U.S. Environmental Protection Agency Industrial Environmental Research EPA-600/7"77~125b
Off ice of Research and Development Laboratory +r\-ti
Research Triangle Park, North Carolina 27711 November 1 977
ENVIRONMENTAL ASSESSMENT
DATA BASE FOR LOW/MEDIUM-BTU
GASIFICATION TECHNOLOGY:
Volume II. Appendices A-F
Interagency
Energy-Environment
Research and Development
Program Report
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. ;J
Environmental Protection Agency, have been grouped into seven series.
These seven broad categories were established to facilitate further
development and application of environmental technology. Elimination
of traditional grouping was consciously planned to fqister technology
transfer and a maximum interface in related fields. 'The seven series
are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR) .3
7. Interagency Energy-Environment Research and Development*
5- ""
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this^series result .from
the effort funded under the 17-agehcy Federal Energy/Environment
Research and Development Program. These studies relate to EPA's
mission to protect the public health and welfare from adverse effects
of pollutants associated with energy systems. The goal of the program
is to assure the rapid development of domestic energy supplies ,in an
environmentally—-.compatible manner by providing *the necessary ,
environmental data and control technology. Investigations include
analyses of the transport of energy-related pollutants and their health
and ecological effects; assessment^ of, and development of, control
technologies for energy systems; and integrated assessments of a wide
range of energy-related environmental issues. *
REVIEW NOTICE
This report has been reviewed by the participating Federal
Agencies , and approved for publication. Approval does not
signify that the contents necessarily reflect the views and
policies of the Government, nor does mention of trade names
or commercial products constitute endorsement or recommen-
dation for use.
This document is available to the public through the National' Technical
Information Service, Springfield, Virginia 22161.
-------
EPA-600/7-77-125b
November 1977
ENVIRONMENTAL ASSESSMENT
DATA BASE FOR LOW/MEDIUM-BTU
GASIFICATION TECHNOLOGY:
Volume II. Appendices A-F
by
E.G. Cavanaugh, W.E. Corbett,
" and G.C. Page
Radian Corporation
8500 Shoal Creek Boulevard
Austin, Texas 78758
Contract No. 68-02-2147, Exhibit A
Program Element No. EHE623A
EPA Project Officer: William J. Rhodes
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, N,C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
-------
CONTENTS
APPENDICES Page
APPENDIX A COAL GASIFICATION OPERATION A-l
Wellman-Galusha Gasifier A-15
Lurgi Gasifier A-25
Woodall-Duckham/Gas Integrale Gasifier A-37
Chapman (Wilputte) Gasifier A-47
Riley Morgan Gasifier A-57
Pressurized Wellman-Galusha (MERC) Gasifier.. A-67
GFERC Slagging Gasifier A-78
BGC/Lurgi Slagging Gasifier A-89
Foster Wheeler/Stoic Gasifier A-101
Winkler Gasifier A-109
Koppers-Totzek Gasifier A-121
Bi-Gas Gasifier A-132
Texaco Gasifier A-144
Coalex Gasifier A-154
APPENDIX B GAS PURIFICATION OPERATION . B-l
Rectisol Process B-2
Selexol Process B-12
Purisol Process B-16
Estasolvan Process B-20
Fluor Solvent Process B-24
iii
-------
CONTENTS (Continued)
APPENDICES
APPENDIX B: MEA (Monoethanolamine) Process B-28
(Cont'd.)
MDEA (Mothyldiethanolamine) Process B-32
DEA (Diethanolamine) Process B-36
DIPA (Dtisopropanolamine) Process B-40
DGA (Diglycolamine) Process B-44
Benfield Process B-48
Sulfinol Process B-53
Amisol Process B-58
APPENDIX C : AIR POLLUTION CONTROL C-l
Glaus Process C-2
Stretford Process C-13
Beavon Process C-22
SCOT (Shell Glaus Offgas Treating) Process... C-29
Direct-Flame Afterburners C-35
Catalytic Afterburners C-43
Carbon Adsorption C-51
APPENDIX D: WATER POLLUTION CONTROL D-l
Flocculation-Flotation D-2
Oil-Water Separators D-6
Filtration D-14
Phenosolvan D-18
Adsorption of Dissolved Organics D-23
IV
-------
CONTENTS (Continued)
APPENDICES Page
APPENDIX D: Biological Oxidation of Dissolved Organics... D-29
(Cont'd.)
Acid Gas Stripping D-36
Acid Gas Stripping (WWT) D-40
Forced Evaporation D-45
Evaporation Pond D-51
APPENDIX E: SOLID WASTE CONTROL E-l
Sanitary Landfill E-2
APPENDIX F: REFERENCES FOR VOLUME II F-l
v
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APPENDIX A
COAL GASIFICATION OPERATION
-------
Table A-l. SUMMARY OF PROMISING COAL GASIFIERS
Gasifier
ChAptBan
(Vilputce)
tfoodall-
Duckhas/
Gas
Integrale
GFESC
Slagging
Mley
Morgan
Winkler
Texaco
Pressurized
Wellnan-
Galusha
Gasification Gas/Solid
Pressure Bed (Type) Media Flow
ataospheric gravitating steaa plus countercurrent
air, or steaa
plus oxygen
atmospheric gravitating steaa plus eountercurrent
air, or stean
plus oxygen
high gravitating steaa plus countercurrent
oxygen
atmospheric gravitating stean plus countercarrent
air, or steam
plus oxygen
atmospheric fluidiced steam plus coontercurrent
air, or steaa
plus oxygen
high entrained stean plus co-current
air, or steam
plus oxygen
high gravitating stean plus countercurrent
air
Development
Status
ecmercially
available
(since 1945)
coaaereially
available
(siace 1940)
pilot plant
(reactivated
1976)
eonaexcially
available
pilot plant
(since 1975)
commercially
available
(since 1926)
pilot plant
pilot plant
(since 19S8)
Coanercial
Applications
production of
low-Btu fuel
gas
• low-Btu fuel
gas
• oxygen-blovn
synthesis gas
none
none
• synthesis
gas
•water gas
synthesis
none
Number in
Operation
2 present
10 inactive
•low-Btu gas:
72 present
•synthesis gas:
8 present
'
•synthesis gas:
6 present
8 past
•water gas:
23 past
Acceptable
Coal Types
all types
operated vith
air or oiyges
various 'j-pes
operated vith
air or oxygen
lignite.
lignite char,
bltuainous
char
lignite,
anthracite ,
caking and
noncaking
bituminous
several
types
operated
with QI
lignite and
bituninous
coal
caking and
noncaking
coals
(continued)
-------
Table A-l. SUMMARY OF PROMISING COAL GASIFIERS
(continued)
!>
u>
Casifier
Koppers-
Totzek.
BGC/I^rgi
Slagging
Lurgi
Foster
Wheeler/
Stoic
Bi-Gss
Weilcan-
Galusha
Coalex
Gasification Gas/Solid
Pressure Bed (Type) Media Flov
atmospheric entrained steam plus co-current
Of
high gravitating steaa plus countercurrent
Oz
high gravitating steals plus countercurrent
air, or steam
plus Oj
atmospheric gravitating steaa plus countercurrent
air, or steam
plus Oj
high entrained steam plus two stage
(two stage) 02
atmospheric gravitating steam plus countercurrent
air, or steam
plus 02
atmospheric entrained air plus co-current
additive
Development
Status
coioierciaily
available
(since 1S52)
pilot plan;
(1955-6i)
desonstratioa
plant (1976)
_
coosercially
available
(since 1936)
pilot plant
(under
construction)
pilot plant
(since 1976)
commercial ly
available
(since 1941)
conmercially
available
pilot plant
(since 1976)
CooBterclal
Applications
synthesis gas
none
•aecius-BCu
team gas
•synthesis gas
•aediun-Btu
fuel gas
firing boilers
for space
heating
none
• lou-3tu
fuel gas
•synthesis gas
• others
•low-Btu
fuel gas
Nuaber in
Operation
39 present
• town gas-
39 present
•synthesis gas:
22 present
•fuel gas-
5 present
• fuel gas-
8 present
•synthesis gas
undetermined
•others -
150 past
1 under
construction
Acceptable
Coal Types
all types
•noncaking
and weakly
caking
bituminous
•low and high
ash
•low and high
fusion temp.
various types
caking
•lignite
• subbituminous
•bituminous
•bituminous
• anthracite
• charcoal
•coke
all types
-------
Table A-2. SUMMARY OF GASIFIER OPERATING PARAMETERS (cont'd)
-p-
Gaslfler
Chapman
(Wilputte)
Woodall-
Duckhax/Gas
Integrale
GFERC
Slagging
Riley
Morgan
Winkler
Texaco
Pressurized
Vellaan-
Galusha
Gas Outlet
Tenperature
•K CF)
810 (1000)
to
920 (1200)
DtiA
360 (185)
to
845 (700)
840 (1050)
to
895 (1150)
865 (1100)
to
1060 (1450)
480 (400)
to
535 (500)
755 (900)
to
920 (1200)
OPERATING PARAMETER RABCES
Maxinun
Coal Bed Gasifier Coal Residence
Temperature Pressure Tiae in
°K (*F) MPa (psia) Gasifler (hrs)
^1310
C^-1900)
DNA
•V1645
(•x.2500)
1255 (1800)
to
1365 (2000)
1090 (1500)
to
1255 (1800)
1255 (1800)
to
2090 (3300)
1590 (2400)
to
1645 (2500)
0.101 2
(14.7)
0.101 t several
(14.7)
0.66 (95) 0.25 to 0.75
to
2.9 (415)
0.101 2-9
(14.7)
0.101 1-2
(14.7)
1.5 (215) several
to seconds
8.4 (1215)
0.103 (15) *2
to
2.1 (300)
NORMAL OPERATING PARAMETERS
Ma^mim
Gas Outlet Coal Bed
Temperature Temperature
•K (*?) "K (°F)
840 (1050) 1310 (1910)
top 395 (250) 1480 (2200)
side 920 (1200)
480 (400) VL645
C*.2500)
860 (1090) 1255 (1800)
to
1365 (2000)
980 (1300) 1090 (1500)
lignite
to
1255 (1800)
other
480 (400) 1535 (2300)
920 (1200) 1590 (2400)
to
1645 (2500)
Gasifier Coal Residence
Pressure Time in
MPa (psia) Gasifier (hrs)
0.101 2
(14.7)
0 . 101 several
(14.7) *
0.66 (95) 0.25 to 0.75
to
2.9 (415)
0.101 2-9
(14.7)
0.101 1-2
(14.7)
2.5 (365) several
seconds
0.69 (100) ^2
to
1.3 (195)
OKA - Data not available
(continued)
-------
Table A-2. SUMMARY OF GASIFIER OPERATING PARAMETERS
(continued)
Gasifier
Siypers-
lotzek
SGC/Lurgi
Slagging
Lurgi
Foster
Kbeeler/
Stoic
Bi-Cas
Wellman-
Galusha
Coalex
Gas Outlet
Tenperature
Off *O— >
A. V rj
1755 (2700)
to
1785 (2750)
470 (390)
to
1070 (1470)
645 (700)
to
865 (1100)
top 395 (250)
side 920 (1200)
1020 (1375)
to
1455 (2160)
700 (800)
to
1090 (1500)
1200 (1700)
to
1220 (1740)
OPERATING PARAMETER PANCES
Xaxin -a
Coal Bed
Ta=oeracure
"«. ccr;
2090 C330C)
to
2200 (3500)
>1535
(>2300)
1255 (180C-)
to
1695 (2500)
T-iiao
C-2200)
1755 (2700)
to
1920 (3000)
1590 CiCO)
1365 (2000)
Gasifier Coal Residence
Press-re Time in
XPa (?sia) Gasifier (hrs)
0.101 M. second
(14.7)
2.1 (300) 10 to 15
to minutes
2.8 (400)
2.1 (300) M.
to
3.2 (465)
0.101 several
(14.7)
1.6 (235) 3 to 22
to seconds
10.4 (1515)
0.101 2-9
(14.7)
0.101 DNA
(14.7)
Gas Outle;
Temperature
O-- / » — \
^ ( l!
1755 i270C)
620 (660)
to
720 (S-iQ1!
730 (350)
top 395 (25C)
side 920 (1200)
1200 (1700)
860 (10SS)
1200 (1700)
to
1220 (1740)
SORMAL OPERATING
HaxiKua
Coal Bed
Teoperature
'K CF)
2200 (3500)
>1535
(>2300)
1255 (1800)
to
1695 (2500)
M480
(^2200)
1755 (2700)
1590 (2400)
1365 (2000)
PARAMETERS
Gasifier
Pressure
>t?a (psia)
0.101
(14.7)
2.1 (300)
3.0 (435)
(02)
2.1 (300)
(air)
0.101
(14.7)
8.1 (1175)
0.101
(14.7)
0.101
at'.T)
Coal Residence
Time in
Gasifier (hrs)
M second
10 to 15
minutes
M
several
Stage 1
2 seconds
Stage II
6 seconds
2-9
DNA
DNA - Data not available
-------
Table A-3. SUMMARY OF GASIFIER MATERIAL REQUIREMENTS
Gaslfiar
Cha?asa
(«Jii?at:£a)
Voodall-
r»-i-V-a-j/
Gas
Integrals
G7Z31C
Slagging
Siley
Morgan
Winkler
Texaco
Pressurized
Wellman-
Calusha
Coal
Feedstock
Type
all types
• lignite
•bituoiaous
•bituminous
char
•lignite char
•lignite
•anthracite
•bituminous
- caking
- noncakiiig
•lignite
• subbitmninous
•weakly caking
bituminous
•lignite
•bituminous
all types
Coal
Feedstock
Size
BE (in)
<102(4)
6.4 to 38.1
(0.25 to 1.5)
6.4 to 19
(0.25 to C.75)
3.2(0.125)
to 51(2.0)
<9. 53(0. 38)
70% less
than 0.074
(0.003)
usually
50% less than
12.7(0.5)
Coal
leedstock
Kate g/sec-BZ
(Ib/hr-ft2)
43.6(32)
100(74)
262 to 1288
(193 to 947)
47 to 204
(35 to 150)
177 to 191
(130 to 140)
M08(300)
99 to 228
(73 to 168)
Coal Steaa Oxygen Air
Pretreatment (kg/kg coal) C£*/'*g coal) (kg/Kg coal)
crushing and DXA 3SA DKA
sizing
crushing and 0.25 D8A 2.3
sizing; partial
oxidation may
be required for
strongly caking
coals
crushing and 0.30 to 0.46 0.48 to 0.55 SA
sizing; drying
to less than
35% moisture
crushing and ^0.6 D&A ^2.7
sizing
crushing; drying 0.2-0.3 0.5 2.5
to less than 30Z (Oj blown)
moisture for lig- 0.2 (air blown)
nite, to less
than 18% for
higher ranking
coals; partial
oxidation may be
needed
crushing, 0.1 to 0.6 0.6 to 0.9 UNA
pulverizing,
slurry
preparation
crushing and 0.32 to 0.7 BSA 2.3 to 4.1
sizing; no (air-blovn)
predrying is
necessary
Quench
Water
Makeup
m3/kg coal
(gal/lb coal)
DNA
DNA
DNA
DNA
DSA
DNA
DNA
(continued)
-------
Table A-3. SUMMARY OF GASIFIER MATERIAL REQUIREMENTS
(cont'd)
Gasifier
Koppers-
Totzek
3GC/Lurgi
Siaggiag
Lurgi
Foster
Wheeler/
Stoic
Bi-Gas
Wellman-
Galusha
Coalex
Coal
Dssl Feedstock
teeasiocx Size
Type aQ(in)
all types 70Z to 90Z
less than
0.074(0.003)
all cyjea 13 to 51
(0.5 to 2.0)
all types 3.2 to 38.1
(0.125 to 1.5)
• lignite 19.0 to 38.1
•subbituminous (0.75 to 1.5)
•noncaking
bituminous
all types 70% less than
0.074' (0.003)
•anthracite 'anthracite:
•bituminous 7.9-14.3
•coke (.31-. 56)
•bituminous:
26-51 Cl-2)
all types <0.074
(0.003)
Coal
Feedstock
Rate g/sec-m2
(Ib/hr-fc2)
431 to 734
(317 to 540)
702 to 1958
(516 to 1440)
136 to 544
(100 to 400)
408 to 8160
(300 to 6000)
^4080
(3000)
10-134(8-99)
DNA
Coal Steaa Oxygen
Pretreatsent (kg/kg coal) (kg/kg coal)
pulverizing; 0.14 to 0.59 0.73 to 0.95
drying to
approximate ly
1-8S aoiscure
crushing md 0.29 to 0.31 0.48 to 0.53
sizing; drying
to less than
20Z ooisture
crashing and 1.01 to 3.24 0.23 to 0.61
sizing; drying (Oj blcwa)
to less than 0.6 (air blown)
35Z •oisture;
partial oxidation
Bay be required
for strongly
caking coals
crushing and 0.37 NA
sizing; partial
oxidation nay be
required for
strongly caking
coals
crushing, 0.4 to 1.35 0.5 to 0.64
pulverizing,
slurry prepara-
tion
crushing and alrblown: .4 DNA
sizing 0* blown: DNA
pulverizing DNA NA
Quench
Vater
Kake«7
Air B3.'«s caai
(kg/kg coal) (gai 'lb coal)
DA 2SA
NA 2XA
1.3 to 1.9 3.3 x 10~*
(0.04)
(Oj blown)
2.13 Ib/coal DNA
•v-3.1 USA
3.5 IMA
2.7 to 6.1 DNA
DNA - data not available
HA - not applicable
-------
Table A-4. SUMMARY OF GASIFIER UTILITY REQUIREMENTS
Boiler
Feed water
m3/kg coal
(gal/ton coal)
Cooling Water
m3/kg coal
(gal/ton coal)
> Electricity
oo
Basis:
•Oxidant
•Coal Type
HHV
joule/kg
(Btu/lb)
Woodall-
Chapman Duckham JGFERC Riley
(Wilputte) Gas Integrale Slagging Morgan
DNA 2.75xlO~* DNA DNA
(66)
DNA DNA DNA DNA
DNA DNA DNA DNA
DNA
•Air Blown DNA DNA
•Pittsburgh
#8
DNA 3. 19x10 7 DNA DNA
(13860)
Winkler Texaco
8.26x10-" DNA
(198)
DNA DNA
DNA DNA
•Oa Blown DNA
•Illinois
#6
2.88xl07 DNA
(12530)
Pressurized
Wellman-
Galusha
DNA
DNA
DNA
DNA
DNA
(continued)
-------
Table A-4. SUMMARY OF GASIFIER UTILITY REQUIREMENTS
(continued)
Foster
Koppers- BGC/Lurgi Wheeler
Totzek Slagging Lurgi Stoic
Boiler
Feedwater
m3/kg coal
(gal /ton coal)
Cooling Water
m /kg coal
(gal/ton coal)
•f" Electricity
VO
Basis :
•Oxidant
•Coal Type
-
TSBH
joule/kg
(Btu/lb)
2.0xlO~3 DNA
(480)
DNA DNA
DNA DNA.
»02 Blown DNA
•Eastern
Coal
2. 91x10 7 DNA
(12640)
2.42xlO~3 DNA
(580)
DNA DNA
DNA DNA
•02 Blown DNA
•Pittsburgh
#8
3. 43x10 7 DNA
(14900)
Wellman-
Bi-Gas Galusha
DNA 4.2x10"*
(100)
DNA 5. 8x10" 2
(14000)
DNA DNA
DNA -Air Blown
•Bituminous
or Anthracite
DNA 3.2xl07
(14000)
Coalex
DNA
DNA
DNA
DNA
DNA
DNA - data not available
-------
Table A-5. SUMMARY OF GASIFIER EFFICIENCY AND GAS PRODUCTION RATE
Cold Gas (%)*
Overall
Thermal (%)2
Reference
Temp. °K (°F)
i
Oxygen Blown
Air Blown
Expected
Turndown Ratio3
Gasifier Efficiency
Woodall- Pressurized
Chapman Duckham GFERC Riley Wellman-
(Wilputte) Gas Integrale Slagging Morgan Winkler Texaco Galusha
DNA 77 85 64-68 55-72 77 79
DNA 88 DNA 71-78 69 DNA DNA
DNA 300 DNA DNA 300 DNA DNA
'= V (80> (8°)
Gas Production Rate Nm3/kg coal (scf/lb coal)
1.95 DNA 1.4-1.9 1.94 1.33-1.62 DNA NA
(33) (24-33) (32.8) (22.5-27.5)
1.77-3.54 DNA NA 3.47 DNA DNA 2.7-4.7
(30-60) (58.9) (46-79)
TWA 10° TWA DNA 10° 10° 10°
DNA 25 DNA DNA 25 15 ^
(continued)
-------
Table A-5. SUMMARY OF GASIFIER EFFICIENCY AND GAS PRODUCTION RATE(eontlnued)
Gasifier Efficiency
Cold Gas (Z)1
Overall
Thermal (%)*
Reference
Temp. °K (°F>
Oxygen Blown
Air Blown
Expected
Turndown Ratio3
rCold Gas Efficien
Wrall Thermal E
Koppers
Totzek
75
68
300
(80)
1.47-1.92
(25-32.5)
NA
100/60
(2 headed)
100/30
(4 headed)
BGC/Lurgi
Slagging
83
DNA
DNA
Gas Production
2.03-2.14
(34.4-36.2)
NA
DNA
Lurgi
63-80
76
300
(80)
Rate Nm3/kg
0.77-2.5
(13-42)
DNA
100
25
i
Foster
Wheeler
Stoic
DNA
89
DNA
coal (scf/lb
HA
3.24
(54.8)
100
20
Bi-Gas
69
65
DNA
coal)
1.33-1.62
(22.5-27.5)
DNA
100
50
Wellman-
Galusha
75
81
300
(80)
DNA
1.24-4.48
(21-76)
100
25
Coalex
DNA
90
DNA
NA
DNA
DNA
[Product Gas Energy Output] inn
"y ~ [Coal Energy Input] * 1UU
fficiency
The useful overall thermal
upon the ability
carbons and waste
3
[Total Energy^
[Total Ener
efficiency of a
Output (product gas, hydrocarbons,
gy Input (co
gasifier may
al, electric
power , and
and steam) ] „
steam) ]
100
vary from the ranges given depending
of the integrated system to use the energy contained in by-product hydro-
steam.
f
[Full Capacity
Output]
[Minimum Sustainable Output]
DNA = Data Not Available
NA - Not Applicable
-------
Table A-6. SUMMARY OF GASIFIER RAW PRODUCT GAS COMPOSITION
Chapman
(Wilputte)
Coal Type unspecified
HHV J/HM1
(Btu/scf)
Gasification
Media
CO (Z Vol)
Hj (Z Vol)
C2H,, -•• CjH, (Z Vol)
CH» (Z Vol)
COj (Z Vol)
N2 + Ar (Z Vol)
Oj (Z Vol)
H,S (Z Vol)
COS -I- CSj (Z Vol)
Mercaptans (Z Vol)
Ihioph«n«s (Z Vol)
SOi (Z Vol)
HjO (kg/kg coal)
Tar (kg/kg coal)
Tar Oil (kg/kg)
Crude Phenol* (ZV)
KH, (Z Vol)
HCN (Z Vol)
ParticulaCM*
(kg/kg coal)
Traci Elements
6.33x10*
(170)
steam/air
22.7
16.6
PR
3.6
5.9
51.0
0.2
HD
ND
NO
HD
ND
PR
ND
ND
PR
, PR
PR
PR
PR
Woodall-
Duckham
Gaa Integrale
Bituminous
1. 04xl07
(280)
ateam/02
37. S
38.4
0.4
3.5
18.0
2.2
ND
ND
ND
ND
ND
PR
PR
} .075
PR
PR
ND
PR
PR
CFERC
Slagging
Lignite w/slag
1.28xl07
(345)
ateam/Ot
58.4
30.1
0.8
4.8
5.7
ND
0.2
PR
ND
ND
ND
' ND
PR
1.4x10'*
5.9xlO"2
PR
ND
ND
PR
PR
Rile;
Morgan
SubbitunlnouB
5.7x10*
(153)
ateam/Oj
23.5
16.4
0.35
1.7
7.3
50.62
ND
0.12
PR
ND
ND
ND
PR
PR
PR
PR
PR
PR
PR
PR
Winkler
Subblcuminous
l.OxlO7
(270)
iteam/Oj
37.0
37.0
ND
3.0
20.0
3.0
ND
PR
ND
ND
ND
ND
PR
HP
HP
ND
ND
ND
PR
PR
Texaco
Bituminous
9.4x10"
(253)
•teaa/Oj
37.6
39.0
ND
0.5
20.8
0.6
NP
1.5
ND
ND
ND
ND
PR
ND
HP
HP
ND
ND
PR
PR
Pressurized
Hellaum-
Calusha
Subbltumlnous
5.6x10*
(150)
steaa/alr
16.0
19.0
0.3
3.5
12.6
48.4
ND
0.2
PR
ND
ND
ND
PR
3.4x10"*
PR
PR
PR
ND
1.7x10"*
PR
(continued)'
A-12
-------
Table A-6. SUMMARY OF GASIFIER RAW PRODUCT GAS COMPOSITION (cont'd)
CoeX Type
HHV 1/m'
(Btu/scf)
Gasification
Media
co (x vox)
Hi (X VoX)
CiH, + CzH, (X VoX)
CHu (X VoX)
CO* (X VoX)
NZ + Xr (X VoX)
Oj (X VoX)
HiS (X VoX)
COS + CSi (X VoX)
Mercaptana (X VoX)
Thlophenes (X VoX)
SOt (X VoX)
HiO (kg/kg coaX)
Tar (kg/kg coaX)
Tar Oil (kg/kg)
Crude FhenoXa (X VoX)
NHi (X VoX)
HCN (X VoX)
Partlculates*
(kg/kg coaX)
Trace Elements
Koppera-
Totzek
Bituminous
X.XxXO'
(290)
Steoa/Oj
52.35
35.66
FR >
XO.O
X.X2
ND
0.82
0.05
ND
ND
PR
FR
ND
ND
ND
<0.2
FR
0.06
PR
BGC/Lurgi
SXagglng
Bituminous w/alag
1.39x10'
(374)
steam/0]
61.3
28.05
} 8.XO
2.55
ND
ND
1.2X10-2**
9.8xXO'***
ND
ND
ND
FR
7.3xXO~*
PR
FR
PR
ND
X.lxXO-1
PR
Lurgl
Bituminous
X.XXxXO7
(298)
««./<>,.
