United States
Environmental Protection
Agency
Air and Energy Engineering
Research Laboratory
Research Triangle Park NC 27711
Research and Development
EPA/600/S7-85/029 Jan. 1986
Project Summary
Alkaline and Stretford
Scrubbing Tests for H2S
Removal from In-situ Oil Shale
Retort Offgas
H. J. Taback, G. C. Quartucy, and R. J. Goldstick
Two mobile pilot-plant scrubbers
(one alkaline, the other Stretford) were
evaluated for removing reduced sulfur
compounds from the offgas of an in-
situ retort at Qeokinetics. The alkaline
scrubber efficiency varied inversely
with selectivity: at high solution con-
centration in the tower, 94 percent re-
moval was achieved at a selectivity of
9; and at low concentration in the ven-
turi, the removal was 50 percent and
the selectivity was 79. The Stretford
achieved 99+ percent removal with the
packed tower and 95 percent with the
venturi. A computer model of the alka-
line scrubber based on the penetration
theory was developed and agrees well
with the observed performance. Based
on this model, it appears possible to
design an alkaline scrubber system in-
cluding a Claus plant which can achieve
95 percent H2S removal at a selectivity
of 37.
This Project Summary was devel-
oped by EPA's Air and Energy Engineer-
ing Research Laboratory, Research Tri-
angle Park, NC, to announce key
findings of the research project that is
fully documented in a separate report
of the same title (see Project Report or-
dering information at back).
Introduction
Removing hydrogen sulfide (H2S) and
other reduced sulfur compounds (car-
bonyl sulfide, carbon disulfide, mercap-
tans, thiophenes, etc.) from shale oil re-
tort offgas with a wet scrubber requires
a process that will selectively react with
the sulfur compounds and react as little
as possible with the carbon dioxide
-------
with scrubbing reduced sulfur
compounds in the presence of
high C02 concentration.
2. For the Stretford Pilot Plant
• Duplicate on retort gas the 99+
percent removal efficiency at-
tained in a previous test of offgas
from a coal gasifier.
• Upon achieving that, explain the
low removal efficiency on the
1982 test at GKI by deliberately
introducing upsetting changes in
the plant chemistry, then return-
ing to the 99+ percent perform-
ance.
Site and Process Description
The GKI retort offgas is brought to the
surface for processing where it is
treated in four steps, shown schemati-
cally in Figure 1, before it is discharged
to the atmosphere: (1) gas passage
through a condenser/demister, up-
stream of the two blowers; (2) ammonia
absorption; (3) sulfur recovery; and
(4) incineration. Steps 2, 3, and 4 are
performed in series, with the treatment
units arranged so that the desired treat-
ment configuration can be obtained by
bypassing one or more process steps.
Expected operations during the scrub-
ber test were to bypass the ammonia
absorber and treat the gas in the sulfur
recovery unit and the incinerator. A
maximum of 10 Sm3/s of gas at a maxi-
mum temperature of 82°C can be
treated in the GKI gas processing opera-
tion.
Findings
Alkaline Scrubber
The alkaline scrubber system was op-
erated using both the tray tower and the
venturi as the gas/liquid contactor. After
relocating the main blower, the equip-
ment performed satisfactorily.
The alkaline scrubber was operated in
a simple blowdown process where the
alkali solutions were mixed to a specific
concentration and fed into either the
tray tower or venturi contactors. In a
commercial process unit, the scrubber
solution would be cycled through a
stripper where the absorbed H2S and
C02 would be removed. Then the solu-
tion would be returned to the original
mixing tanks and recycled into the con-
tactor. No significant alkali addition
would be required in that case. Since a
stripper was not included as part of the
EPA pilot plant, the scrubbing solution
was used on a once-through basis, then
discharged to the GKI pond.
The experimental results for the alka-
line scrubber are summarized in Table 1
and Figure 2. The runs were conducted
using alternately the tower then the
venturi at the same solution concentra-
tion. Three different solution concentra-
tions were used for each alkali except
for the last four runs (No. 31-34) where
only the tower was used to make two
high concentration runs for both NaOH
and KOH.
