United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
Research and Development
EPA-600/S7-82-054 Dec. 1982
Project Summary
Coal Gasification/Gas
Cleanup Test Facility:
Volume III. Environmental
Assessment of Operation with
New Mexico Subbituminous
Coal and Chilled Methanol
J. K. Ferrell, R. M. Felder, R. W. Rousseau, R. M. Kelly, M. J. Purely, and S.
Ganesan
This report concerns the second
major study carried out on a pilot-
scale coal-gasification/gas-cleaning
test facility: the steam-oxygen gasifi-
cation of a New Mexico subbituminous
coal using refrigerated methanol as
the acid gas removal solvent. The
report briefly describes the facility;
summarizes gasifier operation using
the New Mexico coal; gives results of
mathematical modeling of the gasifier,
detailed chemical analyses of gasifier
effluent streams, and operation of the
acid gas removal system using the
gasifier make gas as feed; and sum-
marizes results of mathematical model
development for the acid gas absorber
column. Several trace sulfur com-
pounds and aliphatic hydrocarbons
were found to distribute among all exit
streams from the acid gas removal
system. In addition, a wide range of
simple aromatic hydrocarbons were
found to accumulate in the recir-
culated methanol.
This Project Summary was devel-
oped by EPA's Industrial Environ-
mental Research Laboratory. Research
Triangle 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
ordering information at back).
Introduction
As a part of a continuing research
program on the environmental aspects
of fuel conversion, the EPA has spon-
sored a research project on coal
gasification at North Carolina State
University. The facility used for this
research is a small coal-gasification/
gas-cleaning pilot plant. The overall
objective of the project is to characterize
the gaseous and condensed phase
emissions from the gasification/gas-
cleaning process, and to determine how
emission rates of various pollutants
depend on adjustable process pa-
rameters.
The plant, described in detail in
Volume I (EPA-600/7-80-046a; NTIS
PB80-188378) consists of a fluidized-
bed reactor, a cyclone and venturi
scrubber for particulates, condensables,
and solubles removal, and absorption
and stripping columns for acid gas
removal and solvent regeneration. The
plant has a nominal capacity of 23 kg/hr
(50 Ib/hr) of coal feed for steady state
operation. Figure 1 is a schematic of the
gasifier, the acid gas removal system
(AGRS), and other major components.
In an initial series of runs on the
gasifier, a pretreated Western Kentucky
No. 11 coal was gasified with steam and
-------
Syn Gas
NtPui
Coal
Feed
Hopper
NX Purg
ge
e _
I
Gasifier
NX Purge
Plor
not
<
>
rh 1
:xc/onelNX1 ^
a
p k>
J
:har
Receiver
/V2 Purpe
tf are/-
ol
Steam
-u
[
fei
'cr
.
1 1 V^ 1
7rur/ fc
e/- [y
Dehydrator ^
Sour-Gas T
Compressor D T~
iMist
Eliminator
r*!
Y
/"\ ^
Heat
Exchanger
PCS Tank H
Excr
-©
Acid Gas
I L
Circulation
Pump
Solvent Pump
S = Sample Port
Figure 1. Pilot plant facility.
oxygen. The results of this work and a
detailed list of project objectives are in
Volume II (EPA-600/7-82-023).
This report concerns the second
major study carried out on the facility,
the steam-oxygen gasification of a New
Mexico subbituminous coal using
refrigerated methanol as the AGRS
solvent. This coal, from the Navaho
mine of the Utah International Co., was
ground and screened by the Morgan-
town Energy Technology Center of the
Department of Energy. Table 1 shows
an average analysis of the char and coal
used in studies to date.
This report briefly describes the facili-
ty; summarizes gasifier operation using
New Mexico coal; gives results of math-
ematical modeling of the gasifier, de-
tailed chemical analyses of gasifier ef-
fluent streams, and operation of the
AGRS using the gasifier make gas as
feed; and summarizes results of mathe-
matical model development for the
AGRS absorber.
Results and Discussion
Fifteen gasification runs were made
using the pilot plant facility with New
Mexico coal. Six runs made use of the
gasifier-PCS system only, and nine runs
were integrated and included the acid
gas removal system.