X7.3
39.1
0.7
9.4
31.2
X.2
ND
X.I
5.4XXO-11**
FR
PR
PR
PR
S.BxXO"1
3.5xXO"2
PR
4.0xXO~'**
6.2xXO-3**
S.6xXO->
PR
Poster
Wheeler
Stole
unspecified
5.7x10*
(X53)
steoa/alr
24. XX
3. XI
X.92
ND
3.69
40.41
ND
0.04
ND
ND
ND
ND
0.43
3.7XXO"2
3.XxXO"2
ND
ND
ND
5.3xXO~2
PR
Bl-Gas
Bituminous
1.3xX07
(350)
steam/02
40.6
22.5
ND
X4.3
X2.9
0.6
ND
X.3
FR
ND
ND
ND
FR
HP
NP
ND
FR
ND
FR
FR
Hellman-
GaXusha
Bituminous
6.3x10*
(X68)
steam/air
28.6
X5.0
PR
2.7
3.4
50.3
ND
PR
PR
PR
PR
PR
PR
0.06
PR
PR
PR
PR
PR
PR
CoaXex
unspecified
4.9x10*
(X33)
air/
additive
20.7
X0.8
ND
0.5
4.4
62.8
0.8
PR
PR
m
m
PR
PR
HD
ND
HD
PR
PR
PR
PR
* • (coaX fines, ash)
** - (kg/kg coaX)
PR • component la probably present, amount not determined
ND • preeenca of component not determined
HP - component Is probably not present
A-13
-------
Table A-7. SUMMARY OF GASIFIER ADVANTAGES AND LIMITATIONS
Gaslfler
Chapman
(Wilputte)
Woodall-
Dockhaa Gas
Integrate
GFERC
S tagging
alley
Morgan
Winkler
Texaco
Pressurized
Wellman-
Galusha
Koppers-
Totzek
BGC/Lurgi
Slagging
Lurgi
Foster
Wheeler
Stoic
Bi-Gas
Wellnan-
Galusha
Coalex
Capacity
low
DNA
high
lov
low
DHA
low to
•oderate
DNA
high
•oderate
DHA
high
low
DHA
Ability
To Handle
Caking Coals
w/o Pretreatoent
DNA
poor
moderate
good
poor to
moderate
good
good
good
good
good to
•oderate
poor
good
good (requires
use of agitator)
good
Tenperature
Control
DHA
good
DHA
DHA
good
DHA
DKA
DSA
DHA
DHA
DHA
poor
DSA
DHA
Refractory
Problems
DNA
DSA
•oderate
DSA
good
DHA
DHA
DSA
•oderate
good
DKA
poor
DHA
DHA
By-Product
Tar
Formation
yes
yes
yes
yes
probably not
probably not
yes
probably not
yes
yea
yes
probably not
yes
probably not
Ability to
Extract Ash
Low In Carbon
DNA
good
good
DNA
poor
good
poor to
moderate
poor to
moderate
good
soderate
•oderate
good
good
good
Ability
to Consume
Fine Carbon
Particles
poor
poor
good
node rate
to poor
good
excellent
•odarate
to poor
excellent
good
DNA
poor
excellent
poor
excellent
Bed Type
gravitating
gravitating
gravitating
gravitating
£luidized
entrained
gravitating
entrained
gravitating
gravitating
gravitating
entrained
gravitating
entrained
DHA - data not available
-------
COAL GASIFICATION OPERATION GASIFICATION MODULE
FIXED BED GASIFIERS
Wellman-Galusha Gasifier
GENERAL INFORMATION
Process Function - Atmospheric coal gasification in a
gravitating bed by injection of steam plus air or steam
plus oxygen with countercurrent gas/solid flow,
Development Status - Commercially available since 1941.
Licensor/Developer - McDowell Welltnan Engineering Company
113 St. Clair Avenue, N.E.
Cleveland, Ohio 44114
Commercial Applications -
Production of low-Btu fuel gas: 8 gasifiers currently
in operation in the United States.
Production of synthesis gas: undetermined number of
gasifiers currently operating in Spain, Taiwan, and Cuba.
Other applications: 150 gasifiers have been
installed worldwide in the past 35 years. Exact
locations and uses are uncertain.
Applicability to Coal Gasification - Proven commercial
gasifier which can accept bituminous, anthracite, charcoal,
or coke and which can be operated with air or oxygen.
Glen-Gery Brick Company, Reading, PA, operates 6 gasifiers
with anthracite coal and air. Bituminous coal gasification
with oxygen has not been commercially demonstrated.
PROCESS INFORMATION
Equipment (Refs. 1, 2) -
• Gasifier construction: vertical, cylindrical steel
vessel.
• Gasifier dimensions: 0.5 to 3.0 meters (1.5 to 10.0 ft)
in diameter.
A-15
-------
Bed type and gas flow: gravitating bed; continuous
counter-current gas flow, vertical gas outlet near the
outer rim of the top of the gasifier.
Heat transfer and cooling mechanism: direct gas/solid
heat transfer; water jacket provides gasifier cooling.
Coal feeding mechanism: continuous feeding via multiple
feed pipes through the top of the gasifier; two-,stage
coal hopper; slide valves allow isolation of the bottom
hopper which supplies the feed pipes.
Gasification media introduction: continuous blowing
of steam plus air or oxygen at the bottom of the coal
bed through a slotted ash extraction grate.
Ash removal mechanism: eccentrically rotating slotted
grate at the bottom of the coal bed; cone shaped ash
hopper collects the ash for intermittent dumping.
Special features:
Cyclone at gas outlet removes entrained coal dust
from the product gas; cyclone can be flooded with
water to act as a shut off valve.
Vaporisation of water in gasifier steam jacket pro-
vides 1007o of air saturation'steam or 25% of oxygen-
blown steam requirements.
- Rotating, slotted ash grate which is eccentrically
mounted in order to break up the dry ash and force
it through the slots.
- Rotating, water-cooled agitator which spirals
vertically below the surface of the coal bed to
retard channeling and to maintain a uniform bed,
especially with caking coals; agitator provides a
25% increase in throughput rate over non-agitated
Wellman-Galusha gasifiers (agitator optional).
Flow Diagram - See Figure 1.
Operating Parameter Ranges (Refs. 3, 4) -
Gas outlet temperature: 700 to 1090°K (800 to 1500°F).
Maximum coal bed temperature: approximately 1590°K
(2AOO°F)
A-16
-------
STIRRER
COAL I ^-
VENT
GASES
COAL
STORAGE
FEEDING
COMPARTMENT
COAL FINES
LOW / MEDIUM
BTU GAS
QUENCH
WATER
ASH
Figure 1. Wellman-Galusha Gasifier.
-------
Gasifier pressure: atmospheric
Coal residence time in gasifier: approximately 2 to 9
hours.
Normal Operating Parameters (Refs. 5,6)-
• Gas outlet temperature: 860°K (1088°F)
• Maximum coal bed temperature: 1590°K (2400°F)
Gasifier pressure: atmospheric
Coal residence time in gasifier: approximately 2 to
9 hours.
Raw Material Requirements (Refs. 7, 8) -
Coal feedstock requirements:
- Type: anthracite, bituminous, coke
- Size: 7.9 to 14.3 mm (0.31 to 0.56 in.) for
anthracite; 26 to 51 mm (1 to 2 in.) for bituminous.
- Rate: 10 to 134 g/sec-m2 (8 to 99 lb/hr-ft2)
Pretreatment required: crushing and sizing.
Steam requirements:
- Airblown operation: 0.4 kg/kg coal.
Oxygen blown operation: data not available.
Oxygen requirements: data not available.
Air requirements: 3.5 kg/kg coal.
Quench water make-up requirements: data not available.
Utility Requirements (Ref. 9) - Basis: Approximate values
for bituminous or anthracite coal feed for air blown opera-
tion. ;
• Boiler feedwater: 6.3 x 10"3 m3/kg coal (0.75 gal/lb
coal) for cooling of gasifier jacket; 4.2 x 10"* m3/kg
coal (0.05 gal/lb coal) net gasifier jacket consumption.
A-18
-------
• Cooling water: 8.3 x 10" * m3/kg coal (0.1 gal/lb coal)
for agitator cooling only. 5.8 x 10"2 m3/kg coal
(7.0 gal/lb coal) for indirect gas cooling only.
Electricity: data not available.
Process Efficiency (Ref. 10) - Basis: air-blown operation;
quenched and cooled product gas; bituminous coal feed with
HHV - 3.22 x 107 joule/kg (14,000 Btu/lb); reference tempera-
ture - 300°K (80°F).
Cold gas efficiency: 7570
r=i [Product gas energy output] ,nn
1 J [Coal energy input] X 1UU
• Overall thermal efficiency: 81%
, , [Total energy output (product gas + by-products + steam)]
[Total energy input (coal + electricity)]
Expected.Turndown Ratio (Ref. 11) - 100/25
r-i [Full capacity output]
L~J [Minimum sustainable output]
Gas Production Rate: Airblown: 2.12 x 10"2 to 3.2 x 10"2
Nm3/sec-m2 (265 to 400 scf/hr-ft2);
1.24 to 4-48 Nm3/kg coal
(21 to 76 scf/lb coal)
PROCESS ADVANTAGES
Coal type: gasifier can be operated with anthracite,
bituminous, charcoal or coke. The use of an optional
coal bed agitator allows gasification of caking coals.
Gasification media: gasifier can be operated with air
or oxygen.
• Start-up considerations: gasifier can be started up
in about 4 hours; gasifier can be maintained in a
standby condition with a few minutes of air blowing
once a day.
• Reactor size: small reactor size may be advantageous
for small scale industrial applications.
Development status: gasifier has been operated commer-
cially for many years.
A-19
-------
PROCESS LIMITATIONS
Process efficiency: maintaining the coal bed temperature
below the ash fusion temperature limits the maximum
process efficiency.
By-products produced: by-products require additional
processing for recovery.
Environmental considerations: process condensate and
by-products require additional processing for environ-
mental acceptability.
Operating pressure: low operating pressure may limit
utilization possibilities.
Reactor size: limited reactor size may necessitate use of
multiple units in parallel for large installations.
INPUT STREAMS (Refs. 12, 13)
Coal (Stream No. 1)
- Type:
- Size:
- Rate:
- Composition:
- HHV (Dry):
- Swelling number:
- Caking Index:
Bituminous
32 to 51 mm
(1.25 to 2.0 in.)
121 g/sec-m2
(89 lb/hr-ft2)
Anthracite
• 9 to 14 mm
(0.3 to 0.6 in.)
39 g/sec-m2
(29 lb/hr-ft2)
Data not available Data not available
3.2 x 107 joule/kg
(14,000 Btu/lb)
Data not available
Data not available
• Steam (Stream No. 2): M).4 kg/kg coal
• Oxygen (Stream No. 3): Not applicable
• Air (Stream No. 3): ^3.5 kg/kg coal
3.1 x 107 joule/kg
(13,500 Btu/lb)
Data not available
Data not available
^0.4 kg/kg coal
Not applicable
^3.5 kg/kg coal
A-20
-------
DISCHARGE STREAMS AND THEIR CONTROL (Refs. 14, 15)
& '
The Wellman-Galusha gasifier will produce the following
discharge streams. Stream numbers refer to Figure 1.
Gaseous Discharge Streams -
• Low/medium-Btu gas (Stream No. 10)
Coal bin gas (Stream No. 7)
Ash hopper gas (Stream No. 6)
Liquid Discharge Streams -
Process condensate and gas quenching liquor (Stream No. 9)
Solid Discharge Streams -
• Ash (Stream No. 4)
Coal fines (Stream No. 8)
The following text discusses the compositions of these
discharge streams and the control methods which can be used to
treat them, using as a basis the INPUT STREAM data given above
and the following gasifier conditions:
Coal type: Bituminous Anthracite
• Gasifier pressure: 0.101(14.7) 0.101(14.7)
MPa (psia)
- Steam/air: kg/kg 0.114 0.114
Gas outlet temperature
•K (°F) Data not available
• Gas production rate:
Nm3/kg coal (scf/lb coal) Data not available
Low/Medium-Btu Gas (Stream No. 10) - The composition of
the low/medium-Btu gas from the Wellman-Galusha gasifier
will be dependent on the nature of the coal feed, gasifier
operating conditions, and the gas cooling operations applied
to the raw gas stream. The compositions given below list
the components in the raw gas (Stream No. 5) for bituminous
and anthracite coal feedstocks. This gas stream may con-
tain significant amounts of H2S, organic sulfur compounds,
A-21
-------
C02 , heavy hydrocarbons, and water which may require removal
prior to utilization of the gas. Processes that can be used
to remove these contaminants are described in the acid gas
removal section.
Coal Type
Bituminous Anthracite
Component Component Vol7o Compottent Vol%
C02 28.6 27.1
H2 15.0 16.6
CH,, 2.7 0.5
Cj-m PR PR
C2H5 PR PR
C02 3.4 3.5
N2+Ar 50.3 56.8
02 ND ND
H2S PR PR
COS + CS2 PR PR
Mercaptans PR PR
Thiophenes PR PR
S02 PR PR
H20 PR PR
Naphthas PR PR
Tar (kg/kg coal) (0.06) ND
Tar Oil PR PR
Crude Phenols PR ND
NH3 PR PR
HCN PR PR
Particulates
(coal fines, ash) ' PR PR
Trace elements PR PR
HHV (Dry basis): 6.3 x 106 (168) 5.4 x 106 (146)
joule/Nm3 (Btu/scf), joule/Nm3 (Btu/scf)
Gasification media: Steam/air Steam/air
ND = presence of component not determined
PR » component is probably present, amount not determined
Component volume % is given on a relative basis to all other
components that have a value for volume 70 listed.
Coal Bin Gas (Stream No. 7) - This gaseous discharge stream
is created when the slide valves at the bottom of the coal
feed hopper open,to allow the coal feed to enter the gasi-
fier. A small amount of raw product gas from the gasifier
fills the space in the hopper as the coal is discharged.
When the slide valves at the top of the coal feed hopper
A-22
-------
open to admit another charge of coal, this gas can escape
to the atmosphere through the feed bin. The composition of
this stream should be similar to the raw gas (Stream No. 5),
although some constituents may condense or be adsorbed on
the surface of the coal feed. In order to prevent the re-
lease of these components to the atmosphere, this stream
may be collected using hoods and then incinerated or
recycled to the raw gas (Stream No. 5) or air intake
(Stream No. 3).
Ash Hopper Gas (Stream No. 6) - This gas stream is discharged
when the ash hopper is opened in order to dump accumulated
ash. This gas stream could potentially contain any of the
components found in the raw gas (Stream No. 5). Under normal
operating conditions, this stream would consist mainly of
steam plus air or oxygen, with traces of particulate and
volatile material from the ash. If the ash is quenched
prior to being dumped from the hopper, this gas stream
could also contain any volatile compounds in the quench water.
If any of these hazardous components are present in signi-
ficant concentrations in this gas stream, it would be
necessary for the ash hopper gas to be collected and then
either recycled, incinerated, or passed through a scrubber
prior to discharge.
Process Condensate and GasQuenching Liquor (Stream No. 9) -
If a direct quench is used, this stream will be composed
mostly of water. The other components in this stream will
be the constituents of the raw gas (Stream No. 5) which
condense or dissolve in the quench water. The components
most likely to be present in this stream are:
H20
Tar
Tar oil
Naphthas
Crude phenols
Particulates
(coal fines, ash)
NH3
H2S
Organic sulfur compounds
Thiocyanates
HCN
Trace elements
The amounts of these components will be dependent on the
raw gas composition and the gas cooling or quenching pro-
cesses used. Processes that can be used to remove .these
contaminants are described in the water pollution control
section.
Ash (Stream No. 4) - This stream will be composed mainly
of the mineral matter present in the feed coal with approxi-
mately 0.1% unreacted carbon. The exact composition of
A-23
-------
the ash is dependent on the composition of the feed coal
and the gasifier operating conditions. If the ash is
quenched, other constituents from the quench water may be
present in this stream. The ash from the gasifier is a
solid waste product which requires ultimate disposal.
Methods that can be used for ash disposal are described in
the solid waste treatment section.
Coal Fines (Stream No. 8) - If a cyclone is used for parti-
culate removal, this stream will be composed of small, hot
particles of coal, ash and tar which are removed from the
raw gas (Stream No. 5). Any of the heavy solid or liquid
constituents present in the raw gas could potentially be
present in this stream. These coal fines may be sent to
disposal with the gasifier ash (Stream No. 4), recycled to
the gasifier coal feed (Stream No. 1) in a briquette form,
or they may be burned as a fuel, depending on their carbon
content.
REFERENCES NOT CITED
L-860 Mudge, L. K., et al., The Gasification of Coal. Energy
Program Report. Richland, WA, Battelle Pacific North-
west Labs., 1974.
L-1436 Howard-Smith, I., and G- J. Werner, Coal Conversion
Technology. Park Ridge, NJ, Noyes Data Corp., 1976.
L-1445 Hall, E. H., et al., Fuels Technology. A State-of-the-
Art Review. Report No. PB-242 535, EPA-650/2-75-034,
EPA Contract No. 68-02-1323, Task 14. Columbus, OH,
Battelle Columbus Labs., April 1975.
L-1924 Hamilton, G. W., "Gasification of Solid Fuels", Cost
Engineering 8_ 4-11 (4 July 1963).
A-24
-------
COAL GASIFICATION OPERATION GASIFICATION MODULE
FIXED-BED GASIFIERS
Lurgi Gasifier
GENERAL INFORMATION
Process Function - High pressure coal gasification in a
gravitating bed by injection of steam plus air or steam
plus oxygen with countercurrent gas/solid flow.
Development Status - Commercially available since 1936.
Licensor/Developer - Lurgi Mineraloltechnik GmbH
American Lurgi Corporation
377 Rt. 17 South
Hasbrouck Heights, New Jersey
Commercial Applications (Ref. 16) -
Production of medium-Btu town gas: 39 gasifiers currently
in operation.
Production of synthesis gas: 22 gasifiers currently in
operation.
Production of medium-Btu fuel gas: 5 gasifiers currently
in operation.
Applicability to Coal Gasification - Proven commercial gasi-
fier which can accept various types of coal feedstocks, and
which can be operated with air or oxygen. Largest installa-
tion is at Sasolburg, South Africa; no commercial installa-
tions are located in the United States.
PROCESS INFORMATION
Equipment (Refs. 17, 18, 19, 20, 21) -
• Gasifier construction: vertical, cylindrical steel
pressure vessel.
A-25
-------
Gasifier dimensions:
- 2.5 to 3.8 m (8.3 to 12.4 ft) in diameter
- 2.1 to 3.0 m (7 to 10 ft) coal bed depth
- 5.8 m (19 ft) approximate overall height of gasifier
Bed type and gas flow: Gravitating bed; continuous
countercurrent gas flow; lateral gas outlet near the
top of the gasifier.
Heat transfer and cooling mechanism: Direct gas/solid
heat transfer; water jacket provides gasifier cooling.
Coal feeding mechanism: Intermittent, pressurized lock
hopper at the top of the gasifier which dumps the coal
onto a rotating, water-cooled coal distributor.
Gasification media introduction: Continuous injection
of steam plus air or oxygen at the bottom of the coal
bed through a slotted' ash extraction grate.
Ash removal mechanism: Rotating, slotted grate at the
bottom of the coal bed; refractory lined, pressurized
lock hopper collects the ash and dumps it intermittently.
Special features:
Direct quench gas scrubber and cooler which knocks
out particulates, tars, oils, phenols and ammonia
' is attached to the gasifier at the gas outlet.
Gasifier water jacket supplies approximately 10
percent of the required gasification steam.
- Rotating coal distributor provides uniform coal bed
depth.
- Tar injection nozzle at the top of the gasifier permits
recycle of by-product tar which also helps to reduce
coal fines carryover in the product gas (optional
feature).
- Rotating, water cooled coal bed agitator aids the
gasification of strongly caking coals (optional
feature).
A-26
-------
Floy Diagram - See Figure 1.
Operating Parameter Ranges (Ref'. 22) -
• Gas outlet temperature: 644 to 866°K (700 to HOO'F).
• Marfimum coal bed temperature: 1255 to 1644°K (1800 to
2500°F).
• Gasifier pressure: 2.1 to 3.2 MPa (300 to 465 psia)
Coal residence time in gasifier: approximately one hour.
Normal Operating Parameters (Refs. 23, 24, 25)
• Gas outlet temperature: 727°K (850°F)
• Maximum coal bed temperature: 1255 to 1644°K (1800 to
2500°F).
Gasifier pressure:
- Oxygen-blown operation - 3.0 MPa (435 psia)
- Air-blown operation - 2.1 MPa (300 psia)
Coal residence time in gasifier: approximately one hour
Raw Material Requirements (Refs. 26, 27, 28, 29, 30, 31)
• Coal feedstock requirements:
Type: All types; strongly caking coals require
agitator and/or increased steam rate.
- Size: 3.2 to 38.1 mm (0.125 to 1.5 in); coal is
usually fed in two size ranges; coal with up to 10%
below 3.2 mm (0.125 in) can be gasified.
- Rate: 136 to 544 g/sec-m2 (100 to 400 Ib/hrrEt2).
- Pretreatment required: crushing and sizing; drying
to less than 35% moisture; partial oxidation may be
required for strongly caking coals in gasifiers
without agitators.
A-27
-------
COAL
ro
CO
COAL LOCK
FILLING GAS '
QUENCH
LIQUOR
STEAM
COAL LOCK
VENT
7>-«-GAS
ASH
. QUENCH }-
ASH LOCK (CHAMBER
FILLING GAS
CONOENSATE
-i QUENCH WATER
CONDENSATE
LOW/MEDIUM
BTU GAS
WET ASH
Figure 1. Lurgi Gasifier
-------
Steam requirements:
- Oxygen-blown operation - 1.01 to 3.24 kg/kg coal
Air-blown operation - 0.6 kg/kg coal
Oxygen requirements: 0.23 to 0.61 kg/kg coal as pure oxygen
Air requirements: 1.3 to 1.9 kg/kg coal
Quench water makeup requirements: Oxygen-blown operation:
approximately 3.3 x W~k m3/kg coal (0.04 gal/lb coal).
Utility Requirements (Ref. 32) - Basis: Oxygen-blown opera-"
tion; Pittsburgh #8 coal, HHV - 3.43 x 107 joule/kg
(14,900 Btu/lb)
• Boiler feedwater: 2.42 x 10"3 m3/kg coal (580 gal/ton
coal)
Cooling water: Data not available.
Electricity: Data not available.
Process Efficiency (Refs. 33, 34) - Basis: Oxygen-blown
operation;quenched and cooled product gas; subbituminous
coal feed HHV (dry) - 19.3 x 10% joule/kg (8380 Btu/lb);
reference temperature =300°K (80°F).
• Cold gas efficiency: 63% to 80%
[-] [Product gas energy output]
[Coal energy input] x
Overall thermal efficiency: 76%
'0
[ - ] [Totaj^ energy output (product gas + HC by-products + steam)] .._
[Total energy Input (coal + electric power)] x
Expected Turndown Ratio (Ref. 35) - 100/25
t•] [Full capacity output]
[Minimum sustainable output]
Gas Production Rate (Refs. 36, 37) - Oxygen-blown: 0.11
to 1.0 NnT/sec-m* (1375 to 12;500 scf/hr-ft2); 0.77 to
2.5 Nm3/kg coal (13 to 42 scf/lb coal).
A-29
-------
PROCESS ADVANTAGES
Coal type: Gasifier can accept caking and non-caking
coals.