To analyze these data, a computer
model of an alkaline scrubber was de-
veloped employing the comprehensive
penetration theory. Penetration theory
treats the gas/liquid mass transfer to al-
low contact time to be a significant fac-
tor. Other models (e.g., the two-plane
theory) have implicit assumptions of
equilibrium and cannot account for the
contact time difference between a tower
and a venturi. The results predicted by
the penetration theory agree with the
experimental results.
Based on the experimental results
and the computer model, an alkaline
Atmosphere
Condenser/
Demister
Retort
Retort
Offgas'
I - 1 I - «*-
I I .X'^X
1 r\o)— .
Condenser/
Demister
EPA
Alkaline
Scrubbei
EPA
Stretford
Plant
Figure 1. Pilot plant installation in the Geokinetics process.
2
-------
scrubbing system design concept is
suggested which could achieve an H2S
removal efficiency of 95 percent with a
selectivity approaching 40. This is a
two-stage scrubber with a venturi-
contactor first stage and a tray-tower
second stage. The first stage removes
50 percent of the H2S in a highly selec-
tive manner. The second stage removes
90 percent of the remaining H2S at a
lower selectivity. Summarized, these
performance values are:
TWO-STAGE ALKALINE SCRUBBER -
CONCEPT I
ALKALINE TOWER SCRUBBER -
CONCEPT II
Stage No
Contactor
Selectivity
Removal
Efficiency, %
1
Tray
Tower
40
90
II
Tray
Tower
40
90
Combined
23
99
Stage No
I
II Combined
Contactor Venturi Tray
Tower
Selectivity 110 40 37
Removal
Efficiency, % 50 90 95
Another concept, employing a two-
stage tray tower scrubber which results
in a higher removal efficiency but a
lower selectivity, is summarized as:
This two-stage tray tower scrubber
can be combined into a single tower of
double length.
The alkaline scrubber showed little re-
moval of the organic sulfur compounds.
This is similar to previous results re-
ported in the literature.
Stretford Plant
The Stretford operated for over 200
hours. Table 2 gives available measure-
ments of H2S removal efficiency and
pertinent process data taken in conjunc-
tion with the removal efficiency. For 140
hours, the plant operated with a venturi
contactor, modified from that used in
previous tests in that the throat area
could be adjusted to handle variable gas
flow rates. In this test, the throat was
Table 1. Summary of Alkali Scrubbing Results
Contactor
Venturi
Venturi
Venturi
Venturi
Venturi
Venturi
Venturi
Venturi
Venturi
Tower
Tower
Tower
Tower
Tower
Tower
Tower
Tower
Tower
Tower
Tower
Tower
Tower
Alkali
NaOH
KOH
NaOH
KOH
NaOH
KOH
NH4OH
NH4OH
NH4OH
NaOH
KOH
NaOH
KOH
NaOH
KOH
NH4OH
NH4OH
NH4OH
KOH
NaOH
KOH
NaOH
OH~ Cone.
gmole/liter
0.012
0.012
0.023
0.023
0.045
0.046
0.049
0.29
2.0
0.012
0.012
0.023
0.023
0.045
0.046
0.049
0.29
2.0
0.89
1.25
1.79
2.5
Removal
Efficiency, %
52
53
48
48
70
71
60
62
67
52
54
54
59
83
88
64
91
93
94
93
92
94
Measured
Selectivity8
79
71
60
51
84b
21
71
56
11
52
43
41
49
36
41
29
29
9
N/AC
N/A
N/A
N/A
Run
No.
21
28
24
30
19
26
15
17
13
20
27
22
29
18
25
14
16
12
31
33
32
34
'Selectivity is a measure of the preferential removal of H^ over CO2, taking into account the
relative difference in concentration between the two gases. In this report, selectivity is the ratio
of percent removal of H^S to percent removal of CO2.
bData are suspected to be erroneous.
"Selectivity value was not available because the spent scrubbing solution was not analyzed.
adjusted to the smallest throat area, 7.1
in. (18 cm), and held constant during
most of the testing.
The maximum H2S removal efficiency
measured while using the venturi alone
was 95 percent, which was maintained
only briefly. Over the period of opera-
tion with this contactor alone the re-
moval efficiency averaged 80 percent. A
brief attempt was made to experiment
with increasing the venturi throat area.
When no effect on removal efficiency
was observed, the throat area experi-
ment was discontinued.