To evaluate the ability of the system to
handle the tars associated with the coal
feedstock, gasifier runs were com-
menced by feeding mixtures of the sub-
bituminous coal and devolatilized West-
ern Kentucky coal char used in previous
studies. The first four runs used 10, 30,
30, and 50 wt % subbituminous coal;
the rest used char. After some system
Table 1. Coal and Char Analysis
modification to accommodate tars,
these runs indicated that 100% New
Mexico subbituminous coal could be
used as a feedstock, so 100% coal was
used for the rest of the runs.
Sampling and chemical analysis
methods were developed for all feed and
effluent streams. Methods used to
sample and analyze gaseous streams
were satisfactory for the major gases
and for all minor components of the
gaseous streams in concentrations
Coal Char
New Mexico Coal
wt%
Proximate Analysis %
Fixed Carbon
Volatile Matter
Moisture
Ash
86.0
2.4
0.9
10.7
36.2
31.1
9.7
23.0
Ultimate Analysis %
Carbon
Hydrogen
Oxygen
Nitrogen
Sulfur
Ash
83.8
0.6
2.2
O.1
2.6
10.7
50.2
4.2
20.7
1.1
0.8
23.0
-------
greater than a few parts per million.
Detailed chemical compound analyses
for solid and liquid streams are gener-
ally satisfactory, but are still under
development.
A major effort was made to develop
methods to detect trace metal elements
in the feed and effluent streams.
Methods now used for As analysis
are satisfactory, both for ease of
application and reliability. The main
problem with As is the ineffectiveness
of the impinger solutions in trapping it
from the gas stream. Reproducibility of
Pb concentration measurements has
been less than satisfactory, although
considerable improvement has been
made recently by diluting all samples to
fall within the linear range of the atomic
absorption spectrometer calibration,
and by adding dibasic ammonium
phosphate to the injected sample,
thereby binding the Pb and enabling
higher charring temperatures. The cold-
vapor technique used for Hg is satisfac-
tory; the main difficulty with Hg is its
volatility: samples must be analyzed
soon after they are taken.
The most important quality assurance
test for the evaluation of the experimen-
tal data was good closures on the mass
balances for total mass and for all major
elements. In general, the mass balance
results for both the gasif ier-PCS and the
acid gas removal systems are excellent:
they indicate no gross errors in either
chemical analyses or mass flow mea-
surements. Frequent calibration checks
were necessary to achieve the mass
balance results shown.
Reactor temperature and steam-to-
carbon feed ratio were the main
operating parameters varied for the
gasifier: results show that the make gas
flow rate and the carbon conversion
both increase with increasing tempera-
ture. This increase is expected: the
degree of devolatilization and the
gasification reaction rates all increase
with increasing temperature. Although
the effects of operating parameters on
reactor performance are not easily
determined directly from the experimen-'
tal data, a mathematical model devel-
oped in this study correlates run results
reasonably well, and is useful in
evaluating the effects of operating
parameters.
Previous studies with a char feed
indicated that the sulfur conversion
could be roughly estimated by assuming
it to equal the carbon conversion. For
New Mexico coal, this crude approxima-
tion also seems applicable. In addition.
results of a detailed analysis of the
reactor make gas for the various sulfur
gases indicate that the distribution
between H2S and COS may be predicted
by assuming that the reaction,
COS + H2O = H2S + C02
is at equilibrium at the temperature
above the fluidized bed. Figure 2 shows
the equilibrium constant (Ki) for this
reaction plotted versus the temperature
at the top of the f lu idized bed for both the
char and the coal runs.
The gasification of New Mexico coal
produces many hydrocarbon gases.
Aliphatics up to butene and butane and
simple aromatic compounds have been
detected in the gasifier make gas
stream. Analyzing these hydrocarbon
emission rates indicates that they
generally increase with increasing
reactor bed temperature. Table 2 shows
the gas compositions measured at six
gas sample locations shown on Figure
1.
After leaving the PCS system, the
reactor make gas is compressed to
about 3610 kPa (525 psig) and then
cooled to approximately 10°C. During
this process higher molecular weight
compounds in the gas stream in very
low concentrations are condensed and
separated from the gas in a knockout
drum. This drum eliminates pressure
fluctuations at the sour gas flow meter
and also collects liquids which may
condense after compression and cooling.
A sample of this liquid was collected
after Run GO-79 and was analyzed by
GC-MS. The mass spectrogram is
shown in Figure 3; results of compound
identification are listed in Table 3. While
a variety of hydrocarbon compounds
were found in this liquid, no aromatic
compounds heavier than substituted
benzenes were found. This fact, together
with results of analyses of the methanol
AGRS solvent, indicates that no detect-
able polynuclear aromatic compounds
are in the gases leaving the PCS system.