Gasification media: Gasifier can be operated with air
or oxygen
Operating pressure: High-pressure operation favors the
formation of methane in the gasifier and reduces product
gas transmission costs. High pressure may also be
advantageous for combined-cycle or synthesis gas
utilization.
Development status: Gasifier has been operated commer-
cially for many years.
Reactor size: Small reactor size may be advantageous
for small-scale industrial applications.
PROCESS LIMITATIONS
Coal type: Caking coals reduce throughput rate and
increase steam consumption which also increases the
amount of liquid waste to be treated.
Process efficiency: Maintaining the coal-bed tempera-
ture below the ash fusion temperature limits the
maximum process efficiency.
By-products produced: By-products require additional
processing for recovery.
Environmental considerations: Process condensate and
by-products require additional processing for environ-
mental acceptability.
Steam conversion: Maintaining a low coal bed temperature
results in low steam conversion.
Reactor size: Limited reactor size may necessitate use
of multiple units in parallel for large installations.
A-30
-------
INPUT STREAMS (Refs. 38, 39)
Coal: (Stream No. 1)
- Type:
- Size: mm
(in)
Montana
Subbituminous A
6.4 to 31.8
(0.25 to 1.25)
Illinois No. 6
High Volatile C
Bituminous
6.4 to 31.8
(0.25 to 1.25)
New Mexico
Subbituminous C
2.0 to 44.4
(0.08 to 1.75)
- Rate: g/sec-nr
(lb/hr-ft2)
- Composition:
Volatile matter
Moisture
Ash
Sulfur (dry basis)
- HHV: J/kg
(Btu/lb)
- Swelling number:
- Caking index:
• Steam: (Stream No. 2)
• Oxygen: (Stream No. 3)
• Air: (Stream No. 3)
DISCHARGE STREAMS AND
140
(103)
. 29.2%
24.7%
9-7%
1.45%
2.63 x 107
(11,436)
0
0
1.9 kg/kg
DAF coal
0.4 kg/kg
DAF coal
NA
THEIR CONTROL
131
(96)
34.7%
10.2%
9.1%
3.13%
2.94 x 107
(12,770)
3
15
1.9 kg/kg
DAF coal
0.4 kg/kg
DAF coal
NA
337
(248)
31.0%
16.4%
17.8%
0.63%
2.03 x 107
(8838)
2
0
0.965 kg/kg
DAF coal
NA
1.99 kg/kg
DAF coal
The Lurgi gasifier will produce the following discharge
streams. Stream numbers refer to Figure 1.
A-31
-------
Gaseous Discharge Streams -
Low/medium-Btu gas (Stream No. 10)
Coal lock gas (Stream No. 7)
Ash lock gas (Stream No. 6)
Liquid Discharge Streams -
Process condensate and gas quenching liquor (Stream No.
8 and 9)
Ash quench water (Stream No. 4)
Solid Discharge Streams -
Ash (Stream No. 4)
The following text discusses the compositions of these discharge
streams, using as a basis the INPUT STREAM data given above and
the following gasifier conditions:
Coal type:
Subbltuminou8 A High Volatile Subbitumlnous C
C Bituminous
• Gasifier pressure:
• Steam/02 (kg/kg):
Steam/air (kg/kg):
Gas Outlet
temperature:
•• Gas production
rate: NmVkg coal
(scf/lb coal)
2.65 MPa
(385 psia)
5.13
NA
654°K
(718°F)
2.08
(35.3)
2.59 MPa
(375 psia)
5.5
NA
881°K
(1126°F)
2.17
(36.8)
2.07 MPa
(300 psia)
NA
0.485
Data not available
3.10
(52.5)
Low/Medium-Btu Gas (Stream No. 10) - The composition of the
low/medium-Btu gas from the Lurgi gasifier will be dependent
on the composition of the coal feed, gasifier operating
conditions, and the gas cooling operations applied to the
raw gas stream. The compositions given below list the com-
ponents in the raw gas (Stream No. 5) for subbituminous and
bituminous coal feedstocks. Because this gas stream contains
significant amounts of H2S, organic sulfur compounds, C02,
heavy hydrocarbons and water, further treatment may be re-
quired prior to utilization of the gas. Processes that can
be used to remove these contaminants are described in the
acid gas removal section.
A-32
-------
Component
CO
Hz
CHi
C2H«» )
C2He f
CO 2
Nz+Ar
02
H2S
COS + CSz
(kg/kg coal)
Mercaptans
Thiophenes
SO 2
HzO
Naphthas
(kg/kg coal)
Tar (kg/kg coal)
Tar Oil (kg/kg coal)
Crude Phenols
NH3 (kg/kg coal)
HCN (kg/kg coal)
Particulates (coal
fines, ash)
(kg/kg coal)
Trace elements
HHV (dry basis):
Subbituminous A
Component Vol%
Coal Type
High Volatile
C Bituminous
Component Vol%
(9
15,
41.
11.2
0.5
30.4
1.2
ND
0.5
,2 x 10"*)
PR
PR
ER
PR
(8.6 x 10~3)
(3.0 x 10)
(3.2 x 10~2)
PR
(2.0 x 10" )
(6.0 x 10~6)
(3.7 x 10"2)
PR
1.14 x 107 J/Nm3
(307 Btu/scf)
(5
(1
(3
(3
17.3
39.1
9.4
0.7
31.2
1.2
ND
1.1
.4 x 10~4)
PR
PR
PR
PR
.0 x 10~2)
.8 x 10~2)
.5 x 10~3)
PR
(4.0 x 10 )
(6.2 x 10)
(5.6 x 10"3)
PR
Subbituminous C
Component Vol%
17.4
23.3
5.1
0.63
14.8
38.5
ND
0.23
PR
PR
PR
PR
PR
(1.6 x 10~2)
PR
PR
PR
PR
PR
PR
PR
1.11 x 107 J/Nm3 7.28 x 10 J/Nm3
(298 Btu/scf) (195 Btu/scf)
Gasification media: Steam/oxygen Steam/oxygen Steam/air
ND = presence of component not determined
PR « component is probably present, amount not determined.
Component volume % is given on a relative basis to all other components
that have a value for volume % listed.
A-33
-------
Coal Lock Gas (Stream No. 7) - The composition of this gas
stream will be determined by the mode of pressurizing the
coal lock. Various operating procedures and sources of
pressurizing gas could be used. Prior to dumping the coal
from the lock into the gasifier, the lock may be pressurized
to the gasifier operating pressure with a stream of cooled
raw gas or with a vent stream from an acid gas removal
or oxygen production process. If the pressurizing gas is
added continuously as the coal dumps into the gasifier, the
gas remaining in the lock will have approximately the same
composition as the pressurizing gas. If no gas is added as
the coal is dumped, raw gas from the gasifier will back-flow
into the lock as the coal falls into the gasifier, and the
gas remaining in the lock will be composed of pressurizing
gas and raw gas from the gasifier. If no pressurizing gas
is used, the lock will fill with raw gas as the coal is
dumped into the gasifier, and the gas remaining in the lock
will be composed of raw gas. For any of these procedures,
as raw gases pass countercurrently through the incoming coal
and into the lock, tars, oils, water and other constituents
of the raw gas may condense or be adsorbed on the surface
of the coal feed. In addition to the components in the raw
gas (Stream No. 5) and the lock filling gases, the coal
lock gas may also contain entrained coal fines. The gas
which remains in the lock after depressurization will be
displaced by the incoming coal charge. In order to prevent
the release of this stream to the atmosphere, this stream
may be recycled to the raw gas stream or it may be incin-
erated in a flare or boiler. If gaseous contaminants in
this stream are relatively low in concentration, the stream
may be passed through wet cyclones to remove particulates,
and then vented to the atmosphere.
Ash Lock Gas (Stream No. 6) - The composition of this gas
stream will be determined by the mode of pressurizing the
ash lock. The ash lock may be pressurized with steam
prior to opening the top valve to admit ash from the gasifier,
or the top valve may be opened without pressurizing the ash
lock. In either case, gases from the gasifier can flow
into the coal lock as it fills with ash. The ash in the
lock may be cooled with a water spray, or the ash may be
discharged from the lock into a quench bath. This contact
of the hot ash and water can generate steam and ash dust,
any unburned char can react with the steam, and any organic
contaminnats in the quench water can be thermally cracked.
These reactions contribute to the composition of the gas
stream which is released when the ash lock is depressurized.
This stream is usually passed through steam condensers
which remove some of the particulates. The gas may be
treated further in cyclones, or it may be vented directly
or incinerated. The gases which are emitted as the ash is
dumped from the lock may be collected by hoods and ducts and
A-34
-------
may be treated by the methods described above for treating
the coal lock gas.
Process Condensate and Gas Quenching Liquor (Stream Nos.
& and 9)~^hese liquid streams are composed of the raw gas
scrubbing liquor plus raw gas condensate from waste heat
boilers and indirect coolers. They contain approximately
95% water. Other components of these streams will be the
constituents of the raw gas (Stream No. 5) which condense
or dissolve in the quench water. The components most likely
to be present in this stream are:
H20 NH3
Tar H2S
Tar oil Organic sulfur compounds
Naphthas Thiocyanates
Crude phenols HCN
Particulates Trace elements
(coal fines and ash)
The amounts of these components will be dependent on the
raw gas composition and the gas quenching and cooling pro-
cesses used. Processes that can be used to remove these
contaminants are described in the water pollution control
section.
Ash Quench Water (Stream No. 4) - The ash from a Lurgi
gasifier is usually transported by means of a sluice trough
which also serves to cool the hot ash. The composition of
this stream will be dependent on the source of the water
used to sluice the ash. Generally, the gas quenching liquor
is used to cool and transport the ash. Slowdown streams
from other process units may also be used. In addition to
the components present in these input streams, the ash
sluice water will also contain any of the components in the
ash lock gas which condense as the ash lock is depressurized
plus suspended ash particles. This quench water may be
recycled to the water pollution control processes described
in Appendix D, or it may be sent to disposal in evaporation
ponds. This evaporation can result in atmospheric emis-
sion of the volatile components contained in the ash quench
water.
Ash (Stream No. 4) - The ash is composed of the mineral
matter in the feed coal with approximately 57* unreacted
carbon. The exact composition of the ash is dependent on
the composition of the feed coal and the gasifier operating
conditions. The ash can be separated from the ash sluice
water by the suspended solids removal processes described
A-35
-------
in the water pollution control section. The ash itself is
a solid waste product which requires ultimate disposal.
Methods that can be used for ash disposal are described in
the solid waste treatment section.
REFERENCES NOT CITED
L-966 Ricketts, T. S., "The Operation of the Westfield Lurgi
Plant and the High-Pressure Grid System", Inst. Gas
Eng. J. 3 563-88 (October 1963).
L-1024 Sherwin, Martin B., and Marshall E. Frank, Chemicals
from Coal and Shale - an R & D Analysis for~National
Science Foundation.Final Report. Report No. PB-243
393, NSF Grant No. NSF-EN-43237. New York, NY, Chem
Systems, Inc., July 1975.
L-1436 Howard-Smith, I., and G. J. Werner, Coal Conversion
Technology. Park Ridge, NJ, Noyes Data Corp., 1976.
L-1984 Ricketts, T. S., "Modern Methods of Gas Manufacture
Including the Lurgi Process", J. Inst. Fuel 37 (283),
328-41 (1964).
L-5772 Yugoslavia Lurgi Gasification Complex, "Information on
Gas Production by Gasification of "KOSOVO" Lignite in
Yugoslavia Using the "LURGI" Process", Attachment #2.
Kosovo, Yugoslavia, 1976.
A-36
-------
COAL GASIFICATION OPERATION GASIFICATION MODULE
FIXED-BED GASIFIERS
Woodall-Duckham/Gas Integrate Gasifier
GENERAL INFORMATION
Process Function - Atmospheric coal gasification in a
gravitating bed by injection of steam plus air or steam
plus oxygen with countercurrent gas/solid flow.
Development Status - Commercially available since 1940.
Licensor/Developer - Woodall-Duckham (USA) Limited
1910 Cochran Road
Pittsburgh, Pennsylvania 15220
Commercial Applications -
Production of low-Btu fuel gas: 72 gasifiers currently
in operation.
Production of oxygen-blown synthesis gas: 8 gasifiers
currently in operation.
Production of town gas with cyclic operation: 49
gasifiers currently in operation.
Applicability to Coal Gasification - Proven commercial
gasifier which can accept various types of coal feedstocks
and can be operated with air or oxygen. Largest instal-
lation is in Czechoslovakia.
PROCESS INFORMATION
Equipment (Refs. 40, 41, 42) -
Gasifier construction: Vertical, cylindrical steel
vessel with refractory lining in the upper two-thirds
of the gasifier.
Gasifier dimensions: 3.7 meters (12 ft) in diameter
A-37
-------
Bed type and gas flow: Gravitating bed, continuous
countercurrent gas flow; two lateral gas outlets near
the top of the gasifier which discharge gas from
different zones of the coal bed.
Heat transfer and cooling mechanism: Direct gas/solid
heat transfer, water jacket provides cooling for the
bottom third of the gasifier.
• Coal feeding mechanism: Buffer hopper and lock hopper
feed the coal intermittently to the top of the bed via
a coal distributor.
Gasification media introduction: Continuous injection
of steam plus air or oxygen at the bottom of the coal
bed through a slotted ash grate.
Ash removal mechanism: Rotating slotted grate at the
bottom of the coal bed.
Special features:
Internal gasifier baffles permit separation of the
product gas into a clear, tar-free side gas stream
and a top gas stream which contains volatiles and
tar.
Gasifier steam jacket provides 10070 of gasification
steam for air-blown operation; additional steam is
required for oxygen-blown operation.
Poke holes at the top and side of the gasifier permit
introduction of steam lances or poke rods.
For caking coals: clear gas outlet is at the top in
order to heat walls and prevent sticking of coal in
distillation zone.
- For noncaking coals: clear gas outlet is lower, near
the top of the gasification zone.
Flow Diagram - See Figure 1.
Operating Parameter Ranges (Refs. 43, 44) -
Gas outlet temperature: Data not available.
Maximum coal bed temperature: Data not available.
A-38
-------
VENT GAS
COAL
'—<$>
OIL
PRECIPITATOR
u>
vO
AIR /OXYGEN K3
CONDENSATE
CONDENSATE
LOW/MEDIUM
BTU GAS
ASH
Figure 1. Woodall-Duckham/Gas Integrate Gasifier
-------
Gasifier pressure: Atmospheric.
Coal residence time in gasifier: Several hours.
Normal Operating Parameters (Ref. 45) -
• Gas outlet temperature: 394°K (250°F) at top gas outlet
922°K (1200°F) at side gas outlet
• Maximum coal bed temperature: 1477°K (2200°F)
Gasifier pressure: Atmospheric.
Coal residence time in gasifier: Several hours.
Raw Material Requirements (Refs. 46, 47) -
Coal feedstock requirements:
Type: Lignite, bituminous.
- Size: 6.4 to 38.1 mm (0.25 to 1.5 in); coal is
usually fed in two size ranges.
- Rate: 100 g/sec-m* (74 lb/hr-ft2).
- Pretreatment required: Crushing and sizing; drying
is not required; partial oxidation may be required
for strongly caking coals with a free swelling
index greater than 2.5.
Steam requirements, air-blown operation: 0.25 kg/kg
coal.
Oxygen requirements: Data not available.
Air requirements: 2.3 kg/kg coal.
Quench water makeup requirements: Data not available.
Utility Requirements (Ref. 48) - Basis: Air-blown operation
Pittsburgh #8 coal, HHV (dry) - 3.19 x 107 joule/kg (13,860
Btu/lb).
• Boiler feedwater: 2.75 x 10""" m3/kg coal (66 gal/ton
coal)
Cooling water: Data not available.
Electricity: Data not available.
A-40
-------
Process Efficiency (Ref. 49) - Basis: Air-blown operation;
quenched and cooled product gas; coal type not specified;
reference temperature = 300°K (80°F).
• Cold gas efficiency: 77%
t=l [Product gas energy output] Y -,««
A JLUU
[Coal energy input]
• Overall thermal efficiency: 88%
[-] [Total energy output (product gas + HC by-products + steam)]
A
[Total energy input (coal + electric power)]
Expected Turndown Ratio (Ref. 50) - 100/25
[ = ] [Ful1 cap ac ity output]
[Minimum sustainable output]
Gas Production Rate - Data not available.
PROCESS ADVANTAGES
Coal types: predrying of the feed coal is not required.
Gasification media: can be operated with air or oxygen.
By-products produced: two-stage gas production allows
relatively simple by-product recovery.
Environmental considerations: two-stage operation may
require no direct water quenching of the gas streams
which limits the volume of wastewater requiring further
processing.
Start-up'considerations: gasifier can be started up in
24 hours and can be placed in a standby condition with
a minimal air supply.
Process efficiency: although maximum process efficiency
is limited by maintaining a coal bed temperature below
the ash fusion temperature, the two-stage operation of
the gasifier yields a fairly high thermal efficiency.
Reactor size: small reactor size may be advantageous
for small-scale industrial utilization.
A-41
-------
Development status: gasifier has been operated commer-
cially for many years.
PROCESS LIMITATIONS
Coal types: gasifier requires a coal with a free swelling
index of less than 2.5.
Environmental considerations: process condensate and
by-products require additional processing; poke holes
may be a source of emissions of raw product gas.
Operating pressure: product gas may require compression
for transmission or utilization in combined-cycle
applications.
Process efficiency: maintaining the coal bed temperature
below the ash fusion temperature limits the maximum
process efficiency.
Reactor size: limited reactor size may necessitate use
of multiple units in parallel for large installations.
INPUT STREAMS (Ref. 51) -
Coal (Stream No. 1)
- Type:
Size:
- Rate:
Composition:
- HHV: joule/kg
(Btu/lb)
- Swelling number:
- Caking index:
High volatile C
bituminous
6.35 to 38.1 mm
(0.25 to 1.5 in)
Data not available
Data not available
2.97 x 107
(12,900)
Less than 2.5
Data not available
Steam (Stream No. 2) : Data not available
Oxygen (Stream No. 3): Data not available
Air (Stream No. 3): NA
A-42
High volatile C
bituminous
6.35 to 38.1 mm
(0.25 to 1.5 in)
Data not available
Data not available
2.97 x 107
(12,900)
Less than 2.5
Data not available
Data not available
NA
Data not available
-------
DISCHARGE STREAMS AND THEIR CONTROL
The Wdodall-Duckham/Gas Integrale gasifier will produce the
following discharge streams. Stream numbers refer to Figure 1.
Gaseous Discharge Streams -
Low/medium-Btu gas (Stream No. 13)
• Coal hopper vent gas (Stream No. 7)
• Ash lock gas (Stream No. 6)
Liquid Discharge Streams -
Process condensate (Stream Nos. 11 & 12)
• Tar (Stream No. 9)
Solid Discharge Streams -
Ash (Stream No. 4)
• Dust (Stream No. 10)
The following text discusses the compositions of these discharge
streams, using as a basis the INPUT STREAM data given above and
the following gasifier conditions:
Coal type: High volatile C High volatile C
bituminous bituminous
Gasifier pressure: Atmospheric Atmospheric
Steam/02 : Data not available NA
• Steam/air: NA Data not available
Gas off-take temperature: Data not available Data not available
Gas production rate: Data not available Data not available
Low/Medium-Btu Gas (Stream No. 13) - The composition of the
low/medium-Btu gas from the Woodall-Duckham/Gas Integrale
fasifiers will be dependent on the composition of the coal
eed, gasifier operating conditions, and the processing
operations applied to the top gas and side gas streams. The
compositions given below list the components in the combined
top gas (Stream No. 8) and side gas (Stream No. 5) streams
A-43
-------
for bituminous coal feedstock. Because this gas stream.
contains significant amounts of H2S, organic sulfur compounds,
C02 , hydrocarbons and water, further treatment may be required
prior to utilization of the gas. Processes that can be used
to remove these contaminants are described in the acid gas
removal section.
Coal type
High volatile High volatile
C bituminous C bituminous
Component Component Vol % Component Vol %
CO 37.5 28.3
H2 38.4 17.0
CHi» 3.5 2.7
*C2H<» 0.4 0.3
C2H6 ND ND
C02 18.0 18.0
N2+Ar 2.2 47.2
02 ND ND
H2S ND ND
COS + CS2 ND ND
Mercaptans ND ND
Thiophenes ND ND
S02 PR PR
H20 PR PR
Naphthas PR PR
Tar Oil }
-------
Coal Hopper Vent Gas (Stream No. 7) - This gaseous discharge
stream is created when the valve at the bottom of the coal
feed hopper opens to allow the coal feed to enter the gasi-
fier. The raw gas in the top of the gasifier fills the feed
hopper as the coal is discharged into the gasifier. When
the valve at the top of the hopper opens to admit a new
charge of coal, the raw gas in the hopper is displaced up
through the surge hopper and potentially into the atmosphere.
The composition of this stream should be similar to the top
gas (Stream No. 8), although some constituents may condense
or be adsorbed on the surface of the coal feed. In order
to prevent the release of these components to the atmosphere,
this stream may be collected by hoods and then incinerated
or recycled to the raw gas or air intake.
Ash Lock Gas (Stream No. 6) - This gas stream is discharged
when the ash lock hopper is opened to dump accumulated ash.
This stream could potentially contain any of the components
in the raw gas (Stream Nos. 5 and 8). Under normal operat-
ing conditions, this stream will consist mainly of steam
plus air or oxygen, with traces of particulate and volatile
material from the ash. If the ash is quenched prior to being
dumped from the hopper, this gas stream could contain any
volatile compounds in the quench water. If any of these
hazardous components are present in significant concentra-
tion in this gas stream, it would be necessary for the ash
hopper gas to be collected and then either recycled, inciner-
ated, or passed through a scrubber prior to discharge.
Process Condensate (Stream Nos. 11 & 12) - This stream is
composed of the compounds in the top gas stream which
condense in the gas cooler or precipitate from the oil
precipitator, plus the compounds in the side gas stream which
condense in the gas cooler. The components most likely to
be present in this stream are:
H20
Tar
Tar Oil
Naphthas
Crude Phenols
Particulates (coal fines, ash)
NH3
H2S
Organic Sulfur Compounds
Thiocyanates
HCN
Trace elements
The amounts of these components will be dependent on the
composition of the top gas (Stream No. 8) and side gas
(Stream No. 5) and the tar and dust removal processes used
upstream of the gas cooling processes. If a direct quench
scrubber is used to cool the raw gas streams, this stream
will be much larger in total volume, and any components in
the quench water would be present in the process condensate
A-45
-------
stream. Processes that can be used to remove these contami-
nants are described in the water pollution control section.
Tar (Stream No. 9) - This stream is composed of the droplets
of tar and oil which are removed from the top gas stream by
the electrostatic precipitator. The compounds which make up
these tars and oils will be determined by the composition of
the feed coal and the operating conditions in the gasifier.
In addition to tars and oils, this stream may also contain
water, particulates, phenols, or any of :the components in
the raw top gas (Stream No. 8). The tars and oils in this
stream may be separated from the water, phenols, particu-
lates, or other contaminants in order to recover then as
by-products. The tar may be relatively free of contaminants,
in which case it could be utilized as a by-product without
additional treatment. Processes which can be used to
separate tar and oils from aqueous and solid contaminants
are described in the water pollution control section.
Ash (Stream No. 4) - The ash is composed of the mineral
matter in the feed coal with approximately 170 unreacted
carbon. The exact composition of the ash is dependent on
the composition of the feed coal and the gasifier operating
conditions. If the ash is quenched prior to discharge from
the ash lock hopper, other constituents from the quench
water may be present in this stream. The ash from the gasi-
fier is a solid waste product which requires ultimate dispo-
sal. Methods that can be used for ash disposal are
described in the solid waste treatment section.
Dust (Stream No. 10) - This stream is composed of fine par-
ticulates of coal and ash which are removed from the side
gas stream in the cyclone. Any of the heavy solid or liquid
constituents present in the raw side gas may be present in
this stream. The collected dust may be sent to disposal
with the gasifier ash, or it may be recycled to the gasifier
coal feed, possibly in a briquette form.
REFERENCES NOT CITED
L-1436 Howard-Smith, I., and G. J. Werner, Coal Conversion
Technology. Park Ridge, NJ, Noyes Data Corp., 1976.
A-46
-------
COAL GASIFICATION OPERATION GASIFICATION MODULE
FIXED BED GASIFIERS
Chapman (Wilputte) Gasifier
GENERAL INFORMATION
Process Function - Atmospheric coal gasification in a
gravitating bed by injection of steam plus air or steam
plus oxygen with countercurrent gas/solid flow.