Because of the failure of the plant to
achieve the 99+ percent removal effi-
ciency objective observed in the previ-
ous coal gasifier test, a field-fabricated,
packed-column contactor was added in
series with and downstream of the ven-
turi. This device increased the removal
efficiency to the 99+ percent range dur-
ing its period of operation. Because of
the makeshift nature of this field modifi-
cation, there was no instrumentation to
measure the flow rate of the scrubber
liquid through the tower. Thus, it was
not possible to optimize liquid distribu-
tion between the venturi and the tower.
Conclusions
Based on the findings reported here,
the following conclusions were
reached:
1. For shale oil retort offgas similar in
composition to that from the GKI
process, the alkaline scrubber, in
combination with a stripper and a
Claus plant, could be a viable
means of H2S removal. This over-
all conclusion is based on the fol-
lowing conclusions.
2. For GKI-type process offgas and
based on these tests, the perform-
ance of an alkaline scrubber with a
tray tower contactor similar to that
in the EPA pilot plant can achieve
an H2S removal efficiency of at
least 90 percent with a selectivity
of approximately 30. Under the
same conditions a single venturi
contactor in place of the tray tower
would remove only 50 to 60 per-
cent H2S, but with a selectivity of
70 to 80.
3. Based on the computer model de-
veloped to analyze these test re-
sults, the removal efficiencies and
selectivity above are applicable to
offgas with lower H2S concentra-
tions than found at GKI. This sug-
gests a concept of multiple scrub-
bing actions to increase the H2S
-------
removal. Because this increased
removal efficiency is accompanied
by a reduced selectivity which
could present a problem for the
Claus plant, the cost effectiveness
of this concept requires a design
study.
4. Based on a three gas component
(H2S, NH3, and C02) analysis by the
computer program, the principal
reactant for the H2S in the retort
offgas is the NH3 in that same off-
gas. In that NH3 is present in the
GKI offgas in similar molar quanti-
ties to that of the H2S, the scrubber
performance observed on these
tests may not be applicable to re-
tort offgas with little or no NH3.
This suggests that water with just
the NH3 in the gas stream would be
an effective scrubbing agent.
Scrubbing in this manner would
certainly improve the selectivity;
but, the effect on removal achiev-
able is uncertain.
5. The alkaline scrubber removal effi-
ciency and selectivity seemed to
have little dependency on the al-
kali used. This is consistent with
the above concept that it is the NH3
in the offgas itself that is reacting
the H2S. Since the NH3 and H2S
concentrations are variable, it is
likely that some of the H2S is re-
acted by the alkali. Therefore, it is
likely some alkali will always be
needed. However, the choice of
scrubbing alkali may be made on
such factors as cost, maintenance,
safety, availability, and crew com-
fort (rather than performance).
6. The absorption of H2S and C02 in
the alkaline solution appears to be
fully reversible by distillation. The
sulfur in the scrubber solution is
primarily in the form of sulfide.
The sulfate or sulfite level deter-
mined in the scrubbing solution
was equal to that in the water sup-
ply. The sulfide will distill off as
H2S (along with C02) while the sul-
fate will not.
7. With an adequate contactor the
Stretford process can obtain H2S
removal efficiencies of 99 percent.
These tests suggest that, if ade-
quate H2S removal cannot be
achieved with a venturi, a packed
tower is a workable option for im-
proving performance.
8. To ensure continued satisfactory
performance of a Stretford plant in
processing retort offgas, it is im-
100
u
.§
.<»
I
1
o
I
O N = NaOH
D K = KOH
O A = NH4OH
Open Symbols = Venturi
; Solid Symbols = Tray Tower
Figure 2.
40
_ , . . % Removal H,S
Selectivity, •
% Removal COi
Removal efficiency vs. selectivity for alkaline scrubber.
portant to effectively remove the
hydrocarbon mist and other partic-
ulate matter from the gas before it
enters the plant.
-------
Table 2.