No unusual results were noted from
the proximate and ultimate analyses of
the solid streams; however, the ultimate
analysis of the spent char generally
correlates with gasifier run conditions.
For example, higher temperatures
result in higher carbon conversions and
a lower carbon content in the spent
char.
The tars collected from the cold trap
downstream from the cyclone were
subjected to a solvent partitioning
scheme to separate them into groups of
compounds of varying polarities. The
groups were then quantified as to their
wt % contribution to total tar compo-
sition. In addition to the partitioning
25
20
15
10
From Kohl and Riesenfeld
(COS)(H20)
Char
O New Mexico Coal
O
1400
(760)
Figure 2.
1500
(815)
1600
1870)
170O
4925)
1800
(980)
Temperature at Top of Bed. °F(°C)
Comparison of experimental values of
Riesenfeld.
with data of Kohl and
-------
Table 2. Gas Analysis Summary for AMI-60/GO-79
Species
H2
COs
Ethylene
Ethane
HzS
COS
N,
CHt
CO
Benzene
Toluene
Ethyl Benz.
Xylenes
Thiophene*
CHaSH*,
CzHsSH*
Carbon
disulfide*
Propylene*
Propane*
Butane*
Methanol**
Sample
Train
32.13
21.68
0.30
0.33
0.206
0.0084
21.33
6.78
17.06
N/A
N/A
N/A
N/A
99
37
1
2
925
273
451
PCS
Tank
32.57
21.82
0.30
0.33
0.174
0.0078
20.62
6.65
17.17
0.0272
0.0278
N/A
N/A
97
29
1
2
940
277
1730
Sour
Gas
32.60
21.68
0.32
0.36
0.214
0.0084
20.71
6.61
17.25
0.0391
0.0393
N/A
N/A
83
35
2
2
1012
314
224
Sweet
Gas
43.01
0.065
0.081
0.026
0.0019
27.62
7.44
21.90
N/A
N/A
212
66
Flash
Gas
21.55
27.16
0.69
0.82
0.108
0.0044
24.40
25.18
N/A
N/A
7
381
364
145
Acid
Gas
63.82
0.95
1.03
0.597
0.0233
24.71
2.60
2.06
0.0592
N/A
N/A
13
26
65
5
1053
5004
434
3.49
* Parts per million (volume)
** Estimated
ULA
(NOTE: Peaks identified
in Table 3.)
8 16 24 32 40 48 56 64 72
Figure 3. GC/MS scan of compressor knockout condensate forAMI-60/GO-79.
analysis, the tars were analyzed for
polynuclear aromatic hydrocarbons
(PAHs) and organic sulfur compounds.
The PAHs were analyzed by glass
capillary gas chromatography with a
flame ionization detector; the sulfur-
containing species were analyzed by
gas chromatography with a flame photo-
metric detector. Tables 4,5, and 6 show
results of these analyses.
Table 3. Compressor Knockout
Sample from AMI-60/GO-
79 Peak Numbers from
Figure 3
1. 1-pentene
2. Hydrocarbon
3. Benzene
4. Hydrocarbon
5. Toluene
6. Cyclo C4-C5
7. Hydrocarbon
8. Ethyl benzene
9. Dimethyl benzene
10. Substituted benzene
11. CB hydrocarbon
12. C9 hydrocarbon
13. Propyl or ethyl methyl
substituted benzene
14. Propyl or ethyl methyl
substituted benzene
15. 1-decene
16. 2-propyl benzene
17. 1 -ethyl-4-methyl benzene
The analyses of the tars indicate that
a significant amount of PAHs is in the
gas stream as it leaves the reactor, and
emerge primarily in the stream con-
densed by the venturi scrubber. Com-
pounds with boiling points higher than
that of naphthalene do not seem to be in
the gas stream past the PCS system.
The concentrations of various species
in the water condensate from the
sample train were normalized to deter-
mine rates of evolution in milligrams per
kilogram of coal fed to the gasifier. No
clear trends with reactor temperature
are evident, indicating that (for the
temperature range covered) the reactor
temperature has little effect on the
emission rates of wastewater species.