Development Status - Commercially available since 1945.
Licensor/Developer - Wilputte Corporation
152 Floral Avenue
Murray Hill, New Jersey 07974
Commercial Applications - Production of low-Btu fuel gas:
2 gasifiers currently in operation
10 gasifiers currently inactive
Applicability to Coal Gasification - Proven commercial
gasifier which can accept all types of coal and which can
be operated with air or oxygen. U.S. Army ammunition
plant at Kingsport, Tennessee operates gasifiers with
bituminous coal and air. Lignite feed or operation with
oxygen has not been commercially demonstrated.
PROCESS INFORMATION
Equipment -
Gasifier construction: Vertical, cylindrical steel
vessel with refractory lining
Gasifier dimensions:
- 3.1 meters (10 ft.) in diameter
- approximately 0.7 meters (28 in) bed depth
Bed type and gas flow: Gravitating bed, continuous
countercurrent gas flow; lateral gas outlet near top
of the gasifier.
A-47
-------
Heat transfer and cooling mechanism: Direct gas/solid
heat transfer; water jacket provides gasifier cooling.
Coal feeding mechanism: Semi-continuous rotary hopper
which is an integral part of the top of the gasifier.
Gasification media introduction: Continuous blowing of
steam plus oxygen or steam saturated air at the bottom
of the coal bed through a tuyere in the center of the
ash grate.
Ash removal mechanism: Rotating slotted grate and
water sealed ash pan at the bottom of the coal bed;
a stationary ash plow removes the ash from pan and
discharges it into an ash trough. New designs may
incorporate dry seal ash pans.
Special features:
Tar liquor sprays and direct quench scrubbers cool
the product gas and knock out tars, oils, phenols,
and ammonia.
Rotating agitator which "floats" on the coal bed
provides even coal feed distribution and-prevents
caking.
Tar recycle injection at the top of the gasifier
provides direct utilization of by-product tar and
reduces coal fines carryover (optional).
- Poke holes at the top of the gasifier permit intro-
duction of steam lances for removal of tar deposits
and for breaking up clinkers
Flow Diagram - See Figure 1.
Operating Parameter Ranges -
• Gas outlet temperature: 910 to 922°K (1000 to 1200°F)
• Maximum coal bed temperature: approximately 1310°K
(1900°F)
Gasifier pressure: Atmospheric
Coal residence time in gasifier: Approximately 2 hours
A-48
-------
COAL
BARREL VALVE
VENT GAS
ELECTROSTATIC
PRECIPITATOH
STEAM
AIR /
OXYGEN
SECONDARY
WASH
COOLER
CONDENSATE
LOW / MEDIUM
BTU GAS
WET ASH
Figure 1. Chapman (Wilputte) Gasifier
-------
Normal Operating Parameters -
• Gas outlet temperature: 894°K (1050°F)
• Maximum coal bed temperature: 1310°K (1900°F)
• Gasifier pressure: Atmospheric
Coal residence time in gasifier: Approximately 2 hours
Raw Material Requirements - (Refs. 52, 53, 54)
• Coal feedstock requirements:
- Type: All types
Size: Less than 102 mm (4 in)
- Rate: 43.6 g/sec-m2 (32 lb/hr-ft2)
Pretreatment required: Crushing and sizing
Steam requirements: Data not available.
Oxygen requirements: Data not available
Air requirements: Data not available.
Quench water make-up requirements: Data not available.
Utility Requirements - Data not available.
Process Efficiency - Data not available.
Expected Turndown Ratio - Data not available.
Gas Production Rate - 0.15 to 0.31 Nm3/sec-m2 (1910 to 3820
scf/hr ft*); air blown: 1.77 to 3.54 Nm3/kg coal (30 to 60
scf/lb coal); Oxygen blown: 1.95 Nm3/kg coal (33 scf/lb
coal)
PROCESS ADVANTAGES
Coal type: gasifier can accept all types of coal.
Gasification media: gasifier can be operated with air
or oxygen.
A-50
-------
Steam production: gasifier steam jacket provides 100%
of steam requirement for air blown operation.
Reactor size: small reactor size may be advantageous
for small scale industrial application.
Development status: gasifier has been operated commer-
cially for many years.
PROCESS LIMITATIONS
Coal type: No commercial gasifiers are currently operat-
ing with caking bituminous coal or lignite.
Gasification media: Operation with oxygen has not been
commercially demonstrated. x
By-products produced: By-products produced require
additional processing for recovery.
Environmental considerations: process condensate and
by-products require additional processing for environ-
mental acceptability; emissions from poke holes and
ash pan may be difficult to contain and control.
Operating pressure: Low operating pressure may be a
disadvantage for certain types of utilization technolo-
gies or for transmission by pipeline.
Reactor size: Limited reactor size may necessitate
use of multiple units in parallel for large installations
INPUT STREAMS
Coal (Stream No. 1):
- Type: Data not available
- Size: Less than 102 mm (4in.)
- Rate: 43.6 g/sec-m2 (32 lb/hr-ft2)
Composition: Data not available
- HHV: Data not available
A-51
-------
Swelling number: Data not available
Caking index: Data not available
Steam (Stream No. 2): Data not available
Oxygen (Stream No. 3): Data not available
Air (Stream No. 3): Data not available
DISCHARGE STREAMS AND THEIR CONTROL
The Chapman (Wilputte) gasifier will produce the following
discharge streams. Stream numbers refer to Figure 1.
Gaseous Discharge Streams
Low/medium-Btu gas (Stream No. 13)
Barrel valve vent gas (Stream No. 6)
Poke hole gases (Stream Nos. 8 & 9)
• Ash pan gas (Stream No. 7)
Liquid Discharge Streams
Process condensate and gas quenching liquor (Stream
No. 11)
Solid Discharge Streams
Ash (Stream No. 4)
• Coal fines (Stream No. 10)
The following text discusses the compositions of these discharge
streams, using as a basis the INPUT STREAM data given above, and
the following gasifier conditions:
Coal type: Data not available.
Gasifier pressure: Atmospheric
• Steam/Oa (kg/kg): NA
Steam/air (kg/kg): Data not available
A-52
-------
• Gas off-take temperature °K(°F): 839 (1050)
• Gas production rate Nm3/kg coal (scf/lb coal): Data
not available.
Low/Medium Btu Gas (Stream No. 13) - The composition of
the low/medium-Btu gas from the Chapman (Wilputte) gasifier
will be dependent on the composition of the coal feed,
gasifier operating conditions, and the gas cooling opera-
tions applied to the raw gas stream. The composition given
below lists the components in the raw gas (Stream No. 5).
The coal feed type is not specified, and therefore this
composition should be considered as an approximation.
Because this gas stream contains significant amounts of
H2S, organic sulfur compounds, C02, heavy hydrocarbons,
and water further treatment may be required prior to
utilization of the gas. Processes that can be used to
remove these contaminants are described in the acid gas
removal section.
Unspecified
Coal type
Component Component Vol L
CO 22.7
H2 16.6
Cm 3.6
C2Hif PR
C2H6 PR
C02 5.9
N2 + Ar 51.0
02 0.2
H2S ND
COS + CS2 ND
Hercaptans ND
Thiophenes ND
SO 2 ND
H20 PR
Naphthas PR
Tar ND
Tar Oil ND
Crude Phenols PR
NH3 PR
HCN PR
Particulates (coal fines, ash) PR
Trace elements • PR
HHV (dry basis): 6.33 x 106 (170)
joule/Nm3 (Btu/scf)
A-53
-------
Gasification media: Steam/air
ND • presence of component not determined
PR - component is probably present, amount not determined
Component volume % is given on a relative basis to all
other components that have a value for volume "/<> listed.
Barrel Valve Vent Gas (Stream No. 6) - This gaseous dis-
charge stream is created as the coal feeding barrel valve
rotates and dumps a charge of coal into the gasifier.
A small amount of raw gas from the gasifier fills the
space in the feeder as the coal is discharged, and when
the barrel valve rotates to accept a fresh charge of coal,
the raw gas is displaced from the barrel valve by the
incoming coal and is discharged through a vent. The com-
position of this stream should be similar to the raw gas
(Stream No. 5), although some constituents may condense
or be absorbed on the surface of the coal feed. In order
to prevent the release of these components to the atmos-
phere, this stream may be collected and recycled to the
raw gas stream or air intake, or it may be incinerated.
Poke Hole Gases (Stream No. 8 & 9) - These gaseous dis-
charge streams are created when the poke holes at the top
of the gasifier or at the top of the cyclone are opened.
The poke holes are opened periodically to permit the
introduction of steam lances which are used to remove
tars which have accumulated on the walls of the gasifier
or the cyclone. If the coal feed does not form tars as
it is gasified, this operation may not be required, and
these discharge streams would not be present. When the
poke holes are open, the poke hole gases will be composed
of the constituents in the raw gas (Stream No. 5) plus
steam from the lances, plus entrained particles of coal
and tar. These streams may be collected by hoods and then
passed through steam condensers to knock out water and
condensables. This condensate stream would require
additional treatment, and it could be combined with the
process condensate and gas quenching liquor (Stream No. 11).
The gases passing through the condenser could be recycled
to the raw gas stream or incinerated.
Ash Pan Gas (Stream No. 7) - This gaseous discharge stream
is the result of evaporation of suspended or dissolved
components in the ash pan water seal. Any of the components
in the raw gas (Stream No. 5) plus any components present
in the water input to the ash pan may be present in this
stream. In addition, some entrained ash particulates may
be present in this stream. In new gasifier designs with
A-54
-------
dry ash pan seals, this stream would be replaced by an ash
hopper vent stream which could contain components from the
raw gas plus ash particles. This stream may be small enough
in magnitude to permit direct venting to the atmosphere or
it may be collected by hoods and then incinerated in a
flare or boiler.
Process Condensate and Gas Quenching Liquor (Stream No. 11) -
This liquid stream is composed of the raw gas scrubbing
liquor plus raw gas condensate from the waste heat boiler
and electrostatic precipitator. This stream will be com-
posed mostly of water, plus the constituents in the raw
gas (Stream No. 5.) which condense or dissolve in the quench
water. The components most likely to be present in this
stream are:
H20
Tar
Tar oil
Naphthas
Crude phenols
Particulates (coal fines,
ash)
NH3
HjS
Organic sulfur compounds
Thiocyanates
HCN
Trace elements
Processes that can be used to remove these contaminants are
described in the water pollution control section.
Ash (Stream No. 4) - This solid stream will be composed
mainly of the mineral matter present in the coal feed.
The exact composition of the ash is dependent on the compo-
sition of the feed coal and the gasifier operating condi-
tions. The ash may also contain any of the components
present in the water seal. The ash from the gasifier is
a solid waste product which requires ultimate disposal.
Methods that can be used for ash disposal are described in
the solid waste treatment section.
Coal Fines (Stream No. 10) - If a cyclone is used for
particulate removal, this stream will be composed of small,
hot particles of coal, ash and tar which are removed from
the raw gas (Stream No. 5). Any of the heavy solid or
liquid constituents present in the raw gas could potentially
be present in this stream. These coal fines may be sent
to disposal with the gasifier ash, or they may be recycled
to the gasifier coal feed, possibly in a briquette form.
Depending on their carbon content, the coal fines may be
burned as a fuel.
A-55
-------
REFERENCES NOT CITED
L-9032 U.S. Army Environmental Hygiene Agency, Air Pollution
Engineering Source and Ambient Sampling. Survey No.
21-032-71/72,HoTston Army Ammunition'Plant, Kingsport,
TN. 3 May - 30 June 1971. 15 August - 4 September J971.
A-56
-------
COAL GASIFICATION OPERATION GASIFICATION MODULE
FIXED-BED GASIFIERS
Riley Morgan Gasifier
GENERAL INFORMATION
Process Function - Atmospheric coal gasification in a gravi-
tating bed by injection of steam plus air or steam plus
oxygen with countercurrent gas/solid flow.
Development Status - Pilot plant since 1975.
Licensor/Developer - Riley Stoker Corporation
P.O. Box 547
Worcester, Massachusetts 01613
Commercial Applications - None. The gasifier is a modified
version of the Morgan gas producer. Numerous Morgan gas
producers were operated commercially in the past.
Applicability to Coal Gasification - Gasifier has been
successfully operated using anthracite, noncaking bituminous,
and caking bituminous coals with steam plus air. The gasi-
fier at the pilot plant is a commercial-size unit. Operation
with oxygen has not been demonstrated in the commercial-size
unit. The pilot plant unit is located in Worcester, MA.
PROCESS INFORMATION
Equipment (Refs. 55, 56) -
Gasifier construction: rotating, vertical, cylindrical
steel vessel with refractory lining.
Gasifier dimensions: 3.2 m (10.5 ft) in diameter
2.0 m (6.5 ft) bed depth
Bed type and gas flow: gravitating bed; continuous
countercurrent gas flow; vertical gas outlet at the top
of the gasifier. ,
«w
Heat transfer and cooling mechanism: direct gas/solid
heat transfer; water jacketed barrel, head, and ash pan
provide gasifier cooling.
A-57
-------
Coal feeding mechanism: semi-continuous twin lock hoppers
at the top of the gasifier.
Gasification media introduction: continuous injection of
steam plus air/oxygen at the bottom of the coal bed
through a blast hood distributor.
Ash removal mechanism: helical ash plow at the bottom of
the gasifier which can be intermittently engaged in 'order
to push the ash outward radially and upward over the edge
of the ash pan and into a water-sealed hopper.
Special features:
- Water-cooled bed leveller arms at the top of the
gasifier provide a uniform coal bed.
Water-cooled agitator moves vertically and radially
through the bed to reduce caking and to provide
uniform pressure drop.
Gasifier barrel and ash pan rotate while the head
remains stationary.
Flow Diagram - See Figure 1.
Operating Parameter Ranges (Ref. 57) -
• Gas outlet temperature: 839 to 894°K (1050 to 1150°F)
• Maximum coal bed temperature: 1255 to 1367°K (1800 to
2000°F)
Gasifier pressure: atmospheric
Coal residence time in gasifier: 2 to 9 hours
Norma 1 Operating^ Parameters (Ref. 58) -
• Gas outlet temperature: 861°K (1090°F)
Maximum coal bed temperature: 1255 to 1365°K (1800 to
2000°F)
Gasifier pressure: atmospheric
Coal residence time in gasifier: 2 to 9 hours
A-58
-------
VENT GAS
COAL ? Q-
QUENCH WATER
>
vo
STEAM
AIR /
OXYGEN
STIRRER
CONDENSATE
ASH
LOW / MEDIUM
BTU GAS
Figure 1. Riley Morgan Gasifier
-------
Raw Material Requirements (Refs. 59, 60) -
Coal feedstock requirements:
Type: anthracite, bituminous, caking bituminous
- Size: 3.2 to 51 mm (0.125 to 2.0 in)
- Rate: 47 to 204 g/sec-m2 (35 to 150 lb/hr-ft2)
Pretreatment required: crushing and sizing
Steam requirements: Air-blown operation: ^0.565 kg/kg
coal
Oxygen requirements: Data not available
k
Air requirements: ^2.741 kg/kg coal
Quench water makeup requirements: Data not available
Utility Requirements - Data not available.
Process Efficiency (Ref. 61) - Basis: Air-blown operation;
quenched and cooled product gas; high volatile bituminous
coal; HHV (dry) = 3.22 x 107 joule/kg (14,000 Btu/lb).
• Cold gas efficiency: 64% to 68%
["] [Product gas energy output] ,nn
[Coal energy Input] x iuu
• Overall thermal efficiency: 71% to 78%
[= 1 [Total energy output (product gas + HC by-products + steam)] -__
[Total energy input (coal + electric power)] x
Expected Turndown Ratio - Data not available.
Gas Production Rate -
• Air-blown: 0.41 Nm3/sec-m2 (5107 scf/hr-ft2); 3.47
Nm3/kg coal (58.9 scf/lb coal)
• Oxygen blown: 0.38 Nm3/sec-m2 (4812 scf-/hr-ft2) ; 1.94
NmVkg coal (32.8 scf/lb coal).
A-60
-------
PROCESS ADVANTAGES
Coal type: Gasifier can be operated with bituminous or
anthracite coal. The coal bed agitator allows gasifica-
tion of caking coals.
Gasification media: Gasifier can be operated with air
or oxygen.
Reactor size: Small reactor size may be advantageous
for small-scale industrial applications.
Development status: Commercial-size gasifier has been
operated for several years.
PROCESS LIMITATIONS
Process efficiency: Maintaining the coal bed temperature
below the ash fusion temperature limits the maximum
process efficiency.
By-products produced: By-products require additional
processing for recovery.
Environmental considerations: Process condensate and by-
products require additional processing.
Operating pressure: Low operating pressure may be a
disadvantage for certain types of utilization technologies
or for gas transmission by pipeline.
Reactor size: Limited reactor size may necessitate use
of multiple units in parallel for large installations.
INPUT STREAMS (Ref. 62)
• Coal (Stream No. 1):
_ Type: Anthracite High volatile Medium volatile
A bituminous bituminous
- Size: mm 6.4 to 31.8 6.4 to 31.8 6.4 to 31.8
i (in) (0.25 to 1.25)(0.25 to 1.25) (0.25 to 1.25)
A-61
-------
- Composition:
Volatile matter
Moisture
Ash
Sulfur (dry basis)
- HHV (as received):
J/kg (Btu/lb)
- Swelling number:
- Caking index:
• Steam (Stream No. 2):
• Oxygen (Stream No. 3)
• Air (Stream No. 3):
3.6%
3.6%
8.0%
0.8%
2.6 x 107
(11,430)
30.8%
5.5%
7.1%
0.8%
3.1 x 107
(13,405)
21.4%
7.1%
5.0%
0.7%
3.2 x 107
(13,830)
8.5
-Data not available-
Data not ,0.56 kg/kg
available coal
NA
NA
Data not 2.74 kg/kg
available
Data not
available
NA
Data not
available
DISCHARGE STREAMS AND THEIR CONTROL
The Riley Morgan gasifier will produce the following discharge
streams. Stream numbers refer to Figure 1.
Gaseous Discharge Streams -
Low/medium-Btu gas (Stream No. 11)
Coal lock gas (Stream No. 6)
Ash pan gas (Stream No. 7)
Liquid Discharge Streams -
Process condensate and gas quenching liquor (Stream No. 10)
Solid Discharge Streams
Ash (Stream No. 4)
• Coal fines (Stream No. 9)
A-62
-------
The following text discusses the compositions of these
discharge streams, using as basis the INPUT STREAM data given
above, and the following gasifier conditions:
• Coal type: Anthracite High volatile Medium vola-
A bituminous tile bituminous
• Steam/02 (kg/kg): NA NA NA
• Steam/air (kg/kg): 0.21 0.17 0.19
• Gas off-take temperature Data not 861 Data not
°K (°F) Available (1090) Available
• Gas production rate: -Data not available-
Low/Medium-Btu gas (Stream No. 11) - The composition of the
low/medium-Btu gas from the Riley Morgan gasifier will be
dependent on the composition of the coal feed, gasifier
operating conditions, and the gas cooling operations applied
to the raw gas stream. The compositions given below list
the components in the raw gas (Stream No. 5) for bituminous
and anthracite coal feedstocks. Because this gas stream
contains significant amounts of H2S, organic sulfur compounds,
C02, heavy hydrocarbons and water, further treatment may be
required prior to utilization of the gas. Processes that can
be used to remove these contaminants are described in the
acid gas removal section.
Coal Type
Subbituminous A Lignite Subbituminous
Component Component Vol % Component Vol % Component Vol %
CO 22.7 21.0 23.5
H2 16.6 17.92 16.4
CH,, 0.25 2.0 1.7
ND 0.45 0.35
C02 9.1 8.85 7.3
N2+Ar 51.26 49.62 50.62
02 ND ND ND
H2S 0.09 0.16 0.12
COS + CS2 PR PR PR
Mercaptans ND ND ND
Thiophenes ND ND ND
SO 2 ND ND ND
H20 (kg/kg coal) PR (0.322) PR
Naphthas ND PR PR
Tar (kg/kg coal) ND (0.037) PR
Tar Oil (kg/kg coal) ND (0.040) PR
A-63
-------
Crude Phenols PR PR PR
NH3 PR PR PR
HCN ND PR PR
Particulates (coal fines,
ash) (kg/kg coal) PR (.0.007) PR
Trace elements PR PR PR
HHV (dry basis):
joule/Nm3 4.85 x 106 5.81 x 106 5.70 x 106
(Btu/scf) (130) (156) (153)
Gasification media: Steam/air Steam/air Steam/air
ND = presence of component not determined
PR = component is probably present, amount not determined
Component volume % is given on a relative basis to all other components that
have a value for volume % listed.
Coal Lock Gas (Stream No. 6) - This gaseous discharge stream
is created when the valve at the bottom of the coal feed
hopper opens to allow the coal feed to enter the gasifier.
The raw gas in the top of the gasifier fills the feed
hopper as the coal is discharged into the gasifier. When
the valve at the top of the coal feed hopper opens to admit
a new charge of coal, the raw gas in the hopper is displaced
up through the coal feed pipe and potentially into the atmos-
phere. The composition of this stream should be similar to
the raw gas (Stream No. 5), although some constituents may
condense or be adsorbed on the surface of the coal feed. In
order to prevent the release of these components to the
atmosphere, this stream may be collected by hoods and then
it may be incinerated or recycled to the raw gas stream
or air intake.
Ash Pan Gas (Stream No. 7) - This gaseous discharge stream
is the result of evaporation of suspended or dissolved com-
ponents in the ash pan water seal. Any of the components
in the raw gas (Stream No. 5) plus any components present
in the water input to the ash pan may be present in the
stream. In addition, some entrained ash particulates may
also be present in this stream. This stream may be small
enough in magnitude to permit direct venting to the atmosphere
or it may be collected by hoods and then incinerated in a
flare or boiler.
A-64
-------
Process Condensate and Gas Quenching Liquor (Stream No. 10) -
The gas quenching and cooling separations shown in Figure 1
are not currently in operation at the Riley Morgan pilot
plant. The raw gas (Stream No. 5) is passed through a
cyclone for particulate removal and is flared. Figure 1
shows the gas quenching and cooling operations proposed by
Riley Morgan. The liquid stream produced by these operations
will be composed of the raw gas scrubbing liquor plus the
components in the raw gas (Stream No. 5) which condense or
dissolve in the quench water. Some of the particulates and
tar droplets will be removed by the cyclone prior to gas
quenching and cooling. The components most likely to be
present in this stream are:
H20
Tar
Tar Oil
Naphthas
Crude Phenols
Particulates (coal fines, ash)
NH3
H2S
Organic Sulfur Compounds
Thiocyanates
HCN
Trace Elements
The amounts of these components will be dependent on the raw
gas composition and the gas quenching or cooling processes
used. Processes that can be used to remove these contami-
nants are described in the water pollution control section.
Ash (Stream No. 4) - This solid stream will be composed
mainly of the mineral matter present in the coal feed. The
exact composition of the ash is dependent on the composition
of the feed coal and the gasifier operating conditions. The
ash may also contain any of the components present in the ash
pan seal water. The ash from the gasifier is a solid waste
product which requires ultimate disposal. Methods that can
be used for ash disposal are described in the solid waste
treatment section.
Coal Fines (Stream No. 9) - If a cyclone is used for parti-
culate removal, this stream will be composed of small, hot
particles of coal, ash and tar which are removed from the
raw gas (Stream No. 5). Any of the heavy solid or liquid
constituents present in the raw gas could potentially be -
present in this stream. These coal fines may be sent to
disposal with the gasifier ash, or they may be recycled to
the gasifier coal feed, possibly in a briquette form. De-
pending on their carbon content, the coal fines may be
burned as a fuel.
A-65
-------
REFERENCES NOT CITED
L-2137 Rawdon, A. H., R. A. Lisauskas and S. A. Johnson, "NOX
Formation in Low and Intermediate BTU Coal Gas Turbulent-
Diffusion Flames", Presented at the NOX Control Tech-
nology Seminar, sponsored by Electric Power Research
Inst., San Francisco, CA, 5-6 February 1976.
L-6044 Walsh, Thomas F., "The Riley-Morgan Gasifier", Presented
at the Third Annual International Conference on Coal
Gasification and Liquefaction, School of Engineering,
University of Pittsburgh, Pittsburgh, PA, 3-5 August
1976.
A-66
-------
COAL GASIFICATION OPERATION GASIFICATION MODULE
FIXED-BED GASIFIERS
Pressurized Wellman-Galusha (MERC) Gasifier
GENERAL INFORMATION
Process Function - Atmospheric and high pressure coal gasi-
fication in a gravitating bed by injection of steam plus
air with countercurrent gas/solid flow.
Development Status - Pilot plant since 1958.