Date
1984 Time
5/5 18:05
18:55
20:30
21:45
22:35
23:30
5/6 00:30
01:30
02:30
03:30
04:25
05:30
5/7 21:21
22:02
5/8 18:23
20:00
22:05
22:17
23:12
23:45
5/9 00:45
16:10
16:30
18:02
20:20
5/10 00:30
17:16
17:48
18:27
19:30
20:15
21:28
22:15
23:21
5/11 00:30
01:30
02:30
03:30
04:35
05:30
06:35
5/12 13:30
14:30
15:30
16:22
17:19
18:25
19:19
20:18
21:25
22:24
23:21
Stretford Operat
Gas
Contest
Device
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V
V&T
V&T
V&T
V&T
V&T
V&T
V&T
V&T
V&T
V&T
V&T
Remova
Eff
%
75.2
74.7
73.7
62.1
51.7
61.3
72.7
79.5
90.3
93.4
94.3
93.7
63.0
70.4
84.5
94.5
76.8
81.1
80.2
80.8
81.4
85.6
82.8
86.1
82.7
82.9
80.7
80.8
80.9
81.1
81.1
80.9
81.3
81.0
81.2
79.7
80.7
80.6
81.8
81.3
84.3
99.1
99.2
99.1
98.8
98.7
98.8
99.1
99.0
99.3
99.4
99.4
ing Com
Gas
1 Flow
Rate
Sm3/s
0.190
0.255
0.233
0.256
0.269
0.269
0.272
0.192
0.327
0.254
0.189
0.189
0.276
0.206
0.280
—
~
0.483
0.489
0.443
0.443
0.208
0.218
0.215
0.205
0.189
0.247
0.190
0.267
0.298
0.189
0.220
0.189
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
iitions
Gas
Out
Temp
°C
40
41
43
40
43
44
44
38
44
45
46
47
46
43
42
—
-
37
37
37
36
42
42
42
42
39
38
38
37
40
40
40
41
42
42
39
39
39
40
40
39
38
41
38
38
38
39
39
38
39
100
39
and Her
Gas
Inlt
Pres
mm Hg
27.8
30.4
30.4
30.4
30.4
32.9
29.3
29.9
24.3
30.4
30.4
30.9
60.1
65.8
43.0
—
-
53.1
70.8
60.7
65.8
140.2
146.7
126.5
126.5
32.9
15.2
15.2
15.2
15.2
15.2
15.2
17.7
17.7
12.7
12.7
12.7
12.7
12.7
10.1
10.1
19.5
19.5
18.2
25.3
22.8
22.8
25.3
25.3
25.3
27.8
25.3
noval £1
Inlt
HzS
Cone
ppmV
1617
1579
1633
1571
1322
1618
1623
2169
2018
1886
1741
1590
763
1157
1369
1372
1378
1392
1395
1398
1399
1689
1700
1818
1768
1761
1362
1330
1305
1283
1270
1259
1255
1250
1248
1134
1250
1232
1242
1240
1236
1024
1036
985
1001
1138
1199
1171
1218
1237
1232
1228
ficiem
Out
H2S
Cone
ppmV
407
400
429
595
639
626
443
444
195
125
100
101
282
343
212
75
320
263
276
269
260
243
293
253
306
301
263
255
249
243
240
240
235
237
235
230
241
239
226
232
194
9
8
9
12
15
14
11
12
9
8
7
-,y During Gi
Sol Sol
Flow Htr
Rate Tin
' S1/s °C
7.93 43
1.91 43
1.79 44
1.77 43
1.86 46
1.54 47
1.60 47
1.48 47
1.48 46
1.51 46
1.48 47
1.50 48
1.67 46
1.64 47
1.80 43
..
..