Water samples were analyzed by
high-performance liquid chromatog-
raphy (HPLC) for phenolics. The sam-
ple preparation consisted of filtering
to remove particulates prior to direct
injection into the HPLC. The results,
shown in Table 7, are not reported as
specific phenolic compounds, but are
categorized as phenols, cresols, and
xylenols. Also, the samples (except GO-
70) were analyzed for total organic
extractables. A methylene chloride
extraction was performed and the
extract evaporated to dryness to deter-
mine the weight percent of organic
extractables in the sample.
In addition, both the trap water and
water from the PCS tank were analyzed
by standard methods. Table 8, summa-
rizing these results, shows average
values for all runs, general levels of
-------
Table 4. Tar Partition Results*
GO-69B GO-70
PCS PCS
Acids 10.9 34.7
Bases 20.9 27.5
TOTAL NEUTRALS 68.3 37.7
Non polar 25.1 5.5
PAHs 36.0 26.7
Polar 7.2 5.5
Cyclohexane
Insolubles
*wt%
Table 5. Capillary GC Tar Analyses*
GO-69B
No. Compound PCS
1 Phenol 0. 15
2 Indene 0.87
3 Naphthalene 3.50
4 Benzothiophene 0.13
5 Quinoline 0.08
6 2-Methylnaphthalene 1.60
7 1 -Methylnaphthalene 1.10
8 Biphenyl 0.36
9 Acenaphthylene 1.50
10 Acenaphthene 0.57
1 1 Dibenzofuran 0. 74
12 Fluor ene 1.00
Dibenzothiophene 0.09
13 Phenanthrene 1.30
14 Anthracene 0.73
15 Fluoranthene 0.45
16 Pyrene 0.32
17 Benzo(a)anthracene 0.09
18 Chrysene 0. 14
19 Triphenylene 0. 14
20 Benzo(b)Fluoranthene 0.04
21 Benzo(k)F/uoranthene 0.02
22 Benzo(e)Pyrene 0.05
23 Benzo(a)Pyrene 0.04
24 Perylene 0.02
Total Wt% 15.03
*wt%
concentrations found, and differences
between the two kinds of samples
collected.
Efforts continued to determine the
fate of several of the more volatile trace
metal elements in the feed coal.
Closures on As mass balances consis-
tently vary between 35% and 70%,
suggesting that a significant fraction of
this substance is passing undetected
from the system, either in the gas phase
or adsorbed on fine particles that are not
trapped by the cold trap or impingers.
Similar results are obtained for Pb, for
which closures never exceeded 34%,
GO-76 GO-76 GO-78
Trap PCS Trap
16.5 11.2 17.29
4.7 6.7 6.05
78.8 80.1 76.66
24.7 30.0 11.53
10.7 11.5 26.85
15.3 15.2 16.45
28.1 23.4 21.83
GO-76 GO-76 GO-78
Trap PCS Trap
2.11 1.30 2.10
0.09 0.06 0.08
0.16 0.09 0.13
0.79 0.60 0.97
0.52 0.37 0.81
0.16 0.14 0.28
0.71 0.53 0.60
0.34 0.30 0.26
0.53 0.46 0.53
0.53 0.51 0.43
0.07 0.08 0.09
0.62 0.67 0.47
0.38 0.32 0.49
0.36 0.32 0.23
0.26 0.25 0. 1 7
0.16 0.07 0.05
0.13 0.09 0.04
0.06 0.03 0.02
0.11 0.05 0.013
0.06 0.01 0.007
0.05 0.01 0.007
0.11 0.03 0.015
0.05 0.01 0.01
8.36 6.30 7.802
indicating a higher volatility for this
element.
The problem with Hg is reproduc-
ibility, rather than failure to detect a
portion of the total emitted element. The
quantity of Hg appearing in the trapped
tar and solids varies dramatically from
one run to another. In some instances
the apparent amount of Hg in one stream
or other exceeds the quantity fed in
with the coal.
To aid in formulating gasifier perform-
ance correlations, a simple mathemati-
cal model of the fluidized bed gasifier
has been developed which considers
the gasification process in three stages:
instantaneous devolatilization of coal at
the top of the fluidized bed, instanta-
neous combustion of carbon at the
bottom of the bed, and steam/carbon
gasification and water gas shift reaction
in a single perfectly mixed isothermal
stage. The model is significant in and of
itself, but its particular importance to
the project is that it enables the
specification of gasifier conditions
required to produce a feed to the acid
gas removal system with a predeter-
mined flow rate and composition.