Licensor/Developer - U.S. Energy Research and Development
i Administration
Morgantown Energy Research Center
P.O. Box 880
Morgantown, West Virginia 26505
Commercial Applications - None; gas produced is used for
analysis and is flared.
Applicability to Coal Gasification - Gasifier has been
operated successfully with caking and non-caking coals. The
only operational unit is located at the Morgantown Energy
Research Center.
PROCESS INFORMATION
Equipment (Refs. 63, 64, 65) -
Gasifier construction: vertical, cylindrical steel pres-
sure vessel with refractory lining in the upper portion
of the gasifier.
Gasifier dimensions:
1.1 meters (3.5 ft.) in diameter
- 1.8 to 2.1 meters (6 to 7 ft.) coal bed depth
7.3 meters (24 ft.) approximate overall height
Bed type and gas flow: gravitating bed; continuous counter-
current gas flow; vertical gas outlet at the top of the
gasifier.
A-67
-------
Heat transfer and cooling mechanism: direct gas/solid
heat transfer; water jacket around the bottom 1.5 meters
(5 ft.) of the gasifier provides cooling of the gasifier.
Coal feeding mechanism: two intermittent pressurized
lock hoppers which feed coal to opposite sides of the
top of the gasifier, below the gas outlet.
Gasification media introduction: continuous injection of
steam plus air at the bottom of the coal bed through a
slotted ash extraction grate.
Ash removal mechanism: eccentrically rotating slotted
grate at the bottom of the coal bed; pressurized lock
hopper collects the ash and dumps it.intermittently.
Special features:
Rotating, water cooled agitator which spirals
vertically below the surface of the coal bed to prevent
channeling and to maintain a uniform bed.
Rotating, slotted ash grate which is eccentrically
mounted in order to break up the dry ash and force
it through the slots.
Flow Diagram - See Figure 1.
Operating Parameter Ranges (Refs. 66, 67) -
Gas outlet temperature: 755 to 922°K (900 to 1200°F)
Maximum coal bed temperature: 1589 to 1644°K (2400 to
2500°F)
Gasifier pressure: 0.1 to 2.1 MPa (15 to 300 psia)
Coal residence time in gasifier: Approximately 2 hours.
Normal Operating Parameters (Ref. 68) -
Gas outlet temperature: 922°K (1200°F)
Maximum coal bed temperature: 1589 to 1644°K (2400 to
2500°F)
A-68
-------
VENT GAS
I
O\
VO
COAL*
COAL
FINES
J
ir t.-
IENCH
r$
VENTURI
LOW/MEDIUM
BTU GAS
C.W.
C.W.
COOLER
• CONDENSATE
QUENCH
WATER
ASH HOPPER
FILLING GAS
VENT
GAS
ASH
Figure 1. Pressurized Wellman-Galusha (MERC) Gasifier
-------
Gasifier pressure: 0.69 to 1.3 MPa (100 to 195 psia)
Coal residence time in gasifier: Approximately 2 hours.
Raw Material Requirements (Refs. 69, 70) -
Coal feedstock requirements:
Type: all types
- Size: usually 50% less than 12.7 mm (0.5 in.); run-
of-mine coal has been successfully gasified.
- Rate: 99 to 228 g/sec-m2 (73 to 168 lb/hr-ft2)
- Pretreatment required: crushing and sizing; no
predrying is necessary.
Steam requirements:
- Air-blown operation - 0.32 to 0.7 kg/kg coal
Oxygen requirements: Data not available.
Air requirements: 2.3 to 4.1 kg/kg coal
Quench water make-up requirements: Data not available.
Utility Requirements - Data not available.
Process Efficiency (Ref. 71) - Basis: Air-blown operation;
quenched and cooled product gas; subbituminous coal feed HHV
(dry) = 2.05 x 10? joule/kg (8900 Btu/lb); reference temper-
ature = 300°K (80°F).
Cold gas efficiency: 79%
I"l. [Product gas energy output] x 100
[Coal energy input]
Overall thermal efficiency: Data not available.
["] [Total .Energy output (product gas + HC by-products + ateam)]
A J.UU
[Total energy input (coal + electric power)]
A-70
-------
Expected Turndown Ratio (Ref. 72) - 100/25
[=] [Full capacity output]
[Minimum sustainable output]
Gas Production Rate (Ref. 73) - Air-blown: 0.32 to 0.77
* (4030 to 9600 scf/hr-ft2); 2.7 to 4.7 Nm3/kg coal
PROCESS ADVANTAGES
Coal type: Gasifier can accept caking and non-caking coals
Operating pressure: High pressure operation favors the
formation of methane in the gasifier and reduces product
gas transmission costs. High pressure operation may
also be advantageous for combined cycle or synthesis
gas utilization.
Feed size: Gasifier has been operated with run-of-mine
coal.
PROCESS LIMITATIONS
Gasification media: Gasifier operation with oxygen has
not been demonstrated.
Process efficiency: Maintaining the coal bed temperature
below the ash fusion temperature limits the maximum
process efficiency.
By-products produced: By-products in the product gas
stream require additional processing if they must be
removed from the product gas prior to utilization.
Environmental considerations: By-products and process
condensates which may be removed from the product gas
stream require additional treatment to insure environmental
acceptability.
May require Nz for pressurizing gas .
A-71
-------
INPUT STREAMS (Refs. 74, 75, 76)
Coal (Stream No. 1):
- Type:
- Size: mm
(in)
- Rate: g/sec-m2
(lb/hr-ft2)
- Composition:
Volatile Matter
Moisture
Ash
Sulfur (dry basis)
Volatiles
- HHV: Joule/kg
(Btu/lb)
- Swelling number:
- Caking index:
New .Mexico Pittsburgh high
subbituminous A volatile A
bituminous
<38.1
(1.5)
211
(155)
31.3 %
8.8 %
24.2 %
1.1 %
31.3 %
2.05 x 107
(8900)
19 to 31.8
(0.75 to 1.25)
253
(186)
35.1 %
1.1 %
8.7 %
2.7 %
35.1 %
3.16 x 107
(13750)
Data not available Data not available
Steam (Stream No. 2): 0.68 kg/kg coal 0.4 kg/kg coal
Oxygen (Stream No. 3): NA NA
Air (Stream No. 3): 2.31 kg/kg coal 3.02 kg/kg coal
DISCHARGE STREAMS AND THEIR CONTROL
1. * -,T,he Jpresfurized Wellman-Galusha (MERC) gasifier will produce
the following discharge streams. Stream numbers refer to Figure 1.
A-72
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Gaseous Discharge Streams
Low/medium-Btu gas (Stream No. 13)
Coal lock gas (Stream No. 6)
• Ash lock gas (Stream No. 9)
Liquid Discharge Streams
• Process condensate and gas quenching liquor (Stream No. 12)
Solid Discharge Streams
• Ash (Stream No. 4)
Coal fines (Stream No. 10)
The following text discusses the compositions of these discharge
streams, using as a basis the INPUT STREAM data given above, and
the following gasifier conditions:
High Volatile A
• Coal type: ; Subbituminous A Bituminous
• Gasifier pressure: 1.5 (220) 1.14 (165)
MPa (psia)
• Steam/02:(kg/kg) NA NA
• Steam/air: (kg/kg) 0.29 0.12
Gas outlet temperature Data not available 828 (1030)
°K (°F)
• Gas production rate:
Nm3/kg coal
(scf/lb coal) 2.77 (46.9) 3.80 (64.4)
Low/Medium-Btu Gas (Stream No. 13) - The composition of the
low/medium-Btu gas from the Pressurized Wellman-Galusha (MERC)
gasifier will be dependent on the composition of the coal feed,
gasifier operating conditions and the gas cooling operations
applied to the raw gas stream. The compositions given below
list the components in the raw-gas (Stream No. 5) for sub-
bituminous and bituminous coal feedstocks. Because this gas
stream may contain significant amounts of H2S, organic sulfur
A-73
-------
compounds, C02, heavy hydrocarbons, and water, further treat-
ment may be required prior to utilization of the gas. Processes
that can be used to remove these contaminants are described in
the acid gas removal section.
Coal Type
Component
CO
C2H6J
CO 2
N2 + Ar
02
H2S
COS + CS2
Mercaptans
Thiophenes
S02
H20 (kg/kg coal)
Subbituminous A
Component Vol%
16.0
19.0
3.5
0.3
12.6
48.4
ND
0.2
PR
ND
ND
ND
(0.64)
Naphthas PR
Tar (kg/kg coal) (.034)
Tar Oil PR
Crude Phenols PR
NH3 PR
HCN ND
Particulates (coal (.017)
fines, ash) (kg/kg coal)
Trace elements PR
High Volatile A
bituminous
Component Vol%
21.6
18.7
2.9
0.2
7.3
48.9
ND
0.4
PR
ND
ND
ND
(0.32)
PR
(.026)
PR
PR
PR
ND
(3.5 x 10~3)
PR
HHV (dry basis) :
Joule/Nm3
(Btu/scf)
Gasification media:
5.6 x 10{
(150)
Steam/air
6.1 x 106
(164)
Steam/air
ND « presence of component not determined.
PR «• component is probably present, amount not determined.
Component volume % is given on a relative basis to all other components
that have a value for volume % listed.
A-74
-------
Coal Lock Gas (Stream No. 6) - The composition of this
gas stream will be determined by the mode of pressurizing
the coal lock and the composition of the pressurizing
gas used. Prior to dumping the coal from the lock into
the gasifier, the lock is pressurized by opening a valve
which connects the two coal locks. The second lock,
which contains raw gas and nitrogen at the gasifier
operating pressure, is depressurized as it fills the first
lock with gas. The valve is closed and the first lock is
brought up to the gasifier operating pressure by the
addition of nitrogen. When the coal is dumped from the lock
into the gasifier, raw gas will back-flow into the lock.
The process is repeated as the empty lock is depressurized
to pressurize the full lock. After the empty lock is
opened to admit a fresh charge of coal, the gases remaining
in the lock will be displaced by the incoming coal. The
displaced coal lock gas will contain components in the raw
gas (Stream No. 5), plus nitrogen, plus entrained coal
particles. In order to prevent the release of these com-
ponents to the atmosphere, this stream may be recycled
to the raw gas stream or air intake or it may be incinerated
in a flare or boiler. If gaseous contaminants in this
stream are relatively low in concentration the stream may
be passed through wet cyclones to remove particulates and
then vented to the atmosphere.
Ash Lock Gas (Stream No. 9) - The ash lock gas composition
will vary, depending on the operating procedure used to
pressurize the ash lock. If steam is used to pressurize the
lock, the ash lock gas will be composed mostly of steam with
lesser amounts of the components in the raw gas (Stream
No. 5). If the lock is not pressurized prior to admitting
ash from the gasifier, the ash lock gas will be composed
mostly of raw gas (Stream No. 5) which enters the lock as
the lock opens. Depending on the method of ash removal,
additional components may be present in the ash lock gas.
If the ash is quenched with water, ash dust will be entrained
in the steam formed from cooling the ash. Some non-condensable
gases may be generated by reaction between unburned char
and steam or by thermal cracking of organic constituents in
the quench water. This stream may be passed through steam
condensers to knock out condensables and some particulates.
The gas may be treated further in cyclones, or it may be
vented directly or incinerated. The gases which are emitted
as the ash is dumped from the lock may be collected by hoods
and incinerated or vented to the atmosphere after passing
the gas through a wet cyclone to remove entrained particulates.
A-75
-------
Process Condensate and Gas Quenching Liquor (Stream No. 12) -
The gas quenching and cooling operations shown in Figure 1
are not currently in operation at the MERC pilot plant.
The raw gas (Stream No. 5) is passed through a cyclone for
particulate removal and is flared. The gas quenching and
cooling operations shown in Figure 1 will be installed at
the MERC pilot plant in the future. The liquid stream
produced by these operations will be composed of the raw
gas scrubbing liquor plus raw gas condensate from the indirect
cooler and electrostatic precipitator. This stream will
contain any of the components in the raw gas (Stream No. 5)
which condense or dissolve in the quench water. Some of the
particulates and tar droplets will be removed by the cyclone
prior to gas quenching and cooling. The components most
likely to be present in this stream are:
H20
Tar
Tar oil
Naphthas
Crude phenols
Particulates (coal fines, ash)
NH3
H2S
Organic sulfur compounds
Thiocyanates
HCN
Trace elements
The amounts of these components will be dependent on the
raw gas composition and the gas cooling or quenching processes
used. Processes that can be used to remove these contami-
nants are described in the water pollution control section.
Ash (Stream No. 4) - This solid stream will be composed
mainly of the mineral matter present in the feed coal with
approximately 5% to 15% unreacted carbon. The exact com-
position will depend on the feed coal and the gasifier
operating conditions. If the ash is quenched, other consti-
tuents from the quench water may be present in this stream.
The ash from the gasifier is a solid waste product which
requires ultimate disposal. Methods that can be used for
ash disposal are described in the solid waste treatment section,
Coal Fines (Stream No. 10) - This solid stream is composed
of small, hot particles of coal, ash, and tar which are
removed from the raw gas (Stream No. 5). Any of the heavy
solid or liquid constituents present in the raw gas could
potentially be present in this stream. These coal fines
may be sent to disposal with the gasifier ash, or they may
be recycled to the gasifier coal feed, possibly in a briquette
form. Depending on their carbon content, the coal fines may
be burned as a fuel.
A-76
-------
REFERENCES NOT CITED
L-727
L-4526
L-4896F
L-5063
L-5283
L-5688
Katz, Donald L., et al., Evaluation of Coal Conversion
Processes to Provide Clean Fuels.Final Report.Report
No. EPRI 206-0-0, PB-234 202 & PB-234 203. Ann Arbor,
MI, Univ. of Michigan, Col. of Engineering, 1974.
Gillmore, Donald W., and Neil H. Choates, "Behavior
of Caking Coals in Fixed-Bed Gasifiers", in Proceedings
of the Coal Agglomeration and Conversion Symposium,
Morgantown, yV, 5-p May 1975. Morgantown, WV, west
Virginia Geological anid Economic Survey, April 1976.
pp. 195+.
Lewis, P. S., et al.,
Stirred-Bed Producer.
Bituminous Coal Gasified in a
Report No. MERC/RI-75/1.
Morgantown, WV, Morgantown Energy Research Center,
ERDA, June 1975.
Liberatore, A. J., and D. W. Gillmore, Behavior of
Caking Coals in Fixed-Bed Gasifiers. Report No.
CONF-750868-1.Morgantown, WV, Morgantown Energy
Research Center, 1975.
Ayer, Franklin A., comp., Symposium Proceedings:
Environmental Aspects of Fuel Conversion Technology, II,
Hollywood, FL, December IgTTReport No. EPA-600/2-76-
149, EPA Contract No. 68-02-1325, Task 57. Research
Triangle Park, NC, Industrial Environmental Research
Lab., Office of Energy, Minerals and Industry, June
1976.
Gillmore, G. W., and N. H. Coates, Behavior of Caking
Coals in Fixed-Bed Gasifiers. Report No. CONF-750870-1.
Morgantown, WV, Morgantown Energy Research Center, 1975.
A-77
-------
COAL GASIFICATION OPERATION GASIFICATION MODULE
FIXED-BED GASIFIERS
GFERC Slagging Gasifier
GENERAL INFORMATION
Process Function - High pressure coal gasification in a
gravitating bed by injection of steam plus oxygen with
countercurrent gas/solid flow.
Development Status - Pilot plant operated 1958 to 1965;
reactivated in 1976.
Licensor/Developer - U.S. Energy Research and Development
Administration
Grand Forks Energy Research Center
Grand Forks, North Dakota
Commercial Applications - None; gas produced from one unit
is used for analysis and is flared.
Applicability to Coal Gasification - Gasifier has been
operated successfully with lignite, lignite char and bitu-
minous char. The only operational unit is located at the
Grand Forks Energy Research Center.
PROCESS INFORMATION
Equipment (Refs. 77, 78) -
Gasifier construction: vertical, cylindrical steel
pressure vessel with refractory lining.
• Gasifier dimensions:
- 0.4 meters (16.6 in.) in diameter
- 1.8 to 4.6 meters (6 to 15 ft.) coal bed depth
12.0 meters (39.3 ft.) approximate overall height
• Bed type and gas flow: gravitating bed, continuous
countercurrent gas flow, lateral gas outlet near the
top of the gasifier.
A-78
-------
Heat transfer and cooling mechanism: direct gas/solid
heat transfer, water jacket provides gasifier cooling.
Coal feeding mechanism: intermittent pressurized lock
hopper which is an integral part of the top of the
gasifier.
Gasification media introduction: continuous injection
of steam plus oxygen through tuyeres at the sides of
the bottom of the gasifier.
• Ash removal mechanism: tap hole in the conical bottom
of the gasifier which drains the slag into a water quench
bath and slag lock. Intermittent discharge of the con-
tents of the slag lock provides slag removal.
Special features:
- Direct quench gas scrubbing cooler knocks out parti-
culates, tar, oils, phenols, and ammonia at the gas
outlet.
- Side stream sample line at the top of the gasifier
allows raw product gas analysis.
Flow Diagram - See Figure 1.
Operating Parameter Ranges (Ref. 79) -
. Gas outlet temperature: 358 to 644°K (185 to 700°F)
• Maximum coal bed temperature: approximately 1644°K
(2500°F), depending on the ash fusion temperature of
the feed coal
• Gasifier pressure: 0.66 to 2.9 MPa (95 to 415 psia)
Coal residence time in gasifier: Approximately 15 to
45 minutes
Normal Operating Parameters (Ref. 80) -
• Gas outlet temperature: 477eK (400°F)
Maximum coal bed temperature: Approximately 1644°K
(2500°F) depending on the ash fusion temperature of
feed coal.
• Gasifier pressure; 0.66 to 2.9 MPa (95 to 415 psia)
A-79
-------
STEAM
I
00
O
LOCK HOPPER
VENT GAS
GAS / WATER
SEPARATOR
VENT GAS
MAKE-UP
WATER
LOW / MEDIUM
BTU GAS
SLOWDOWN
Figure 1. GFERC SLAGGING GASIFIER
-------
• Coal residence time in gasifier: Approximately 15 to
45 minutes.
Raw Material Requirements (Ref. 81, 82, 83) -
Coal feedstock requirements:
Type: Bituminous char, lignite char, or lignite
- Size: 6.4 to 19 mm (0.25 to 0.75 in.)
- Rate: 262 to 1288 g/sec-m2 (193 to 947 lb/hr-ft2)
- Pretreatment required: Crushing and sizing; drying
to less than 35% moisture.
Steam requirements: 0.30 to 0.46 kg/kg coal
Oxygen requirements: 0.48 to 0.55 kg/kg coal
Air requirements: NA
Quench water make-up requirements: Data not available.
Utility Requirements - Data not available.
Process Efficiency (Ref. 84) - Basis: oxygen-blown operation;
quenched and cooled product gas; lignite coal feed HHV (dry)
= 1.82 x 107 joule/kg (7920 Btu/lb); reference temperature
= 300°K (80°F).
• Cold gas efficiency: 85%
[=] [Product gas energy output] Y inn
[Coal energy input]A iuu
Overall thermal efficiency: Data not available
["] [Total energy output (product gas + HC by-products + steam)] y
[Total energy input (coal + electric power)]
Expected Turndown Ratio - Data not available
Gas Production Rate - oxygen blown: 0.53 to 2.1 Nm3/sec-m2
(6566 to 26060 scf/hr-ft2); 1.4 to 1.9 Nm3/kg DAF coal
(24 to 33 sc.f/lb DAF coal). "
A-81
-------
PROCESS ADVANTAGES
Process efficiency: slagging operation increases pro-
cess efficiency and throughput rate over fixed-bed non-
slagging operations.
Steam consumption/conversion: operation at slagging
temperatures reduces steam consumption and increases
steam conversion.
Environmental considerations: lower steam consumption
reduces the volume of liquid wastes requiring treatment.
Operating pressure: high pressure operation favors the
formation of methane in the gasifier and reduces gas
transmission costs. High pressure is advantageous for
utilization of the gas as a synthesis gas or in combined
cycle applications.
Fuel size: coal fines may be injected into the gasifier
through the steam/Oa tuyeres.
Reactor size: small reactor size may be advantageous
for small scale industrial applications.
PROCESS LIMITATIONS
Coal types: caking coals may require pretreatment;
coals with low ash content or high percentages of
refractory type ash may require addition of ash fluxing
agents.
Gasification media: operation with steam plus air will
not provide hot enough temperatures for slagging operation.
By-products produced: by-products require additional
processing for recovery.
Environmental considerations: process condensate and
by-products require additional processing for environ-
mental acceptability.
Reactor size: limited reactor size may necessitate use
of multiple units in parallel for large installations.
Development status: gasifier has only been operated on
a pilot plant scale.
A-82
-------
INPUT STREAMS (Refs. 85, 86) -
Coal (Stream No. 1)
- Type:
- Size: mm (in)
- Rate: g/sec-m2
Steam Dried
Baukol-Noonan
Lignite A
6.4 to 19
(0.25 to 0.75)
Baukol-Noonan Velva
Lignite A Lignite A
6.4 to 19 6.4 to 19
(0.25 to 0.75) (0.25 to 0.75)
510 (375)
1695 (1247)
1322 (972)
(lb/hr-ftz)
- Flux added:
Lignite slag
0.2 kg/kg coal
Lignite slag None
0.06 kg/kg coal
Composition:
Volatile matter
Moisture
Ash
Sulfur (Dry basis)
- HHV: J/kg (Btu/lb)
Swelling number:
- Caking index:
• Steam (Stream No. 2)
Oxygen (Stream No. 3)
Air (Stream No. 3)
DISCHARGE STREAMS AND THEIR
37.0%
11.9%
9.0%
1.2%
2.7 x 10 7
(11,540)
0
0
0.33 kg/kg
DAF coal
0.52 kg/kg
DAF coal
NA
CONTROL
29.1%
29.1%
6.5%
0.4%
1.82 x 10 7
(7,930)
0
0
0.30 kg/kg
DAF coal
0.48 kg/kg
DAF coal
NA
28.8%
35.2%
3.5%
0.21%
1.66 x 10 7
(7,210)
0
0
0.30 kg/kg
DAF coal
0.49 kg/kg
DAF coal
NA
The GFERC Slagging Gasifier will produce the following
discharge streams. Stream numbers refer to Figure 1.
A-83
-------
Gaseous Discharge Streams
Low/medium-Btu gas (Stream No. 15)
Coal lock gas (Stream No. 6)
Slag quench vent gas (Stream No. 12)
Slag lock gas (Stream No. 8)
Liquid Discharge Streams
Process condensate and gas quenching liquor (Stream No. 14)
Slag quench blowdown (Stream No. 11)
Solid Discharge Streams
Slag slurry (Stream No. 4)
The following text discussed the compositions of these discharge
streams, using as a basis the INPUT STREAM data given above, and
the following gasifier conditions:
Coal type: Lignite A Lignite A Lignite A
Gasifier pressure: 0.66 2.86 2.86
MPa (psia) (95) (415) (415)
Steam/02: (kg/kg) 0.63 0.63 0.63
Steam/air: (kg/kg) NA NA NA
Gas outlet temperature: 358 450 450
K <°F) (185) (350) (350)
o
Gas production rate: 1.75 1.76 1.72
Nm3 /kg coal
(scf/lb coal)
Low/Medium-Btu Gas (Stream No. 15) - The composition of the
low/medium-Btu gas from the GFERC Slagging Gasifier will be
dependent on the composition of the coal feed, gasifier
operating conditions, and the gas cooling operations applied
to the raw gas stream. The compositions given below list
the components in the raw gas (Stream No. 5) for lignite
coal feed at different pressures, and with different amounts
of flux added to the coal feed. Because this gas stream
contains significant amounts of H2S, organic sulfur
compounds, C02, heavy hydrocarbons and water, further
A-84
-------
treatment may be required prior to utilization of the gas.
Processes that can be used to remove these contaminants are
described in the acid gas removal section.
Component
CO
H2
CH.,
*C2H4
Ar
CO 2
N2
02
H2S (kg/kg .coal)
COS + CS2 (kg/kg coal)
Mercaptans (kg/kg coal)
Thiophenes
S02
H20
Naphthas
Tar (kg/kg coal)
Tar Oil (kg/kg coal)
Crude Phenols
NH3
HCN
Particulates (coal
fines, ash)
Trace elements
Coal type/ flux
Lignite A/slag Lignite A/slag Lignite A/none
Component Vol% Component Vol% Component Vol%
)
1)
(1.4
(5.9
58.4
30.1
4.8
0.5
0.3
5.7
ND
0.2
PR
ND
ND
ND
ND
PR
PR
x 10"2)
x 10"2)
PR
ND
ND
PR
PR
57.7
28.4
6.4
0.5
0.3
6.5
ND
0.2
(1.9 x 10 3)
(1.3 x 10~")
(8.5 x 10~5)
ND
ND
PR
PR
(1.7 x 10~2)
(5.6 x 10~2)
PR
ND
Nl>
PR
PR
56.0
28.8
6.9
0.5
0.2
7.4
ND
0.2
(1.5 x 10~3)
(1.3 x 10"")
(8.5 x 10"5)
ND
ND
PR
PR
(1.2 x 10~2)
(4.0 x 10~2)
PR
ND
ND
PR
PR
HHV (Dry basis):
J/Nm3 (Btu/scf)
1.28 x 107
(345)
Gasification media: Steam/02
1.32 x 107
(353)
Steam/Oz
1.31 x 107
(352)
Steam/02
* Originally reported as "Illuminants", which may include other light
olefins.
