy* Js3
O »J
PM o
to G
H W
co o$
o
Q H
i S
M C§
H-l £"*
^d 25
S3 &3
!S O
o >,
° •> «• *l *
cj\ co co in
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverie before completing)
(.REPORT NO.
EPA-450/3°82-023a
3. RECIPIENT'S ACCESSION NO.
». TITLE AND SUBTITLE
S02 Emissions 1n Natural Gas Production Industry
Background Information for Proposed Standards
6. REPORT DATE
November 1983
6. PERFORMING ORGANIZATION CODE
AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
>. PERFORMING ORGANIZATION NAME AND ADDRESS
Office of A1r Quality Planning and Standards
U.S. Environmental Protection Agency
Research Triangle Park, N.C. 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
12. SPONSORING AGENCY NAME AND ADDRESS
13. TYPE OF REPORT AND PERIOD COVERED
Director for A1r Quality Planning and Standards
Office of Air, Noise, and Radiation
U.S. Environmental Protection Agency
Research THanale Park., N.L
14. SPONSORING AGENCY CODE
g
>7
EPA/200/04
15. SUPPLEMENTARY NOTES This report discusses the regulatory alternatives considered during
development of the proposed new source performance standards and the environmental
and economic impacts associated with each regulatory alternative.
16. ABSTRACT
Standards of performance for the control of SOa emissions from natural gas
sweetening operations are being proposed under Section 111 of the Clean Air Act.
This document contains background information and environmental and economic
impact assessments of the regulatory alternatives considered in developing the
proposed standards.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Held/Group
A1r Pollution
Pollution Control
Standards of Performance
Sulfur Dioxide (S02)
Natural Gas Production
Air Pollution Control
13b
18. DISTRIBUTION STATEMENT
Unlimited
18. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
436
20. SECURITY CLASS (Thispage/
Unclassified
22. PRICE
EPA Perm 2220-1 (Rev. 4-77) PREVIOUS EDITION i« OBSOLETE
-------
-------
-------
-
83
9L
§s
o
c
O Q.
i w
m
!
I
Q)
a
-------