1.74 39
1.71 39
1.73 39
1.72 39
1.81 43
1.82 43
1.82 43
1.90 43
1.93 43
1.36 41
1.36 41
1.36 40
1.35 41
1.36 41
1.36 42
1.36 43
1.38 44
1.36 43
1.36 43
1.36 43
1.38 43
1.67 42
1.53 42
2.12 43
1.63 42
1.64 43
1.60 42
1.59 42
1.61 42
1.62 42
1.69 42
1.70 42
1.86 42
1.96 43
2.05 42
KITes
Sol
Htr
Tout
"C
40
43
44
43
44
47
47
41
46
46
47
47
46
46
41
—
-
36
34
34
35
43
43
43
43
39
39
39
39
42
42
42
43
44
44
41
41
41
42
41
41
42
45
42
43
42
43
43
42
42
41
41
tt Program
Oxidizer
Air
1 Flow
Sm3/s
0.036
0.035
0.029
0.029
0.026
0.026
0.026
0.026
0.025
0.024
0.024
0.026
0.039
0.038
0.034
-
-
0.030
0.034
0.034
0.034
0.039
0.038
0.038
0.038
0.030
0.025
0.024
0.024
0.024
0.020
0.019
0.019
0.019
0.024
0.019
0.027
0.017
0.017
0.021
0.021
0.026
0.027
0.029
0.029
0.029
0.027
0.031
0.031
0.033
0.035
0.035
Motor
Curr
amps
7.5
7.3
7.4
7.4
7.3
7.3
7.3
7.4
7.4
7.3
7.3
7.3
7.5
7.4
7.5
—
-
7.4
7.4
7.4
7.3
7.3
7.3
7.4
7.4
7.4
7.7
7.7
7.7
7.7
7.7
7.7
7.8
7.7
7.7
7.7
7.7
7.7
7.7
7.7
7.7
7.8
7.8
7.7
7.5
7.7
7.7
7.7
7.7
7.6
7.5
7.6
ADA
Cone
kg/m3
7.5
7.5
7.5
8.7
8.7
8.7
8.7
8.6
8.6
8.6
8.5
8.5
10.0
9.9
8.2
8.0
7.7
7.6
7.5
7.4
7.3
4.6
4.6
4.6
4.6
5.5
9.9
9.9
9.8
9.7
9.7
9.6
9.5
9.5
9.4
9.3
9.2
9.1
9.1
9.0
8.9
7.5
7.5
7.4
7.3
7.3
7.2
7.1
7.1
7.0
6.9
6.8
Van.
Cone
kg/m3
2.3
2.2
2.2
2.5
2.4
2.4
2.4
2.4
2.3
2.3
2.3
2.2
3.3
3.3
3.3
3.3
3.3
3.3
3.3
3.3
3.3
3.2
3.2
3.2
3.2
3.5
3.4
3.4
3.4
3.4
3.3
3.3
3.3
3.3
3.3
3.3
3.3
3.3
3.2
3.2
3.2
3.0
3.0
2.9
2.9
2.9
2.8
2.8
2.7
2.7
2.6
2.6
Carb.
Cone
kg/m3
16.8
16.4
15.8
15.3
14.9
14.5
14.1
13.7
13.3
12.9
12.5
12.0
16.0
15.9
30.0
30.2
30.4
30.4
30.5
30.6
30.7
30.1
30.1
29.9
29.6
31.5
30.1
29.9
29.8
29.5
29.3
28.9
28.7
28.4
28.1
27.8
27.5
27.3
27.0
26.7
26.7
30.9
30.7
30.4
30.2
30.0
29.7
29.5
29.3
29.0
28.7
28.5
Thio-
sul. Oxidation
Cone Potential
kg/m3 pH mV
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.3
0.3
0.5
0.5
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.7
0.7
0.7
0.7
0.7
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
1.0
1.0
1.0
1.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
10.8
10.5
10.2
9.9
9.9
9.9
9.8
9.8
9.1
8.4
7.7
7.0
10.0
9.9
7.4
7.4
7.4
7.4
7.8
8.2
8.9
9.1
8.9
8.6
9.9
9.7
9.4
9.4
9.5
9.5
9.4
9.4
9.5
9.7
9.8
10.0
10.1
9.9
9.6
9.4
9.4
9.3
9.3
70.7
70.8
77.6
72.3
77.5
10.7
9.9
9.8
9.6
+38
+ 19
0
-21
-15
-8
-2
+5
+4
+2
+ 1
0
-50
-37
-39
-33
-27
-21
-21
-21
-21
-69
-78
-87
-75
-42
-54
-48
-42
-46
-51
-55
-51
-48
-44
-41
-37
-23
-10
+4
0
+2
-15
-15
-16
-16
-17
-22
-27
-32
-23
-13
-------
Table 2. (Continued)
Inlt Out Sol Sol Sol
Oxidizer
Thio-
Gas Gas Gas
Gas Removal Flow Out Inlt H^S HjS Flow Htr Htr Air Motor ADA Van. Carb. sul.