ND - presence of component not determined.
PR » component is probably present, amount not determined.
Component volume % is given on a relative basis to all other components
that have a value for volume % listed.
A-85
-------
Coal Lock Gas (Stream No. 6) - The composition of this gas
stream will be determined by the mode of operation of the
coal lock. Prior to dumping the coal from the lock into
the gasifier, the lock is pressurized to the gasifier
operating pressure with a stream of cooled raw gas. If the
pressurizing gas is added continuously as the coal dumps
into the gasifier, the gas remaining in the lock will have
approximately the same composition as the pressurizing gas.
If no gas is added as the coal is dumped, raw gas from
the gasifier will back-flow into the gasifier, and the gas
remaining in the lock will be composed of pressurizing gas
and raw gas from the gasifier. As raw gases from the
gasifier pass countercurrently through the incoming coal
and into the lock, tars, oils, water and other constituents
of the raw gas may condense or be absorbed on the coal feed.
In addition to the components in the raw gas (Stream No. 5)
and the lock filling gases (Stream No. 7), the coal lock
gas may also contain entrained coal fines. As the coal
lock is depressurized, the gas in the lock is recycled to
the raw gas stream. The gas which remains in the lock
after depressurization will be displaced by the incoming
coal charge. In order to prevent the release of this
gas stream to the atmosphere, it may be collected by hoods
and incinerated in a flare or boiler.
Slag Quench Vent Gas (Stream No. 12) - The composition of
this gas stream will be determined by the mode of operation
of the slag tap. If the slag is tapped intermittently by
inducing slag flow with a slag burner as shown in Figure
1, the slag quench vent stream will be created when slag
is drained from the gasifier by swinging the slag burner
aside and by opening the slag quench vent to create a
positive pressure differential across the slag tap hole.
The slag quench vent will be composed of combustion pro-
ducts, raw gas from the gasifier, steam, entrained slag
particles, and any volatile components in the slag quench
make-up water (Stream No. 10). This gas stream may be
first passed through a cyclone to remove particulates,
or it may be incinerated directly in a flare or boiler.
If the slag is tapped continuously, slag quench vent
stream would not be present.
Slag Lock Gas (Stream No. 8) - This gas stream is created
when the slag lock is depressurized in order to discharge
the slag slurry. This stream may contain components in
the raw gas from the gasifier which have dissolved in the
slag quench water, steam, entrained slag particles, and
any volatile components in the slag quench make-up water
(Stream No. 10). Depending on the composition of the slag
lock gas, it may be first passed through a cyclone to
A-86
-------
remove particulates and then vented to the atmosphere or
it may be incinerated in a flare or boiler.
Process Condensate and Gas Quenching Liquor (Stream No. 14)
This liquidstream is composed ofthe raw gas scrubbing
liquor plus raw gas condensate from the waste heat boiler.
This stream will be composed of water plus the constituents
of the raw gas (Stream No. 5) which condense or dissolve
in the quench water. The components most likely to be
present in this stream are:
H20
Tar
Tar oil
Naphthas
Crude phenols
Particulates (coal
fines and ash)
NH3
H2S
Organic sulfur compounds
Thiocyanates
HCN
Trace elements
The amounts of these components will be dependent on the
raw gas composition and the eas quenching and cooling prb-
cesses used. Processes that can be used to remove these,
contaminants are described in the water pollution control
section.
Slag Quench Slowdown (Stream No. 11) - This liquid stream
will be composed of the slag quench water which is removed
from the slag lock prior to removal of the slag slurry.
This stream will also contain condensate from the slag
quench vent gas/liquid separator. The slag quench blowdown
may contain any of the components present in the raw gas
from the gasifier (Stream No. 5) or in the quench water
make-up (Stream No. 10). This stream may also contain
suspended slag particles. The concentrations of contami-
nants in this stream will determine the control technology
used to control this stream. This stream may be sent to
disposal in evaporation ponds which will result in emission
to the atmosphere of all volatile components in the stream,
Slag Slurry (Stream No. 4) - The slag slurry contains slag
particles and slag quench water. The slag quench water in
the slurry will have the same composition as the slag quench
blowdown (Stream No. 11). The slag is composed of the
mineral matter in the feed coal with approximately 17o
unreacted carbon plus any ash fluxing agents added to the
feed coal. The exact composition of the slag is dependent
on the composition of the feed coal and fluxing agent (if
used) and the gasifier operating conditions. The suspended
A-87
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solids removal processes described in Appendix D can be
used to dewater the slag slurry. The recovered water could
be recycled to the process condensate and gas quenching
liquor (Stream No. 14). The dewatered slag or slag
slurry is a solid waste product which requires ultimate
disposal. Processes that can be used for slag slurry
disposal are described in the solid waste treatment section.
REFERENCES NOT CITED
L-1744 Gronhovd, G. H. , et al. , Slagging Fixed-Bed Gasification
of North Dakota Lignite at Pressures to 400 PSIG.U.S.
Bur. Mines, Rep. Invest. No. RI-7408, NTIS Report No.
PB-193 207. Washington, DC, U.S. Bur. Mines, July 1970.
L-5407 Seamans, Robert C., et al. , Fossil Energy Program Report
1975-1976. Report No. ERDA 76-10.Washington, DC,
Energy Research & Development Admin., 1976.
A-88
-------
COAL GASIFICATION OPERATION GASIFICATION MODULE
FIXED-BED GASIFIERS
BGC/Lurgi Slagging Gasifier
GENERAL INFORMATION
Process Function - High-pressure coal gasification in a
gravitating bed by injection of steam plus oxygen with
countercurrent gas/solid flow.
Development Status - Pilot plant operation: 1955 to 1964.
Demonstration plant operation started in 1976.
Licensor/Developer - British Gas Corporation
59 Bryanston St.
Marble Arch
London W-l
Lurgi Mineraloltechnik GmbH
P.O. Box 119181
Bockheimer Landstrasse 42
D-6 Frankfurt (Main), Germany
Commercial Applications - None; gas produced is used for
analysis and is flared.
Applicability to Coal Gasification - Gasifier has been
operated successfully with noncaking and weakly caking
bituminous coals. Successful operation has been maintained
using coals with high and low ash content, and coals with
high and low ash fusion .temperatures. Development work is
currently being conducted at the Westfield Development
Centre, Westfield, Scotland. Previous development work was
conducted at the Midlands Research Station, Solihull, England.
NOTE: No operating data are currently available for the new
demonstration-scale unit at Westfield. Therefore all infor-
mation presented below pertains tp the pilot-scale gasifier
at Solihull, unless otherwise noted.
PROCESS INFORMATION
Equipment (Refs. 87, 88) r
• Gasifier construction: Vertical, cylindrical steel pres-
sure vessel with refractory lining in the lower half of
the gasifier.
A-89
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• Gasifier dimensions: 0.9 m (3 ft) in diameter
3.1 m (10 ft) coal bed depth
2.8 m (9.25 ft) in diameter (Westfield gasifier)
Bed type and gas flow: Gravitating bed; continuous
countercurrent gas flow; lateral gas outlet near the top
of the gasifier.
Heat transfer and cooling mechanism: Direct gas/solid
heat transfer; water jacket provides gasifier cooling.
Coal feeding mechanism: Intermittent, pressurized lock
hopper at the top of the gasifier which dumps the coal
onto a rotating, water-cooled coal distributor. Coal
fines can be injected into the combustion zone through
the steam/oxygen tuyeres.
Gasification media introduction: Continuous injection of
steam plus oxygen through tuyeres in the sides of the bottoil
of the gasifier.
Ash removal mechanism: Tap hole in the conical bottom of
the gasifier which drains the slag into a water quench
bath and slag lock. Intermittent discharge of the slag
lock provides slag removal.
Special features:
Direct quench gas scrubber and cooler knocks out
particulates, tars, oils, phenols, and ammonia at
the gas outlet.
- Rotating coal distributor provides uniform coal bed
composition.
- Rotating, water-cooled coal bed agitator aids the
gasification of strongly caking coals.
- Plunger type tar scraper prevents plugging of the gas
outlet from tar condensation.
- Sampling ports at the side of the gasifier permit
measurements of temperatures and gas compositions in
the gasifier.
Flow Diagram - See Figure 1.
A-90
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LOCK HOPPER
VENT GAS
STEAM
GAS / WATER
SEPARATOR
VENT GAS
MAKE-UP
WATER
LOW / MEDIUM
BTU GAS
SLOWDOWN
Figure 1. BGC/Lurgi Slagging Gasifier
-------
Operating Parameter Ranges (Refs. 89, 90) -
• Gas outlet temperature: 473 to 1073°K (390 to 1470°F)
Maximum coal bed temperature: Greater than 1533°K
(2300°F), depending on the ash fusion temperature of
the feed coal.
• Gasifier pressure: 2.07 to 2.76 MPa (300 to 400 pisa)
Coal residence time in gasifier: Approximately 10 to 15
minutes.
Normal Operating Parameters (Ref. 91) -
• Gas outlet temperature: 623 to 723°K (660 to 840°F)
Maximum coal bed temperature: Greater than 1533°K
(2300°F), depending on the ash fusion temperature of
the feed coal.
• Gasifier pressure.- 2.07 MPa (300 psia)
Coal residence time in gasifier: Approximately 10 to 15
minutes.
Raw Material Requirements (Ref. 92) -
Coal feedstock requirements:
- Type: All types: strongly caking coals require agitator,
- Size: 13 to 51 mm (0.5 to 2.0 in)
- Rate: 702 to 1958 g/sec m2 (516 to 1440 Ib/hr ft2)
- Pretreatment required: Crushing and sizing; drying
to less than 2070 moisture.
Steam requirements: 0.29 to 0.31 kg/kg coal.
• Oxygen requirements: 0.48 to 0.53 kg/kg coal.
• Air requirements: Not applicable.
Quench water makeup requirements: Data not available.
Utility Requirements - Data not available.
A-92
-------
Process Efficiency (Ref. 93) - Basis: Oxygen-blown operation;
quenched and cooled product gas; bituminous coal feed;
reference temperature * 300°K (80*F).
• Cold gas efficiency: 83%
[=] [Product gas energy output] 10Q
[Coal energy input]
Overall thermal efficiency: Data not available.
[=] [ Total energy output (product gas + HC by-products + steam)]
[Total energy input (coal + electric power)]
Expected Turndown Ratio - Data not available
[=1 [Full capacity output]
[Minimum sustainable output]
Gas Production Rate - Oxygen blown: 3.5 to 5.1 Nm3/sec-m2
(43,600 to 45,600 scf/hr-ft ); 2.03 to 2.14 Ntn3/kg DAF coal
(34.4 to 36.2 scf/lb DAF coal).
PROCESS ADVANTAGES
Coal type: Gasifier can accept caking and noncaking coals.
Process efficiency: Slagging operation increases process
efficiency and throughput rate over fixed-bed nonslagging
operation.
Steam consumption/conversion: Operation at slagging
temperatures reduces steam consumption and increases steam
conversion.
Environmental considerations: Lower steam consumption
reduces the volume of liquid wastes requiring treatment.
Operating pressure: High-pressure operation favors the
formation of methane in the gasifier and reduces gas
transmission cost. High pressure is advantageous for
utilization of the gas as a synthesis gas or in a combined
cycle. *
A- 93
-------
Fuel size: Coal fines may be injected into the gasifier
through the steam/Oa tuyeres.
Reactor size: Small reactor size may be advantageous
for small-scale industrial applications.
PROCESS LIMITATIONS
Coal types: Coals with low ash content or with a high
percentage of refractory type ash may require addition of
ash fluxing agents.
Gasification media: Operation with steam plus air will
not provide hot enough temperatures for slagging operation,
By-products produced: By-products require additional
processing for recovery.
Environmental considerations: Process condensate and
by-products require additional processing for environ-
mental acceptability.
Reactor size: Limited reactor size may necessitate use
of multiple units in parallel for large installations.
Development status: Gasifier has only been operated on
a pilot-plant scale.
INPUT STBEAMS (Ref. 94) -
Coal (Stream No. 1)
- Type
- Size:
mm
(in)
Donisthorpe Donisthorpe Newstead
weakly caking weakly caking bituminous
bituminous bituminous
25.4 to 38.1
(1.0 to 1.5)
25.4 to 38.1
(1.0 to 1.5)
25.4 to 50.8
(1.0 to 2.0)
- Rate: g/sec-m
(lb/hr-ft2)
- Flux added: kg/kg
1333
(980)
bituminous slag
coal 0.06
1952
(1436)
none
1262
(928)
dolomite
0.02
A-94
-------
- Composition:
Volatile matter
Moisture
Ash
Sulfur (dry basis)
- HHV:
- Swelling number:
- Caking index:
• Steam (Stream No. 2):
kg/kg DAF coal
• Oxygen (Stream No. 3)
kg/kg DAF coal
• Air (Stream No. 3):
- Data not available -
12.7% 13.8% 12.6%
7.4% 5.6% 7.6%
1.45% 1.3% 0.7%
- Data not available -
- Data not available -
- Data not available -
0.29
0.48
NA
0.29
0.48
NA
0.31
0.53
NA
DISCHARGE STREAMS AND THEIR CONTROL
The BGC/Lurgi slagging gasifier will produce the following
discharge streams. Stream numbers refer to Figure 1.
Gaseous Discharge Streams -
• Low/mediutn-Btu gas (Stream No. 15)
Coal lock gas (Stream No. 6)
Slag quench vent gas (Stream No.12)
• Slag lock gas (Stream No. 8)
Liquid Discharge Streams -
Process condensate and gas quenching liquor (Stream No.
14)
• Slag quench blowdown (Stream No. 11)
A-95
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Solid Discharge Stream -
Slag slurry (Stream No. 4)
The following text discusses the compositions of these discharge
streams, using as a basis the INPUT STREAM data given above and
the following gasifier conditions:
• Coal type: Donisthorpe Bonlsthorpe Newstead
bituminous bituminous bituminous
• Gasifier pressure: 2.07 2,07 2.07
MPa (psia) (300) (300) (300)
• Steam/02: kg/kg 0.61 0.61 0.59
• Steam/air: kg/kg NA NA NA
• Gas outlet temperature: - Data not available -
°K (°F)
• Gas production rate: 2.03 1.96 2,14
Nm3/kg coal (scf/lb (34.4) (33.2) (36.2)
coal)
Low/Medium-Btu Gas (Stream No. 15) - The composition of the
low/medium-Btu gas from the BGC/Lurgi slagging gasifier will
be dependent on the composition of the coal feed, gasifier
operating conditions, and the gas cooling operations applied
to the raw gas stream. The compositions given below list
the components in the raw gas (Stream No. 5) for bituminous
coal feed with different amounts of flux added to the coal
feed. Because this gas stream contains significant amounts
of H2S, organic sulfur compounds, COa, heavy hydrocarbons
and water, further treatment may be required prior to utili-
zation of the gas. Processes that can be used to remove
these contaminants are described in the acid gas removal
section.
Coal Lock Gas (Stream No. 6) - The composition of this gas
stream will be determined by the mode of pressurizing the
coal lock. Various operating procedures and sources of
pressurizing gas could be used. Prior to dumping the coal
from the lock into the gasifier, the lock may be pressurized
to the gasifier operating pressure with a stream of cooled
raw gas or with a vent stream from an acid gas removal or
oxygen production process. If the pressurizing gas is added
continuously as the coal dumps into the gasifier, the gas
remaining in the lock will have approximately the same com-
position as the pressurizing gas. If no gas is added as the
coal is dumped, raw gas from the gasifier will back-flow
A-96
-------
Coal Type/Flux
Low/Medium-Btu Gas
Component
CO
H2
*C2H6
CO 2
N2+Ar
02
H2S (kg/kg DAF coal)
COS + CS2 (kg/kg DAF coal)
Mercaptans
Thiophenes
S02
H20
Naphthas
Tar (kg/kg DAF coal)
Tar Oil
Crude Phenols
NH3
HCN
Particulates (coal fines,
ash) (kg/kg DAF coal)
Trace elements
Doniathorpe
Bituminous/Slag
Component Vol %
(1.
(9.
(7.
(1.
61.3
28.05
7.65
0.45
2.55
ND
ND
2 x 10~2)
8 x 10"")
ND
ND
ND
PR
PR
3 x 10~2)
PR
PR
PR
ND
1 x 10" 2)
PR
Donisthorpe
Bituminous/None
Component Vol %
60.85
28.1
7.7
0.55
2.7
ND
ND
PR
PR
ND
ND
ND
PR
PR
PR
PR
PR
PR
ND
(2.3 x 10~2)
PR
Newstead
Bituminous/
Dolomite
Component Vol %
60.55
28.65
7.25
1.05
2.35
ND
ND
(7.4 x 10~
PR
ND
ND
ND
PR
PR
(6.9 x 10"
PR
PR
PR
ND
(9.6 x 10~
PR
3)
2)
3)
*0riginally reported as CnHm which may also contain other light olefins.
HHV (dry basis):
J/Nm3 (Btu/scf)
1.39 x 107
(374)
(1.40 x 107)
(375)
1.41 x 107
(379)
Steam/02
Gasification Media: Steam/02 Steam/02
ND - presence of component not determined
PR - component is probably present, amount not determined
NP • component is probably not present
Component volume % is given on a relative basis to all other components that
have a value for volume % listed.
A-97
-------
into the lock as the coal falls into the gasifier, and the
gas remaining in the lock will be composed of pressurizing
gas and raw gas from the gasifier. If no pressurizing gas
is used, the lock will fill with raw gas as the coal is
dumped into the gasifier, and the gas remaining in the lock
will be composed of raw gas. For any of these cases, as
raw gases pass countercurrently through the incoming coal
and into the lock, tars, oils, water and other constituents
of the raw gas may condense or be adsorbed on the coal feed.
In addition to the components in the raw gas (Stream No. 5)
and the lock filling gases (Stream No. 7), the coal lock
gas stream may also contain entrained coal fines. In order
to prevent the release of these contaminants to the atmos-
phere, this stream may be recycled to the raw gas stream or
it may be incinerated in a flare or boiler. If gaseous
contaminants in this stream are relatively low in concen-
tration, the stream may be passed through wet cyclones to
remove particulates, and then vented to the atmosphere.
The gas which remains in the lock after depressurization
will be displaced by the incoming coal charge. This gas
can be controlled by the same methods described above, but
hoods and vent fans would be required to collect the gas.
Slag Quench Vent Gas (Stream No. 12) - The composition of
this gas stream will be determined by the mode of operation
of the slag tap. If the slag is tapped intermittently by
inducing slag flow with a slag burner as shown in Figure 1,
the slag quench vent stream will be created when slag is
removed from the gasifier by swinging the slag burner aside
and by opening the slag quench vent to create a positive
pressure differential across the slag tap hole. For this
case, the slag quench vent stream will be composed of com-
bustion products, raw gas from the gasifier, steam, en-
trained slag particles, and any volatile components in the
slag quench makeup water (Stream No. 10). If the slag is
tapped continuously, a slag quench vent stream would not be
present. This gas stream may be first passed through a
cyclone to remove particulates, or it may be incinerated
directly in a flare or boiler.
Slag Lock Gas (Stream No. 8) - This gas stream is created
when the slag lock is depressurized in order to discharge
the slag slurry. This stream may contain components in the
raw gas from the gasifier which have dissolved in the slag
quench water, steam, entrained slag particles, and any
volatile components in the slag quench makeup water (Stream
No. 10). Depending on the composition of the slag lock
gas, it may be first passed through a cyclone to remove
particulates and then vented to the atmosphere or it may be
incinerated in a flare or boiler.
A-98
-------
Process Condensate and Gas Quenching Liquor (Stream No. 14) -
This liquid stream is composed of the raw gas scrubbing
liquor plus raw gas condensate from the waste heat boiler.
This stream will be composed of water plus the constituents
of the raw gas (Stream No. 5) which condense or dissolve in
the quench water. The components most likely to be present
in this stream are:
H20
Tar
Tar Oil
Naphthas
Crude Phenols
Particulates (coal fines
and ash)
NH3
H2S
Organic sulfur compounds
Thiocyanates
HCN
Trace Elements
The amounts of these components will be dependent on the raw
gas composition and the gas quenching and cooling processes
used. Processes that can be used to remove these contami-
nants are described in the water pollution control section.
Slag Quench Slowdown (Stream No. 11) - This liquid stream
will be composed of the slag quench water which is removed
from the slag lock prior to removal of the slag slurry.
This stream will also contain condensate from the slag
quench vent gas/liquid separator. The slag quench blowdown
may contain any of the components present in the raw gas
from the gasifier or in the quench water makeup (Stream
No. 10). This stream may also contain entrained slag par-
ticles. The concentrations of contaminants in this stream
will determine the control technology used to control this
stream. This stream may be sent to disposal in evaporation
ponds which will result in emissions to the atmosphere of
all volatile components in the stream.
Slag Slurry (Stream No. 4) - The slag slurry contains slag
particles and slag quench water. The slag quench water in
the slurry will have the same composition as the slag quench
blowdown (Stream No. 11). The slag is composed of the
mineral matter in the feed coal with approximately 1% unre-
acted carbon plus any ash fluxing agents added to the feed
coal. The exact composition of the slag is dependent on
the composition of the feed coal and fluxing agents (if
used) and the gasifier operating conditions. The suspended
solids removal processes described in Appendix D can be
used to dewater the slag slurry. The recovered water could
be recycled to the process condensate and gas quenching
liquor. The dewatered slag or slag slurry is a solid waste
product which requires ultimate disposal. Processes that
A-9 9
-------
can be used for slag slurry disposal are described in the
solid waste treatment section.
REFERENCES NOT CITED
L-6 Stukel, James, Michael Rieber and Shao Lee Soo, Flue
Gas Desulfurization and Low~Btu Gasification. A Com-
parison. Appendix GiReport No. PB-248 064, NSF/RA/
N-75/037G, NSF Grant No. NSF-GI-35821. Urbana-Champaign,
IL, Illinois Univ., Center for Advanced Computation,
May 1975.
L-1984 Ricketts, T. S., "Modern Methods of Gas Manufacture
including the Lurgi Process", J. Inst. Fuel 37 (283),
328-41 (1964).
L-7971 Bituminous Coal Research, Inc., Gas Generator Research
and Development, Survey and Evaluation, Phase T, Volume
T:Report No. PB-234 523, OCR-20, Int. 1, Vol. 1, OCR
Contract No. DI-14-01-0001-324. Monroeville, PA,
August 1965.
L-8583 American Gas Association, Proceedings of the Seventh
Synthetic Pipeline Gas Symposium. Chicago, IL, 27-29
October 1975.Arlington, VA, 1976-
A-100
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COAL GASIFICATION OPERATION GASIFICATION MODULE
FIXED-BED GASIFIERS
Foster Wheeler/Stoic Gasifier
GENERAL INFORMATION
Process Function - Atmospheric coal gasification in a grav-
itating bed by injection of steam plus air with counter-
current gas/solid flow.
Development Status - Demonstration plant construction t
-------
• Heat transfer and cooling mechanism: direct gas/solid
heat transfer; water jacket provides cooling for the
bottom third of the gasifier.
• Coal feeding mechanism: semi-continuous rotary hopper
at the top of the gasifier.
Gasification media introduction: continuous blowing of
steam plus air at the bottom of the coal bed through a
slotted ash grate.
Ash removal mechanism: a slotted grate at the bottom of
the coal bed removes the ash and dumps it into a wat^r
sealed ash pan; an ash elevator picks up the ash and
ejects it from the gasifier.
Special features:
- Internal gasifier baffles permit separation of the
product gas into a clear, tar-free side gas stream
and a top gas stream which contains volatiles and tars.
Poke holes at the top and at the sides of the gasifier
permit introduction of steam lances or poke rods.
Flow Diagram - See Figure 1.