Using optimal parameter values, the
model was run for all gasifier runs and
gave excellent predictions of carbon
conversion, dry make gas flow rate, and
the production rate of all major gases.
Figure 4 shows an example. The model
does a good job of correlating data on
the evolution of individual species and
may be used to predict the composition
of the gasifier make gas for a specified
set of reactor conditions, and also to
study the effects of individual reactor
variables on yield.
Results from the acid gas removal
system show that refrigerated methanol
is an effective solvent for cleaning gases
produced by coal gasification. COa,
COS, and H2S can be removed to
sufficiently low levels with proper
choice of operating conditions and
effective solvent regeneration.
The presence of several trace sulfur
compounds, mercaptans, thiophenes,
organic sulfides, and CS2, complicates
the gas cleaning process. These com-
pounds were found to distribute among
all exit streams from the AGRS. Since
no provision was made to treat these
sulfur gases, they may be emitted to the
atmosphere and must be dealt with to
avoid significant environmental prob-
lems (see Table 2).
A wide variety of aliphatic and
aromatic hydrocarbons are present in
the gas stream fed to the AGRS. The
aliphatic hydrocarbons, from methane
to butane, cover a wide range of
solubilities. Their presence in all AGRS
streams must be anticipated to prevent
their emission to the atmosphere.
While a wide range of simple aromat-
ics were identified in the gas stream fed
to the AGRS, essentially no polynuclear
aromatic compounds were found.
Apparently, the gas quenching process
effectively removes these compounds
from the gasifier product gas. However,
significant quantities of simple aromatics
were found to accumulate in the
recirculating methanol increasing the
-------
Table 6. Quantitative Analysis of Sulfur Species*
(Tar Sample, Run GO-69B)
No. Compound
1 Thiophene
2 Methylthiophenes
3 Cz-thiophenes
4 C3-thiophenes
5 Benzothiophene
6 Ci-benzothiophenes
7 Cz-benzothiophenes
8 C3-benzothiophenes
9 Dibenzothiophenes
10 Naphthothiophenes
1 1 Phenanthrothiophenes
12 Naphthobenzothiophenes
Total
*wt%
Table 7. Water Analyses*
GO-69B GO-70 GO-76
PCS PCS Trap
Phenols 870 637 1250
Cresols 690 398 693
Xylenols 230 881 161
Organic extractables 1620 2040
*mg/l
Table 8. Water Analysis for All Runs*
PCS water
Ammonia 700
Carbon 725
Chloride 20
COD 1,500 - 3,OOO
Cyanate 500
Cyanide 45
Fluoride 5
Nitrogen 600
pH 7.7
Phenolics 20O - 400
Sulfate 35
Sulfite 15
Thiocyanate 50
TOC 400 - 600
TVC 325
Concentration
0.01
0.02
0.03
0.03
0.13
0.05
0.06
0.05
0.09
0.08
0.06
0.09
0.70
GO-76 GO-78
PCS Trap
220 1584
166 783
97 510
460 1900
Trap water
6,000
3,200
40
6,000 - 10.000
2.000 - 5.000
25 - 200
10
6.000
8.5
6OO - 1,100
40 - 300
40
250
2,600
1,500
pollutants throughout the AGRS. The
nature and design of these polishing
steps will depend on the required
discharge levels of specific pollutants
manufactured in the gasification process.
As a part of the AGRS research
program, a mathematical model of the
absorber was developed. The model
assumes adiabatic operation of the
column and uses appropriate mass and
energy balances, physical and transport
property information, and phase equi-
librium relationships to simulate steady-
state behavior of the absorber. The
model was tested by comparing its
predictions with experimental data for
runs made with a mixture of nitrogen
and CO2 only (syngas runs) and with
reactor make gas from the PCS system.
For the syngas runs the measured
and predicted liquid temperature profiles
showed excellent agreement. For runs
using reactor make gas there was very
good agreement between the predicted
and experimental concentrations for
most compounds. However, experimen-
tal data and model predictions for H2S,
C2H4, and CaHe show some small
differences. These differences were
bllUWil l\J UG fclcJLcU LU II Ic ldl*L 11 Id 1 lilt?
entering methanol was not adequately
stripped and contained some H2S (input
data to the model assumed that clean
methanol was fed to the column). The
difference between the values for C2H4
and C2He may be related to the fact that
Henry's law does not provide an
accurate correlation of vapor/liquid
equilibrium data for these species.
Figure 5 gives examples.
^
*mg/l (except pH); values shown are averages or minimum-maximum values.
potential for their discharge to the
atmosphere. Provision must be made to
purge the solvent of these compounds
or to remove them prior to the AGRS
through cold traps. Table 9 shows
results of a GC/MS scan of a sample of
the methanol solvent taken at the
stripper exit after Run GO-76.
In an environmental context, use of
refrigerated methanol as an acid gas
removal solvent for coal gas cleaning
must be accompanied by safeguards to
avoid several potential problems. The
need for polishing steps on any discharge
stream appears necessary because of
the wide distribution of several potential
-------
2.6
"
§2.0
1.4
1.4 1.6 1.8 2.0 2.2 2.4
Experimental, Ib/hr
2.6
Figure 4. Predicted vs. experimental
production rate of H2 from
gasification of New Mexico
coal.
Table 9. AMI-57/GO-76 Stripper
Exit Methanol
1 .
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
1 7.
18.
19.
20.
21.
22.
23.
24.
25.
26.
27.
28.
29.
30.
3 1 .
32.
33.
34.
35.
36.
S at'd hydrocarbon
CO2
CtHg isomer
Tetramethylsilane
Trichlorofluromethane
isomer
Unknown
Freon 113
Cyclopentadiene
CeH-iz isomer
isomer
isomer
Benzene
C7Hi4 isomer
C?Wie isomer
C7Hie isomer
C7Hi 2 isomer
isomer
isomer
Unknown hydrocarbon
Toluene
Methyl thiophene isomer
isomer
isomer
Ca/Ae isomer
Cs/Ae isomer (trace)
CeHi4 isomer (trace)
Hexamethyl
cyclotrisiloxane
CgA/20 isomer
Cg//is isomer
Ethyl benzene
Xylene (M.P)
Styrene
Xylene (O)
CgHia isomer
CgA/20 isomer
Table 9. (Continued)
37. C3 alkyl benzene
38. CioHzz isomer
39. Unknown hydrocarbon
40. Unknown hydrocarbon
41. Ci i#24 isomer
42. C3 alkyl benzene
43. C3 alkyl benzene
44. CioHzz isomer
45. CwHzs isomer
46. CA alkyl benzene
47. Ci(//22 isomer
48. CioW2o isomer
49. Unknown hydrocarbon
50. C9#io
51. CgHa isomer
52. Alkyl benzene isomer
53. Ci i/y^ isomer
54. CsHwO isomer
55. CnHZ4 isomer
56. CaHioO isomer
57. Unknown siloxane
58. Unknown siloxane
59. Unknown siloxane
60. Ci tHao isomer
61. CuHw isomer
62. Unknown
63. CisW32 isomer
3.0- (91.4)
,2.0 (61
t
1.0
5
ln = -34.07°F(-36.71
(30.5)
COZ
H2S
COS
MEOH
H2
CO
N*
CH4
C*H4
C2H6
Inlet*
20. 150
0.300
0.010
32.570
21.230
18.790
6.200
0.310
0.510
Outlet*
trace
0.022
0.001
trace
43.400
25.790
23.010
7.530
0.062
0.112
Predicted
Outlet*
0.257
0.014
41.155
26.800
23.748
7.576
0.163
0.281
*AII Values in Mole Percent
-35 -25 -15 -5 5
(-37) (-32) (-26) (-21) (-15)
Solvent Temperature, °F t°C)
Figure 5. AMI-43/GO-68B ONDA correlation.
7
&U.S. GOVERNMENT PRINTING OFFICE: 1983/659-095/559
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J. K. Ferrell, R. M. Felder. R. W. Rousseau. R. M. Kelly, M. J. Purdy. andS. Ganesan
are with North Carolina State University, Raleigh, NC 27650.
N. Dean Smith is the EPA Project Officer (see below).
The complete report, entitled "Coal Gasification/Gas Cleanup Test Facility:
Volume III. Environmental Assessment of Operation with New Mexico Sub-
bituminous Coal and Chilled Methanol," (Order No. PB 83-107 417; Cost:
$19.00, 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:
Industrial Environmental Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
United States
Environmental Protection
Agency
Center for Environmental Research
Information
Cincinnati OH 45268
Postage and
Fees Paid
Environmental
Protection
Agency
EPA 335
Official Business
Penalty for Private Use $300
PS 0000329
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