Date Contct Eff Rate Temp Pres Cone Cone Rate Tin Tout Flow Curr Cone Cone Cone Cone
1984 Time Device "A '
Oxidation
Potential
Sm3/s °C mm Hg ppmV ppmV S1/s °C °C Sm3/s amps kg/m3 kg/m3 kg/m3 kg/m3 pH mV
5/13
5/14
15:30
16:12
17:17
18:57
19:32
20:16
21:13
22:18
23:25
00:00
01:00
02:00
03:00
04:00
05:00
06:00
07:00
07:30
08:15
V*
V*
V
V*
V*
V*
V*
V
V*
V*
V*
V*
V*
V&T
V&T
V&T
V&T
V&T
V&T
86.9
84.3
83.3
85.4
86.2
86.9
87.3
87.4
87.6
87.7
87.9
87.9
88.3
95.1
95.0
94.5
94.4
97.3
98.7
N/A
N/A
N/A
0.250
0.251
0.251
0.251
0.250
0.250
0.250
0.211
0.210
0.210
0.210
0.210
0.210
0.192
0.182
0.182
38
39
39
39
38
38
38
39
39
38
36
36
36
37
36
37
37
37
—
20.0
25.3
25.3
25.3
25.3
25.3
25.3
26.3
22.8
22.8
22.8
22.8
22.8
22.8
22.8
22.8
22.0
17.5
17.5
990
797
749
940
1001
1063
1094
1113
1119
1125
1133
1133
1128
1116
1127
1115
1106
1101
1091
130
125
125
137
138
139
139
140
139
138
137
137
132
55
56
61
62
30
14
1.88
1.86
1.79
1.82
1.86
1.83
1.83
1.87
1.82
1.83
1.80
1.77
2.02
2.08
2.05
2.05
2.27
2.26
2.26
39
41
42
40
40
42
43
43
44
44
40
40
41
41
38
40
39
39
39
41
41
42
41
42
42
43
43
43
43
38
41
42
42
37
39
39
39
39
0.042
0.043
0.044
0.043
0.039
0.038
0.037
0.036
0.036
0.036
0.033
0.031
0.031
0.028
0.031
0.033
0.033
0.034
0.034
7.6
7.6
7.6
7.6
7.7
7.6
7.6
7.6
7.6
7.6
7.6
7.6
7.6
7.6
7.6
—
7.6
7.7
7.7
7.6
9.7
9.7
9.7
11.0
11.0
11.0
11.0
11.0
11.0
11.0
11.0
11.0
—
—
2.1
2.8
2.7
2.6
3.0
3.0
3.0
2.9
2.9
2.8
2.8
2.7
2.7
3.1
3.0
3.0
2.9
..
—
1.1 9.9
1.1 10.1
1.1 10.4
1.1 10.6
1.1 10.7
1.1 10.9
1.1
1.1
1.1
1.1
1.1
1.1
1.1
1.1
1.1
1.1
1.1
1.1
1.1
-9
-19
-28
-23
-18
-13
—
„
-
„
—
—
_.
..
~
~
..
..
V = venturi.
V&T = venturi plus packed tower.
"On these tests, the packed tower was in place but no solution was flowing to it.
H. Taback andG. Quartucy are with KVB, Inc., Irvine, CA 92714; andR. Goldstick is
with Energy Design Service, Ojai, CA 93023.
Edward R. Bates is the EPA Project Officer (see below).
The complete report, entitled "Alkaline and Stretford Scrubbing Tests for H^S
Removal from In-Situ Oil Shale Retort Off gas," {Order No. PB 85-246 965/AS;
Cost: $22.95, subject to change) will be available only from:
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
Telephone; 703-487-4650
The EPA Project Officer can be contacted at:
Air and Energy Engineering Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
U. S. GOVERNMENT PRINTING OFFICE:1986/646-l 16/20757
-------
United States
Environmental Protection
Agency
Center for Environmental Research
Information
Cincinnati OH 45268
- -~
::\:-•'-<•-I" lU.PDT
" ' '
Official Business
Penalty for Private Use $300
EPA/600/S7-85/029
OOOC329 PS
U S EHVIR PROTECTION A66NCV
REGION 5 LIBRARY
230 S DEARBORN STRiET
CHICAGO II £0604
------- |