Operating Parameter Ranges (Ref. 96) -
Gas outlet temperature: ^394 K (250 F) at top gas outlet
^922 K (1200 F) at side gas outlet
Maximum coal bed temperature: vL477°K. (2200°F)
Gasifier pressure: Atmospheric
Coal residence time in gasifier: Several hours
Normal Operating Parameters (Ref. 97) -
Gas outlet temperature: ^3940K (250 F) at top gas outlet
-V922 K (1200°F) at side gas outlet
Maximum coal bed temperature: -vl477°K (2200°F)
Gasifier pressure: Atmospheric
Coal residence time in gasifier: Several hours
A-102
-------
VENT GAS
l
H«
O
COAL
STEAM
AIR/
OXYGEN
DUST
ASH
ELECTROSTATIC
PRECIPITATOR
TAR/OIL
_^_ LOW / MEDIUM
BTU GAS
Figure 1. Foster Wheeler/Stoic Gasifier
-------
Raw Material Requirements (Ref. 98) -
Coal feedstock requirements:
Type: lignite, subbituminous, noncaking bituminous
- Size: 19 - 38 mm (0.75 to 1.5 in)
- Rate: 103 g/sec-m2 (76.4 lb/hr-ft2)
- Pretreatment required: Crushing and sizing; partial
oxidation may be required for strongly caking coals.
Steam requirements: 0.37 kg/kg coal
Oxygen requirements: Not applicable
Air requirements: 2.13 kg/kg coal
Quench water make-up requirements: Not applicable
Utility Requirements - Data not available.
Process Efficiency - Data not available.
Expected Turndown Ratio - 100/20 with automatic control
100/5 with manual control
tFull capacity output]
[Minimum sustainable
.e output]
Gas Production Rate - 3.24 Nm3/kg coal (54.8 scf/lb coal)
PROCESS ADVANTAGES
• By-products produced: two-stage gas production allows
relatively simple by-product recovery.
• Environmental considerations: two stage operation re-
quires no direct water quenching of the gas streams which
limits the volume of wastewater requiring further'
processing.
• Start-up considerations: gasifier can be started up in
24 hours and can be placed in a standby condition with
a minimal air supply.
A-104
-------
Process efficiency: although maximum process efficiency
is limited by maintaining a coal bed temperature below
the ash fusion temperature, the two-stage operation of
the gasifier should yield a fairly high thermal
efficiency.
Reactor size: small reactor size may be advantageous
for small-scale industrial applications.
PROCESS LIMITATIONS
Coal types: gasifier requires non-caking coal feed.
Environmental considerations: process condensate and
by-products require additional processing; poke holes
may be a source of emissions of raw product gas.
Operating pressure: product gas may require compression
for transmission or utilization in combined-cycle
applications.
Process efficiency: maintaining the coal bed tempera-
ture below the ash fusion temperature limits the maximum
process efficiency.
Reactor size: limited reactor size may necessitate use
of multiple units in parallel for large installations.
INPUT STREAMS
Coal: (Stream No. 1)
- Type: Elkol, Wyoming
Subbituminous A
- Size: mm 19 - 38
(in) (0.75 - 1.5)
- Rate: Data not available
- Composition:
• j, $
Volatile matter 32.7%
Moisture 18.8%
A-105
-------
Ash 5.4%
Sulfur (dry basis) 0.5%
- HHV: J/kg 2.4 x 107
(Btu/lb) (10,259)
- Swelling number: < 2.7
- Caking index: Data not available
Steam: (Stream No. 2) 0.37 kg/kg coal
• Oxygen: (Stream No. 3) Not applicable
Air: (Stream No. 3) 2.13 kg/kg coal
DISCHARGE STREAMS AND THEIR CONTROL
The Foster Wheeler/Stoic gasifier will produce the following
discharge streams. Stream numbers refer to Figure 1.
Gaseous Discharge Streams
Low/medium-Btu gas (Stream No. 11)
Coal hopper vent gas (Stream No. 6)
Ash pan gas (Stream No. 7)
Liquid Discharge Streams:
• Tar/oil (Stream No. 9)
Solid Discharge Streams:
Ash (Stream No. 4)
• Dust (Stream No. 10)
The following text discusses the compositions of these discharge
streams, using as a basis the INPUT STREAM data given above and
the following gasifier conditions:
A-106
-------
Coal type: Subbitutninous
Gasifier pressure: Atmospheric
Steam/02: Not applicable
- Steam/air: (kg/kg) 0.17
Gas outlet temperature °K (°F):
- 394 (250) at top gas outlet
- 922 (1200) at side gas outlet
Gas production rate: 3,24 Nm3/kg coal (54.8 scf/lb coal)
Low/Medium-Btu Gas (Stream No. 11) - The composition of the
low/medium-Btu gas from the Foster Wheeler/Stoic gasifier
will be dependent on the composition of the coal feed, gas-
ifier operating conditions, and the processing operations
applied to the top gas and side gas streams. No quantita-
tive data is currently available pertaining to the composi-
tion of the gas produced by the Foster Wheeler/Stoic gasi-
fier. The components in the combined top gas (Stream No. 8)
and side gas (Stream No. 5) from the Woodall-Duckham/Gas
Integrale gasifier and from the Foster Wheeler/Stoic gasi-
fier are probably similar in occurence and concentration,
due to design and operating characteristic similarities be-
tween the gasifiers with airblown operation. Because the
low/medium-Btu gas stream contains significant amounts of
H2S, organic sulfur compounds, CO2, hydrocarbons, and water,
further treatment may be required prior to utilization of
the gas, Processes that can be used to remove these con-
taminants are described in the acid gas removal section,
Coal Hopper Vent Gas (Stream No. 6) - This gaseous discharge
stream is created when the valve at the bottom of the coal
feed hopper opens to allow the coal feed to enter the gasi-
fier. The raw gas in the top of the gasifier fills the feed
hopper as the coal is discharged into the gasifier. When
the valve at the top of the hopper opens to admit a new
charge of coal, the raw gas in the hopper is displaced up
through the coal hopper and potentially into the atmosphere.
The composition of this stream should be similar to the top
gas (Stream No. 8), although some constituents may condense
or be adsorbed on the surface of the coal feed. In order
to prevent the release of these components to the atmosphere,
this stream may be collected by hoods and then incinerated
or recycled to the raw gas or air intake.
A-107
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Ash Pan Gas Stream No. 7) - This gaseous discharge stream
is the result of evaporation of suspended or dissolved com-
ponents in the ash pan water seal. Any of the components
in the raw gases (Stream Nos. 5 & 8) plus any components
present in the water input to the ash pan may be present in .
this stream. This stream may be small enough in magnitude
to permit direct venting to the atmosphere or it may be
collected by hoods and then incinerated in a flare or boiler.
Oil (Stream No. 9) - This stream is composed of the droplets
of tar and oil which are removed from the top gas stream
by the electrostatic precipitator. The compounds which
make up these tars and oils will be determined by the com-
position of the feed coal and the operating conditions in
the gasifier. In addition to tars and oils, this stream
may also contain water, particulates, phenols, or any of
the components in the raw top gas (Stream No. 8). The tars
and oils in this stream may be separated from the water,
phenols, particulates, or other contaminants in order to
recover them as by-products. The tar may be relatively
free of contaminants, in which case it could be utilized
as a by-product without additional treatment. Processes
which can be used to separate tar and oils from aqueous
and solid contaminants are described in the water pollu-
tion control section.
Ash (Stream No. 4) - This solid stream will be composed
mainly of the mineral matter present in the coal feed with
approximately 97, unreacted carbon. The exact composition
of the ash is dependent on the composition of the feed coal
and the gasifier operating conditions. The ash may also
contain any of the components present in the ash pan seal
water. The ash from the gasifier is a solid waste product
which requires ultimate disposal. Methods that can be used
for ash disposal are described in the solid waste control
section.
Dust (Stream No. 10) - This stream is composed of fine par-
ticulates of coal and ash which are removed from the side
gas stream in the cyclone. Any of the heavy solid or liquid
constituents present in the raw side gas may be present in
this stream. The collected dust may be sent to disposal
with the gasifier ash, or it may be recycled to the gasifier
coal feed, possibly in a briquette form.
A-108
-------
COAL GASIFICATION OPERATION GASIFICATION MODULE
FLUIDIZED-BED GASIFIERS
Winkler Gasifier
GENERAL INFORMATION
Process Function - Atmospheric coal gasification in a
fluidized bed by injection of steam olus air or oxygen with
co-current and countercurrent gas/solid flow.
Development Status - Commercially available since 1926.
Licensor/Developer - Davy Powergas
P.O. Drawer 5000
Lakeland, Florida 33803
Commercial Applications -
Production of synthesis gas: 6 gasifiers currently in
operation; 7 other gasifiers operated in the past.
Production of water gas: 23 gasifiers operated in the past.
Applicability to Coal Gasification - Proven commercial gasi-
fier which can accept several types of coal and which can
be operated with air or oxygen. Largest operating installa-
tion is at Madras, India; no commercial installations are
located in the United States.
PROCESS INFORMATION
Equipment (Refs. 99, 100) -
Gasifier construction: vertical, cylindrical steel
pressure vessel with refractory lining.
Gasifier dimensions:
- 5.5 meters (18 ft) inside diameter
- 22.9 meters (75 ft) approximate overall height
Bed type and gas flow: fluidized bed; continuous gas
flow which is both concurrent and countercurreht due to
action in the fluidized bed and disengaging space;
vertical gas outlet at the top of the gasifier.
A-109
-------
• Heat transfer and cooling mechanism: direct gas/solid
heat transfer; internal radiant boiler section at the
top of the gasifier provides cooling above the dis-
engaging space.
Coal feeding mechanism: continuous screw feeder injects
the coal at the sides of the bottom part of 'the gasifier*
Gasification media introduction; continuous injection
of steam plus air or oxygen through several nozzles at the
sides of the gasifier which are located at several levels
in the fluidized bed and-also in the disengaging space
above the bed.
• Ash removal mechanism: 30% of the ash settles out of
the fluidized bed and is removed from the gasifier by
a screw conveyor. The remainder of the ash, which is
entrained in the product gas, is removed by cyclones, wet
scrubbers, and electrostatic precipitators.
Special features:
Internal radiant boiler above the disengaging zone
solidifies ash particles and cools the product gas.
- Internal radiant boiler and external waste h«wat boil&rs
provide 100% of gasification steam requirements.
- Gasification media injection in the disengaging space
facilitates gasification of unconverted carbon en-
trained in the product gas stream.
Flow Diagram - See Figure 1.
Operating Parameter Ranges (Refs. 101, 102, 103) -
• Gas outlet temperature: 867 to 1060°K (1100 to 1450°F)
Maximum coal bed temperature: 1089 to 1256°K (1500 to
1800°F)
• Gasifier pressure: atmospheric
• Coal residence time in gasifier: -1 to 2 hours
Normal Operating Parameters (Ref. 104) -
• Gas outlet temperature: 978°K (1300°F)
• Maximum coal bed temperature: 10898K (1500°F) for lignite
1256°K (1800°F) for hard coals
A-iiO
-------
STEAM
>
I
"2
COAL VENT
LOW/
BTUGftS
OXYGEN/
AD)
^ »- ASH
SLURRY
DRY ASH
Figure 1. Winkler Gasifier
-------
Gasifier pressure: atmospheric
Coal residence time in gasifier: 1 to 2 hours
Raw Material Requirements (Refs. 105, 106, 107, 108,
109, 110) -
Coal feedstock requirements:
- Type: lignite, subbituminous, weakly caking bituminous,
- Size: less than 9.53 mm (0.38 in)
- Rate: 177 to 191 g/sec-m2 (130 to 140 lb/hr-ft2)
- Pretreatment required: crushing to desired
size; drying to less than 30% moisture for lig-
nites; higher rank coals require drying to less
than 18% moisture; strongly caking coals may
require partial oxidation pretreatment
Steam requirements:
- Oxygen-blown operation - 0.2 to 0.3 kg/kg DAF coal
- Air blown operation - 0.2 kg/kg coal
• Oxygen requirements: 0.5 kg/kg DAF coal
Air requirements: 2.5 kg/kg coal
• Quench water make-up requirements: data not available
Utility Requirements (Refs..Ill, 112, 113) - Basis:
Oxygen-blown operation; Illinois #6 coal, HHV - 2 88
x 107 joule/kg (12530 Btu/lb)
• Boiler feed water: 8.26 x 10"* m3/kg coal (198 gal/ton
coal)
Cooling water: Data not available.
• Electricity: Data not available.
Process Efficiency (Refs. 114, 115) - Basis: Oxygen-blown
operation; quenched and cooled product gas; Illinois #6 hieh
volatile bituminous coal HHV (dry) = 2.8,8 x 107 loule/ke
(12530 Btu/lb); reference temperature - 300°K (80°f)
A-112
-------
• Cold gas efficiency: 55% to 72%
[=] [Product gas energy output] ,nn
[Coal energy input]x uu
• Overall thermal efficiency 69%
t=] [Total energy output (product gas + HC by-products + steam)]
[Total energy input (coal + electric power)]
Expected Turndown Ratio - 100/25
[=] [Full capacity output]
[Minimum BUBtainable output]
Gas Production Rate - 216 to 1757 Nm3/hr-m2 (750 to 6100
scf/hr-ftv); 1.33 to 1.62 Nm3/kg coal (22.5 to 27.5 scf/lb
coal).
PROCESS ADVANTAGES
Coal type: Gasifier can accept all types of coals;
strongly caking coals may require pretreatment.
Gasification media: Gasifier can be operated with air
or oxygen.
Environmental considerations: The absence of tars, oils,
and naphthas in the raw gas simplifies control technology
requirements.
Start up considerations: The gasifier can be shut down
in a few minutes; even after several days the gasifier
can be re-started instantly.
Fuel bed stability: The uniform temperature and composi-
tion of the fluidized bed provide stable operating
conditions.
Development status: Gasifier has been operated commer-
cially for many years.
PROCESS LIMITATIONS
Coal types: Strongly caking coals may require partial
oxidation pretreatment; less reactive coals decrease
thermal efficiency and carbon conversion.
A-113
-------
Process efficiency: Efficiency is limited due to large
amount of unconverted coal which leaves the gasifier;
higher temperatures decrease efficiency due to sensible
heat losses.
By-products produced: The large amount of unreacted coal
in the char can be burned as a by-product, but if a
suitable use is not available, the efficiency of the
overall process is greatly reduced.
Operating pressure: Low operating pressure may be a
disadvantage for transmission of the product gas or
utilization in combined cycle applications.
Ash carryover: Separation of high temperature char par-
ticles from the raw gas stream may be an operating
problem.
INPUT STREAMS -
Coal (Stream No. 1):
- Type: Subbituminous A Lignite Subbituminous
-Size: mm (in) <9.53 (0.38) <8.0 (0.31) <9.53 (0.31)
- Rate: g/sec-m2 DNA 191 (140) DNA
(lb/hr-ft2)
- Composition:
Volatile matter DNA 37% 39%
Moisture 16% 4.2% 3%
Ash 19% 33.1% 24%
Sulfur (dry DNA 1.0% DNA
basis)
- HHV: Joule/kg 2.44 x 107 DNA DNA
(Btu/lb) (10,600)
- Swelling number: DNA 0 DN^
- Caking index: DNA 0 DNA
A-114
-------
Steam (Stream No. 2):
kg/kg coal
^0.2
^0.2-0.3
Oxygen (Stream No. 3):
kg/kg coal NA
Air (Stream No. 4):
kg/kg coal
^2.5
NA
NA
DISCHARGE STREAMS AND THEIR CONTROL
The Winkler gasifier will produce the following discharge
streams. Stream numbers refer to Figure 1.
Gaseous Discharge Streams
Low/medium-Btu gas (Stream No. 13)
Coal bin nitrogen vent (Stream No. 4)
• Dry ash bin nitrogen vent (Stream No. 12)
Ash slurry settler vent (Stream No. 8)
Liquid Discharge Streams
Process condensate and gas quenching liquor (Stream No. 9)
Solid Discharge Streams
• Dry Ash (Stream No. 10)
• Ash slurry (Stream No. 11)
The following text discusses the compositions of these discharge
streams, using as a basis the INPUT STREAM data given above, and
the following gasifier conditions:
• Coal type: Subbitutninous A Lignite Subbituminous
• Gasifier pressure: Atmospheric Atmospheric Atmospheric
• Steam/02: (kg/kg) NA ^0.5 M).5
• Steam/air: (kg/kg) M).08 NA NA
A-115
-------
• Gas outlet temperature DNA
• Gas production rate: DNA 0-75 (12.7) DNA
Nm3/kg DAF coal
(scf/lb DAF coal)
Low/Medium-Btu Gas (Stream No. 13) - The composition of the
low/medium-Btu gas from the Winkler gasifier will be depen-
dent on the composition of the coal feed, gasifier operating
conditions, and the gas cooling operations applied to the
raw gas stream. The compositions given below list the com-
ponents in the raw gas (Stream No. 5) for lignite and sub-
bituminous coal feedstocks. Because this gas stream contains
significant amounts of HzS, organic sulfur compounds, C02,
and water further treatment may be required prior to utili-
zation of the gas. Processes that can be used to remove
these contaminants are described in the acid gas removal
section.
Coal Bin Nitrogen Vent (Stream No. 4) - This gas stream
contains the nitrogen which is used to blanket the coal
dust feed bins in order to prevent explosions of the fine
coal particles. This stream will also contain entrained
coal dust particles. These particles can be removed with
filters, cyclones, or scrubbers prior to venting the
nitrogen to the atmosphere.
Dry Ash Bin Nitrogen Vent (Stream No. 12) - This gas stream
contains the nitrogen which is used to blanket the dry ash
bin in order to prevent further reaction or combustion of
the char in the ash. This stream will also contain en-
trained ash particulates plus some raw product gas or gases
evolved from the hot char. The entrained ash particulates
in this gas stream can be removed with filters, cyclones, or
scrubbers. If there are significant concentrations of raw
gas (Stream No. 5) or gas evolved from the hot char in this
stream, these contaminants may be controlled by recycling
the stream to the raw gas, or by incinerating the stream
in a flare or boiler, although the nitrogen content of the
stream may eliminate this option due to NOX formation or
non-flammability
Ash Slurry Settler Vent (Stream No. 8) - This gas stream
may contain any of the components in the raw gas (Stream
No. 5) which dissolve or condense in the direct contact
scrubber/cooler. The ash which is washed out of the raw gas
stream is separated from the quench liquor in a settler.
The dissolved or condensed components from the raw gas stream
A-116
-------
Coal Type
Low/Medium-Btu Gas Subbituminous A
Component
CO
H2
CH.»
CO 2
N2 + Ar
02
H2S
COS + CS2
Mercaptans
Thiophenes
S02
H20
Naphthas
Tar
Tar Oil
Crude Phenols
NH3
HCN
Particulates
(coal fines, ash)
Trace Elements
Component Vol %
22.0
14.0
1.0
ND
ND
7.0
56.0
ND
PR
ND
ND
ND
ND
PR
NP
NP
NP
ND
ND
ND
PR
PR
Lignite Subbituminous
Component Vol % Component Vol %
35.5
40.0
2.8
ND
ND
19.9
1.8
ND
PR
ND
ND
ND
ND
PR
NP
NP
NP
ND
ND
ND
0.46 kg/kg
coal DAF
PR
37.0
37-0
3.0
ND
ND
20.0
3.0
ND
PR
ND
ND
ND
ND
PR
NP
NP
NP
ND
ND
ND
PR
PR
HHV (Dry basis):
J/Nm3 (Btu/scf)
4.66 x 106
(125)
1.01 x 107
(272)
1.0 x 107
(270)
Steam/02
Gasification media: Steam/air Steam/02
ND » presence of component not determined
PR - component is probably present, amount not determined
NP - component is probably not present
Component volume % is given on a relative basis to all other components
that have a value for volume % listed.
A-117
-------
that evaporate from the quenching liquor are removed from
the settler through the vent. This vent stream may also
contain entrained droplets of gas quenching liquor (Stream
No. 9) or ash slurry (Stream No. 11). The solid and liquid
contaminants in this stream can be removed with filters,
cyclones, or scrubbers. If there are significant concen-
trations of contaminants from the raw gas (Stream No. 5) in
this stream, they may be controlled by recycling the stream
to the raw gas, or by incinerating the stream in a flare
or boiler.
Process Condensate and Gas QuenchingLiquor (Stream No. 9) -
This liquid stream is composed of the raw gas scrubbing
liquor plus raw gas condensate from the direct contact
scrubber/cooler. The ash which is washed out of the raw
gas stream is separated from the quench liquor in a settler,
but some ash particles may be carried along in this blow-
down stream. The other components in this stream will be
the constituents of the raw gas (Stream No. 5) which con-
dense or dissolve in the quench liquor. The components
most likely to be present in this stream are:
• H20
Particulates (coal fines, char)
• NH3
• H2S
Trace elements
Processes that can be used to remove these contaminants are
described in the water pollution control section.
Dry Ash (Stream No. 10) - This stream is composed of the
larger ash particles formed in the gasifier which were heavy
enough to fall to the bottom of the gasifier and into the
screw conveyor plus the ash particles which were removed
from the raw gas (Stream No. 5) in the waste heat boiler and
in the cyclone. The ash will consist of the mineral matter
present in the coal feed with 10% to 30% unreacted carbon.
The exact composition of the ash is dependent on the com-
position of the feed coal and the gasifier operating condi-
tions. The dry ash may contain enough unreacted carbon to
be utilized as a salable by-product. The char in the ash
may be burned as a fuel or may be used as an adsorbent sim-
ilar to activated charcoal. If the dry ash is a solid waste
product, it may be combined with the ash slurry (Stream No.
11) prior to ultimate disposal. Processes that can be used
for ash disposal are described in the solid waste treatment
section.
A-118
-------
Ash Slurry (Stream No. 11) - This stream contains the ash
particles which were not removed from the raw gas (Stream
No. 5) in the waste heat boiler or in the cyclone. The
ash particles are washed out of the raw gas stream in the
direct contact scrubber/cooler and the ash is separated
from the quench liquor (Stream No. 9) in a settler. The
bottom product removed from the settler is the ash slurry
(Stream No. 11) which contains approximately 25% to 35%
solids. The liquid portion of the slurry is composed of
the process condensate and gas quenching liquor (Stream
No. 9). The ash in the slurry will consist of the mineral
matter present in the feed coal with 10% to 30% unreacted
carbon. The suspended solids removal processes described
in Appendix F can be used to dewater the ash slurry. The
recovered water could be recycled to the process condensate
and gas quenching liquor (Stream No. 9). The dewatered
ash or ash slurry is a waste product which requires ultimate
disposal. The ash slurry may be combined with the dry ash
(Stream No. 10) prior to disposal. Processes that can be
used for ash slurry disposal are described in the solid
waste treatment section.
REFERENCES NOT CITED
L-245 Bodle, W. W., and K. C. Vyas, "Clean Fuels from Coal -
Introduction to Modern Processes", in C1ean Fuels From
Coal, Symposium Papers, Chicago, IL, September 1973.
Chicago,IL, Inst. of Gas Technology, December 1973.
L-693 Institute of Gas Technology, Clean Fuels From Coal,
Symposium Papers, Chicago. IL, 10-14 September 1973.
Chicago,IL.December 1973.
L-708 Jahnig, C. E., Evaluation of Pollution Control in Fossil
Fuel Conversion Processes.Gasification,Section 8:
Winkler Process"Final Report.Report No. EPA-650/2-
74-009J, EPA Contract No. 68-02-0629. Linden, NJ, Exxon
Research & Engineering Co., September 1975.
L-727 Katz, Donald L. , et al., Evaluation of Coal Conversion
Processes to Provide Clean Fuels.Final Report.Report
No. EPRI 206-0-0, PB-234 202 & PB-234 203. Ann Arbor,
MI, Univ. of Michigan, Col. of Engineering, 1974.
L-860 Mudge, L. K., et al., The Gasification of Coal. Energy
Program Report. Richland, WA, Battelle Pacific North-
west Labs., 1974.
A-119
-------
L-1436 Howard-Smith, I., and G- J. Werner, Coal Conversion
Technology. Park Ridge, NJ, Noyes Data Corp., 1976.
L-1597 Newman, L. I., Oxygen Gasification Processes in Germany.
Tech. Pub. No. 2116.Washington, DC, U.S. Bur. Mines,
November 1946.
L-5283 Ayer, Franklin A., comp., Symposium Proceedings:
Environmental Aspects of Fuel Conversion Technology, II,
Hollywood, FL, December 1975.Report No. EPA-600/2-76-
149, EPA Contract No. 68-02-1325, Task 57. Research
Triangle Park, NC, Industrial Environmental Research
Lab., Office of Energy, Minerals and Industry, June
1976.
L-7888 Bertrand, R. R., et al., Trip Report: Four Commercial
Gasification Plants. Research Triangle Park, NC, EPA,
Office of Research & Development, 1975.
A-120
-------
COAL GASIFICATION OPERATION GASIFICATION .MODULE
ENTRAINED-BED GASIFIERS
Koppers-Totzek Gasifier
GENERAL INFORMATION
Process Function - Atmospheric pressure coal gasification
in an entrained bed by injection of coal plus steam plus*
oxygen with co-current gas/solid flow.
Development Status - Commercially available since 1952.
Licensor/Developer - Koppers Company, Inc.
Koppers Building
Pittsburgh, Pennsylvania 15219
Commercial Applications -
Production of synthesis gas: 43 gasifiers currently
in operation.
Applicability to Coal Gasification - Proven commercial
gasifier which can accept all types of coal feedstocks.
Largest installation is at Johannesburg, South Africa;
no commercial installations are located in the United
States.
PROCESS INFORMATION
Equipment (Refs. 116, 117, 118) -
Gasifier construction: Horizontal ellipsoidal, double
walled steel vessel with refractory lining. The two-
headed gasifier has two heads shaped as truncated cones
mounted on either end of the ellipsoid. The four-
headed gasifier resembles two intersecting ellipsoids
with heads at the ends of the ellipsoids oriented 90°
apart.
A-121
-------
Gasifier dimensions:
Internal diameter of
ellipsoid
Two-headed
gasifier
3.1 - 3.7 m
(10 - 12 ft)
Internal diameter at the 1.8 - 2.4 m
end of truncated cone head (6-8 ft)
Approximate overall length 7.6 m
of each ellipsoid (25 ft)
Internal volume
28.3 m3
(1000 ft3)
Four-headed
gasifier
. 4.0 m
(13 ft)
7.6 m
(25 ft)
59.4 m3
(2100 ft3)
Bed type and gas flow: Entrained bed; continuous co-
current gas flow; vertical gas outlet at the top of the
gasifier in the center of the ellipsoid.
Heat transfer and cooling mechanism: Direct gas/solid
heat transfer; double walled gasifier acts as a water
jacket to provide gasifier cooling.
Coal feeding mechanism: Continuous screw conveyor feeds
the pulverized coal to mixing nozzles at the ends of the
gasifier heads; the coal is entrained in a pretnixed stream
of steam and oxygen and the mixture is injected into the
gasifier through sets of two adjacent burners.
Gasification media introduction: Continuous injection of
steam plus oxygen, with entrained coal feed, through sets
of two adjacent burners at the ends of the truncated cone
heads of the gasifier. Injection speeds are above ttet
speed of flame propagation to prevent flashback.
Ash removal mechanism: Approximately 50% of the ash
flows down the gasifier walls as molten slag and drains
into a slag quench tank where circulating water causes
it to shatter into a granular form; a conveyor lifts the
slag granules out of the quench.tank. The remainder of
the ash leaves the gasifier as fine slag particles,
entrained in the exit gas, which are quenched and soli-
dified at the gasifier exit by water sprays. The slag
granules are removed from the product gas stream by a
washer cooler and disintegrator scrubbers. The slag is
removed from the water as a sludge by a clarifier.
A-122
-------
Special features:
Direct water sprays and washer cooler solidify and
remove entrained slag from the product gas.
Gasifier water jacket generates low-pressure steam
for gasification.
Coal screw feeder provides continuous coal feed.
Slag quench tank solidifies the slag to permit removal
by a belt conveyor.
Flow Diagram - See Figure 1.
Operating Parameter Ranges (Refs. 119, 120, 121, 122, 123) -
• Gas outlet temperature: 1756 to 1783°K (2700 to 2750°F)
• Maximum coal bed temperature: 2089 to 2200°K (3300 to
3500°F)
Gasifier pressure: Atmospheric
Coal residence time in gasifier: Approximately one second
Normal Operating Parameters (Refs. 124, 125, 126) -
• Gas outlet temperature: 1756°K (2700°F) prior to water
spray.
• Maximum coal bed temperature: 2200°K (3500°F)
Gasifier pressure: Atmospheric
Coal residence time in gasifier: Approximately one second
Raw Material Requirements (Refs. 127, 128, 129) -
Coal feedstock requirements:
' - Type: All types
- Size: 70% to 90% less than 0.074 mm (0.003 in)
- Rate: 431 to 734 g/sec-m2 (317 to 540 lb/hr-ft2)
A-123
-------
-Pv
STEAM
AIR/OXYGEN
COAL
LOW/MEDIUM
BTU GAS
CONDENSATE
SLAG
SLAG SLURRY
Figure 1. Koppers-Totzek Gasifier
-------
Pretreatment required: Pulverizing; drying to approx-
imately 17o to 87o moisture. For coals with a very high
ash fusion temperature, fluxing agents may be added to
the coal feed to lower the ash'fusion temperature.
Steam requirements: 0.14 to 0.59 kg/kg coal
• Oxygen requirements: 0.73 to 0.95 kg/kg coal, as 98%
oxygen.
Air requirements: Not applicable.
Quench water makeup requirements: Data not available.
Utility Requirements (Ref. 130) - Basis: Oxygen-blown operation;;
Eastern coal, HHV - 2.91.x 107 joule/kg (12,640 Btu/lb)
• Boiler feedwater: 2.0 x 10"3m3/kg coal (480 gal/ton coal)
Cooling water: Data not available.
Electricity: Data not available.
Process Efficiency (Ref. 131) - Basis: Oxygen-blown operation;
quenched and cooled product gas; Eastern U.S. bituminous coal
HHV (dry) - 2.91 x 107 joule/kg (12,640 Btu/lb); reference
temperature - 300°K (80°F).
Cold gas efficiency: 757o
[-] [Product gas energy output] x 10Q
[Coal energy input]
Overall thermal efficiency: 68%
[•] [Total energy output (product gas + HC by-products + steam)]
A XUU
[Total energy input (coal + electric power)]
Expected turndown ratio - 100/60 for two-headed gasifier
100/30 for four-headed gasifier
= [Full capacity output]
[Minimum suitable output]
Gas Production Rate - Oxygen-blown; 1.47 to 1.92 Km3/kg coal
(Z5 to 32.5 scf/lb coal) (Ref. 132).
A-12 5
-------
PROCESS ADVANTAGES
Coal type: Gasifier can accept all types of coal.
By-products: No by-products, except sulfur, which require
additional processing are produced.
Environmental considerations: The absence of tars, oils,
naphthas and phenols in the raw gas simplifies control
technology requirements.
Start-up consideration: Gasifier can be started in 30
minutes and can be shut down instantly, and restarted in
10 minutes.
Feed size: Gasifier uses pulverized fuel, which elimi-
nates rejection of fine coal particles.
Development status: Gasifier has been operated commer-
cially for many years.
PROCESS LIMITATIONS
Gasification media: Operation with steam plus air requires
high air preheat and dilutes the product gas with nitrogen;
thus, this mode of operation is not economical.
Process efficiency: High temperature of exit gases and
slag requires heat recovery in order to maintain satis-
factory thermal efficiency.
Operating pressure: Low operating pressure may be a
disadvantage for transmission of the product gas or
utilization in combined-cycle applications.
Ash carryover: Separation of high-temperature slag
particles from the raw gas stream may be an operating
problem
A-126
-------
INPUT STREAMS (Refs. 133, 134) -
• Coal (Stream No. 1):
- Type:
Lignite,A High volatile High volatile
B bituminous C bituminous
70% <200 mesh 70% <200 mesh 70% <200 meali
- Data Not Available -
- Data Not Available -
8%
12.7%
1.5%
2.31 x 107
(10,050)
0
0
2%
10.2%
2.5%
2%
13.7%
1.1%
2.99 x 107 2.91 X 107
(13,000) (12,640)
- Data Not Available -
- Data Not Available -
Size:
Rate:
Composition:
Volatiles -
Moisture -
Ash -
Sulfur (dry basis)
HHV: joule/kg
(Btu/lb)
Swelling number:
Caking index:
Steam (Stream No. 2):
kg/kg DAF coal
Oxygen (Stream No. 3) :
kg/kg DAF coal
Air: Not applicable
DISCHARGE STREAMS AND THEIR CONTROL
The Koppers-Totzek gasifier will produce the following dis-
charge streams. Stream numbers refer to Figure 1.
Gaseous Discharge Streams -
Low/medium-Btu gas (Stream No. 13)
Coal bin nitrogen vent (Stream No. 7)
0.141
0.731
0.412
0.860
0.405
0 . 849
A -12 7
-------
Liquid Discharge Streams -
• Process condensate and gas quenching liquor (Stream No.
12).
Solid Discharge Streams -
• Slag (Stream No. 4)
• Slag slurry (Stream No. 11)
The following text discusses the compositions of these discharge
streams, using as a basis the INPUT STREAM data given above and
the following gasifier conditions:
Coal type: High volatile High volatile
Lignite A B^ bituminous C bituminous
Gasifier pressure Atmospheric Atmospheric Atmospheric
• Steam/Oz (kg/kg) 0.193 0.479 0.477
Gas off-take temp. - Data Not Available -
Gas production rate: 1.62 2.02 1.98
Nm3/kg DAF coal (27.4) (34.3) (33.5)
(scf/lb 13AF coal)
Low/Medium-Btu Gas (Stream No.13) - The composition of the
low/medium-Btu gas from the Koppers-Totzek gasifier will be
dependent on the composition of the coal feed, gasifier
operating conditions, and the gas cooling operations applied
to the raw gas stream. The compositions given below list
the components in the raw gas (Stream No. 5) for lignite
and bituminous coal feedstocks. Because this gas stream
contains significant amounts of H2S, organic sulfur com-
pounds, CO2, and water, further treatment may be required
prior to utilization of the gas. Processes that can be used
to remove these contaminants are described in the section
on acid gas removal.
A-128
-------
Coal type
Component
CO
H2
CH.,
C2H6
CO 2
N2+Ar
02
H2S
COS + CS2
Me reap tans
Thiophenes
S02
H20
Naphthas
Tar
Tar Oil
Crude Phenols
NH3
HCN
Particulates (coal
fines, ash)
(kg/kg DAF coal)
Trace elements
HHV (dry basis):
joule /Nm3
(Btu/scf)
Gasification Media:
Lignite A
Component Vol %
56.87
31.30
PR
ND
ND
10.0
1.18
ND
0.60
0.05
ND
ND
PR
PR
ND
ND
ND
ND
<0.2
PR
B bituminous
C bituminous
(0.08)
PR
i.l x 107
(290)
Steam/02
Component: Vol % Component Vol %
52.51
35.96
PR
ND
ND
10.0
1.15
ND
0.36
0.02
ND
ND
PR
PR
ND
ND
ND
ND
<0.2
PR
(0.08)
PR
1.1 x 107
(290)
Steam/Da
52.35
35.66
PR
ND
ND
10.0
1.12
ND
0.82
0.05
ND
ND
PR
PR
ND
ND
ND
ND
<0.2
PR
(0.06)
PR
1.1 x 107
(290)
Steam/02
ND - presence of component not determined
PR - component is probably present, amount not determined
Component volume % is given on a relative basis to all other components
that have a value for volume % listed.
A-129
-------
Coal Bin Nitrogen Vent (Stream No. 7) - This gas stream
contains the nitrogen which is used to blanket the coal feed
bins in order to prevent explosions of the fine coal parti^
cles. This stream will also contain entrained coal dust
particulates, which can be removed with filters, cyclones,
or scrubbers prior to venting the nitrogen to the atmosphere.
Process Condensate and Gas Quenching Liquor (Stream No. 12) -
This liquid stream is composed of the raw gas scrubbing
liquor plus raw gas condensate from waste heat boilers and
indirect gas coolers. The overflow from the slag quench
tank (Stream No. 9) is also added to this stream. The slag
particles which are removed from the raw gas stream in the
wash cooler are separated from the process condensate in a
settling tank, but some slag particles may be carried along
in the process condensate stream. The other components in
this stream will be the constituents of the raw gas (Stream
No. 5) which condense or dissolve in the quench liquor. The
components most likely to be present in this stream are:
• H20
Particulates (coal fines, slag)
• NH3
• H2S
Trace elements
Processes that can be used to remove these contaminants are
described in the water pollution control section.
Slag (Stream No. 4) - This stream is composed of the larger
slag particles formed in the gasifier which are heavy enough
to fall to the bottom of the gasifier and into the slag
quench tank. The slag particles consist of the mineral
matter present in the feed coal with 5% to 557o unreacted
carbon. The slag may also contain any components present in
the slag quench water (Stream No. 15) or in the raw gas
(Stream No. 5). The exact composition of the slag is depen-
dent on the composition of the feed coal and the gasifier
operating conditions. The slag is a solid waste product
which requires ultimate disposal. In some instances, the
granular slag may be a salable by-product. Processes that
can be used for slag disposal are described in the solid
waste treatment section.
Slag Slurry (Stream No. 11) - This stream contains the smal-
ler slag particles which are carried out of the gasifier in
the raw gas (Stream No. 5). The slag particles are removed
from the product gas stream in the direct quench wash cooler.
The slag slurry is separated from the process condensate and
gas quenching liquor (Stream No. 12) in a settling tank
A-130
-------
The slag particles in this stream will have approximately
the same composition as the slag (Stream No. A) described
above. The slag slurry may also contain any of the compo-
nents present in the raw gas (Stream No. 5), the process
condensate and gas quenching liquor (Stream No. 12), or the
slag quench overflow (Stream No. 9). The slag slurry is a
waste product which requires ultimate disposal. Processes
that can be used for slag slurry disposal are described in
the solid waste treatment section.
REFERENCES NOT CITED
L-394 Corey, Richard C., "Coal Technology", in Riegel's
Handbook of Industrial Chemistry, Seventh edition,
James A. Kent,ed., New York, NY, Van Nostrand Rein-
hold, 1974. (pp. 23-61)
L-693 Institute of Gas Technology, Clean Fuels From Coal,
Symposium Papers, Chicago, IL~10-14 September 1973.
Chicago, IL, December 1973.
L-727 Katz, Donald L., et al., Evaluation of Coal Conversion
Processes to Provide Clean Fuels!Final Report.Report
No. EPRI 206-0-0, PB-234 202 & PB-234 203. Ann Arbor,
MI, Univ. of Michigan, Col. of Engineering, 1974.
L-755 Koppers Engineering & Construction, "Gasification Plants
Using the K-T Process", Company Brochure, Pittsburgh,
PA. undated.
L-811 Magee, E. M., C. E. Jahnig and H. Shaw, Evaluation of
Pollution Control in Fossil Fuel Conversion Processes.
Gasification, Section 1: Koppers-Totzek Process.Final
Report.Report No. PB-231 675, EPA-650/2-74-009a, EPA
Contract No. 68-02-0629. Linden, NJ, Esso Research &
Engineering Co., 1974.
L-1436 Howard-Smith, I., and G. J. Werner, Coal Conversion
Technology. Park Ridge, NJ, Noyes Data Corp., 1976.
L-1445 Hall, E. H., et al. , Fuels Technology. A State-of-the-
Art Review. Report No. PB-242 $35, EPA-650/2-75-034,
EPA Contract No. 68-02-1323, Task 14. Columbus, OH,
Battelle Columbus Labs., April 1975.
L-1710 Personal Communications
A-131
-------
COAL GASIFICATION OPERATION
GASIFICATION MODULE
ENTRAINED-BED GASIFIERS
Bi-Gas Gasifier
GENERAL INFORMATION
Process Function - High-pressure, two-stage coal gasifica-
tion in an entrained bed by injection of oxygen plus steam
and char in the lower stage and injection of steam plus coal
in the upper stage of the gasifier,
Development Status - Pilot plant start-up activities began
in August 1976.
Licensor/Developer - Bituminous Coal Research, Inc.
350 Hochberg Road
Monroeville, Pennsylvania 15146
Commercial Applications - None; gas is used for process
analysis.
Applicability to Coal Gasification - The gasifier concept
has been tested in a small-scale process development unit
and has been operated successfully with lignite, subbittMi-
nous, and bituminous coal feed at elevated temperatures and
pressures. Operation with air instead of oxygen has not
been demonstrated. The pilot plant is located at Homer City,
Pennsylvania.
PROCESS INFORMATION
Equipment (Refs. 135, 136) -
Gasifier construction: vertical, cylindrical steel
pressure vessel which consists of three stages, with
refractory lining in the upper two stages.
• Gasifier dimensions:
- 0.9 meters (3 ft.) inside diameter of refractory
sections
- 1.5 meters (5 ft.) inside diameter of pressure shell
A-132
-------
- 4.0 meters (13 ft.) height of the bottom (slag) zone
- 1.8 meters (6 ft.) height of the middle (char) zone
- 4.3 meters (14 ft.) height of the top (coal) zone
• Bed type and gas flow: entrained bed of coal and char;
continuous concurrent gas flow; vertical gas outlet at
the top of the gasifier.
• Heat transfer and cooling mechanism: direct gas/solid
heat transfer; vertical water tubes in the walls of the
upper two stages provide gasifier cooling.
• Coal feeding mechanism: slurry injection with steam
through nozzles in the upper stage of the gasifier.
• Gasification media introduction: continuous injection
of steam plus oxygen plus char in the lower stage of
the gasifier.
• Ash removal mechanism: slag particles fall into a
quench tank in the bottom of the gasifier. The slag is
removed through a lock hopper.
• Special features:
Slurry feeding mechanism eliminates any moisture con-
tent restrictions for coal feed.
Char cyclone removes entrained char particles from the
raw gas and recycles the char to the gasifier to iifi-
prove carbon conversion.
Two-stage gasifier maximizes methane production in the
gasifier.
Flow Diagram - See Figure 1.
Operating Parameter Ranges (Ref. 137) -
• Gas outlet temperature: 1019 to 1456PK (1375 to 2160°F)
• Maximum coal bed temperature: 1755 to 1922°K (2700 to
3000°F)
• Gasifier pressure: 1.62 to 10.4 MPa (235 to 1515 psia)
• Coal residence time in gasifier; 3 to 22 seconds
A-133
-------
VENT GAS
I
M
CO
HEATER
^ i MAKE-UP
GAS
LOW/MEDIUM
BTU GAS
STEAM
SLAG
Figure 1. Bi-Gas Gasifier
-------
Normal Operating Parameters (Refs. 138, 139) -
Gas outlet temperature: 1200°K (1700°F)
Maximum coal bed temperature: 1755°K (2700°F)
Gasifier pressure: 8.1 MPa (1175 psia)
Coal residence time in gasifier: Stage 1-2 seconds
Stage II - 6 seconds
Raw Material Requirements (Refs. 140, 141, 142, 143) -
Coal feedstock requirements:
Type: all types
- Size: 70% less than 0.074 mm (0.003 in.)
- Rate: %4080 g/sec-m2 (3000 lb/hr-ft2)
- Pretreatment required: crushing, pulverizing, slurry
preparation
Steam requirements: 0.4 to 1.35 kg/kg coal
Oxygen requirements: 0.5 to 0.64 kg/kg coal
Air requirements : <\,3 .1 kg/kg coal
Quench water make-up requirements: Data not available.
Utility Requirements - Data not available.
Process Efficiency (Ref. 144) - Basis: oxygen-blown opera-
tion; quenched and cooled product gas; reference tempera-
ture = 300°K (80°F)
• Cold Gas Efficiency: 69%
['"] [Product gas energy output] x 10Q
[Coal energy input]
Overall thermal efficiency: 65%
[~] [Total, energy output (product gas+HC by-products+^team),] .,
[Total energy input(coal + electric power)]
A-135
-------
Expected Turndown Ratio (Ref. 145) - 100/50
[= ] [Full capacity output]
[Minimum sustainable output]
Gas Production Rate (Ref. 146) - Oxygen blown: 6.4
<7$580 sc£/hr-£ta); 1.33 to 1.62 HmVkg coal (22.5 to 27.5
scf/lb coal) .
PROCESS ADVANTAGES
Coal type: Gasifier can accept all types of coal.
Gasification media: Gasifier can be operated with air
or oxygen.
By-products : No by-products which require additional
processing are produced.
Environmental considerations: The absence of tars, oils,
naphthas and phenols in the raw gas simplifies control
-technology requirements.
Operating pressure: Pressurized operation will be an
advantage for gas transmission by pipeline and utiliza-
tion as a synthesis gas or combined-cycle fuel.
Carbon conversion: Cyclone char recycle system permits
almost 1007o carbon conversion.
Feed size: Gasifier uses pulverized fuel, which elimi-
nates rejection of fine coal particles.
PROCESS LIMITATIONS
Coal type: Coals with low o«h content or a high per-
centage of refractory type ash ftay require a&iitiost of
ash fluxing agents.
Gasification media: Pressurized operation with air ha»
not been demonstrated,
Utilization considerations: Gasifier is designed to
maximize methane formation in the gasifier which may not
be advantageous for all utilization applications.
A-136
-------
• Start-up considerations: The fuel-rich, high-pressure
environment in the gasifier will require start-up using
pyrophoric materials.
Process control: The low system heat capacity and avail-
able reaction capacity will necessitate sensitive feed
control and automatic, interlocked shutdown control.
Char recycle: Separation of large amounts of high tempera-
ture char from the high-pressure gas stream and metering
of the recycled char feed may present operating problems.
Development status: Pilot-plant operations started
in 1976.
INPUT STREAMS (Ref. 147, 148) -
Coal (Stream No. 1 )
- Type:
- Size: mm (in)
- Rate:
- Flux added:
- Composition:
Volatile matter
Moisture
Ash
Sulfur (dry basis)
- HHV J/kg (Btu/lb):
- Swelling number:
- Caking index:
Western Kentucky
#11 Bituminous
less than
0.074 (0.03)
Data not available
Data not available
42.5%
1.3%
7.2%
7.9%
Illinois
#6 Bituminous
70% less than
0.074 (0.03)
Data not available
Data not available
Data not available
4.2%
8.7%
3.9%
3.1 x 107 (13,285) 2.8 x 107 (12,200)
Data not available
Data not available
Data not available
Data not available
A-137
-------
Steam (Stream Nos. 2 & 6): 0.47 kg/kg coal
Oxygen (Stream No. 3 ): 0.57 kg/kg coal
Air (Stream No. 3 ):
Transport Gas (Stream
No. 12 ):
- Rate: Nm3/kg coal
(scf/lb coal)
- Composition:
Component
CO
H2
Not applicable
0.39 (6.56)
0.57 kg/fcg coal
Not applicable
3.1 kg/fcg coal
0.23 (3.96)
C02
N2 + Ar
H20
NH3
H2S
- HHV J/Nm3 (Btu/acf)
Component Vol%
44.0
24.4
15.6
14.0
1.0
1.0
Data not available
Cotgponenj: Vol%
19.6
14.1
3.9
6.5
49.1
6.7
0.1
5.52 x 106 (148)
DISCHARGE STREAMS AND THEIR CONTROL
The Bi-Gas gasifier will produce the following discharge
streams. Stream numbers refer to Figure 1 . -.
Gaseous Discharge Streams
Low/medium-Btu gas (Stream No. 10)
Slurry preparation vent gas (Stream No. 9)
Slag lock gas (Stream No. 7 )
Liquid Discharge Streams
Process condensate and gas quenching liquor (Stream No. 11)
Slag slurry (Stream No. 4)
A-138
-------
Solid Discharge Streams
Slag slurry (Stream No. 4)
The following text discusses the compositions of these discharge
streams, using as a basis the INPUT STREAM data given above, and
the following gasifier conditions:
Coal type:
Gasifier pressure:
MPa (peia)
Steam/Os (kg/kg):
Steam/air (kg/kg):
Gas outlet
temperature:
Gas production rate:
Nm3/kg coal (scf/lb coal)
Western Kentucky
#11 Bituminous
8.07 (1170)
0.82
Not applicable
1200
(1700)
2.33
(39.5)
Illinois #6
Bituminous
3.14 (455)
Not applicable
0.18
1255
(1800)
4.56
(77.3)
Low/Medium-Btu Gas (Stream No. 10) - The composition of the
low/medium-Btu gas from the Bi-Gas gasifier will be depen-
dent on the composition of the coal feed, the composition
and amount of transport gas, the gasifier operating condi-
tions, and the gas cooling operations applied to the raw
?as stream. The compositions given below list the components
n the raw gas (Stream No. 5) for bituminous coal feedstock
with air- and oxygen-blown operation. Because this gas
stream may contain significant amounts of H2S, organic sul-
fur compounds, C02, and water, further treatment may be
required prior to utilization of the gas. Processes that
can be used to remove these contaminants are described in
the acid gas removal section.
A-139
-------
Coal type
Western Kentucky Illinois ?fo
Component
UBi£uminous
Bituminous
voo»L
CO
H2
C02
N2 + Ar
02
H2S
COS + CS2
Her cap tans
Thiophenes
S02
H20
Naphthas
Tar
Tar Oil
Crude Phenols
NH3
HCN
Particulates (coal fines, a«h)
Trace Elements
HHV (Dry basis): J/Nm3
(Btu/scf)
Gasification media
40.6
22.5
14.3
ND
ND
12.9
0.6
ND
1.3
PR
ND
ND
ND
7.7
NP
NP
NP
ND
PR
ND
PR
Pit
1.30 x107
(350)
Steam/02
1
1
18.
13.
3.6
ND
ND
8.3
45.8
ND
0.5
0.1
ND
ND
10.2
NP
NP
NP
ND
0.4
ND
PR
PR
5.29 x 106
(142)
Steam/Air
ND = Presence of component not determined.
PR = