United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
Research and Development
EPA-600/S7-82-054  Dec. 1 982
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. Purdy, 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

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                                          Filter
  NX Purge
                                                      Syn Gas
                                                    Sour I     Sweet
                                                    Gas
 'enturi
Scrubber
       Dehydrator
                  v
     Sour-Gas     _l
   Compressor Q|~|
 \Mist
 Eliminator
                                                                Gas
                                                                 r	T
                                                                 i  Absorber
                                                                        i	
                                          Heat
                                          Exchanger

                                           PCS Tank
                                                               i   ) Solvent
                                                               N-'Chiller
                             \	1
                             i
                                  r
                                                                                                        Acid Gas
                                                                                      i	
   Heat
Exchanger
                                ~\Gas
                                 i Chiller
                                      i	1
                                                  /V2-
                                            V
        Plant Water
                               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
                                     wt%
                                      New Mexico Coal
                                           wt %
 Proximate Analysis /i
  Fixed Carbon
  Volatile Matter
  Moisture
  Ash

 Ultimate Analysis %
  Carbon
  Hydrogen
  Oxygen
  Nitrogen
  Sulfur
  Ash
                     86.0
                      2.4
                      0.9
                     10.7
                     83.8
                      0.6
                      2.2
                      0.1
                      2.6
                     10.7
36.2
31.1
 9.7
23.0
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 importantquality 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 gasifier-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 + H20 = H2S + CO2
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 10C. 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 inTableS. 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
                                                K,=
            From Kohl and Riesenfeld
                                 (COS)(H20)


                             Char
                            O New Mexico Coal



                                         O
                                                    8   
   1400
   (760)
Figure 2.
1500
(815)
                     1600
                    (870)
 1700
J925)
1800
(980)
                         Temperature at Top of Bed, F(C)
Comparison of experimental values of
Riesenfeld.
                                  with  data  of  Kohl and

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Table 2.
Gas Analysis Summary for AMI-60/GO-79
Species
H2
C02
Ethylene
Ethane
H?S
COS
N2
CHA
CO
Benzene
Toluene
Ethyl Benz.
Xylenes
Thiophene*
CHsSH*.
C2#5Stf*
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





272
66


Flash
Gas
21.55
27.16
0.69
0.82
0.108
0.0044
24.40

25.18


N/A
N/A



/

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
                                   (NOTE: Peaks identified
                                   in Table 3.)
                                  17
   1	r
       8
  i	1	1	1	1	1	1	1	1	1	1	1	r
   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.  Ca hydrocarbon
 12.  Cg hydrocarbon
 13.  P ropy I 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
                                  4

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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
N on polar 25. J 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 Qu/no/ine 0.08
6 2-Methylnaphtha/ene 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 Fluorene 1.00
Dibenzothiophene 0.09
13 Phenanthrene 1.30
14 Anthracene 0.73
15 Fluoranthene 0.45
16 Pyrene 0.32
17 Benzofajanthracene 0.09
18 Chrysene 0. 14
19 Triphenylene 0. 14
20 Benzo(b)Fluoranthene 0.04
21 Benzo(k)Fluoranthene 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 0.17
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. CC>2,
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

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Table 6.


No.
1
2
3
4
5
6
7
8
9
10
11
72



*wt %

Table 7.



Phenols
Cresols
Quantitative Analysis of Sulfur Species*
(Tar Sample, Run GO-69BJ

Compound
Thiophene
Me th ylthiophenes
Cz-thiophenes
Cs-thiophenes
Benzothiophene
Ci -benzothiophenes
Cz-benzothiophenes
Cs-benzothiophenes
Dibenzothiophenes
Naphthothiophenes
Phenan throthiophen es
Naphthobenzothiophenes
Total




Water Analyses*
GO-69B GO-70 GO-76
PCS PCS Trap

870 637 1250
690 398 693
Xylenols 230 881 161
Organic extractables 1620 2O40
*mg/l



Table 8.

Ammonia
Carbon
Chloride
COD
Cyanate
Cyanide
Fluoride
Nitrogen
pH
Phenolics
Sulfate
Sulfite
Thiocyanate
TOC
TVC




Water Analysis for All Runs*
PCS water
700
725
20
1.500 - 3,000
500
45
5
600
7.7
200 - 400
35
15
50
400 - 600
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
600 - 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 CC>2 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 C2H6 show some small
differences. These differences were
shown to be related to the tact that the
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 C2H6 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.







N




*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

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1.4
Figure 4.
          1.6  1.8 2.0  2.2  2.4
           Experimental, Ib/hr
                         2.6
Table 9.
      Predicted vs. experimental
     production rate of H2 from
     gasification of New Mexico
     coal.
      AMI-57/GO-76 Stripper
     Exit Methanol
 1.   S at'd hydrocarbon
 2.   CO 2
 3.   C/i/Va isomer
 4.   Tetramethylsilane
 5.   Trichlorofluromethane
 6.   CsA/io isomer
 7.   Unknown
 8.   Freon 113
 9.   Cyclopentadiene
10.   C&H-I2 isomer
11.   CeA/14 isomer
12.   C6^/10 isomer
13.   Benzene
14.   C?A/14 isomer
15.   Cy/Vie isomer
16.   C-,H\ e isomer
17.   C?A/12 isomer
18.   CjHi 2 isomer
19.   CjH-(2 isomer
20.   Unknown hydrocarbon
21.   Toluene
22.   Methyl thiophene isomer
23.   CaA/16 isomer
24.   CsA/ie isomer
25.   CaA/16 isomer
26.   CsA/ie isomer (trace)
27.   Cs/Vi4 isomer (trace)
28.   Hexamethyl
     cyc/otrisiloxane
29.   CgA/20 isomer
30.   CgA/is isomer
31.   Ethyl benzene
32.   Xylene (M,P)
33.   Styrene
34.   Xylene (0)
35.   Cg//i8 isomer
36.   CgA/20 isomer
                                 Table 9.    (Continued)
37.  Cs alkyl benzene
38.  Cic//22 isomer
39.  Unknown hydrocarbon
40.  Unknown hydrocarbon
     Ci 1/^24 isomer
     Cs alkyl benzene
     Cz alkyl benzene
     Cic//22 isomer
     Cio^/22 isomer
     CA alkyl benzene
     CioA/22 isomer
     Cic//2o isomer
     Unknown hydrocarbon
                                  41.
                                  42.
                                  43.
                                  44.
                                  45.
                                  46.
                                  47.
                                  48.
51.  CgHs isomer
52.  Alkyl benzene isomer
53.  C-nf-/24 isomer
54.  CsA/ioO isomer
55.  CnA/24 isomer
56.  CgHioO isomer
57.  Unknown si/oxane
58.  Unknown si/oxane
59.  Unknown siloxane
60.  Ci4/V3o isomer
61.  Ci AH30 isomer
62.  Unknown
63.  CisA/32 isomer
                                     3.0(91.4)
                                   u
                                    \2.0(61.0)
                                   ^
                                   <    *
                                   5
                                      1.0  (30.5)
                                             -35
                                            (-37)

CO2
H2S
COS
MEOH
H2
CO
N2
CH<
C2H<
C2Hs
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
                      -25        -15         -5         5
                      (-32)       (-26)      (-21)       (-15)
                       Solvent Temperature, F fC)
                                  Figure 5.    AMI-43/GO-68B ONDA correlation.

                                                                          7
                                                                          U. S. GOVERNMENT PRINTING OFFICE: 1983/659-095/559

-------
       J. K. Ferr ell, R. M. Folder. 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:
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               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
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Center for Environmental Research
Information
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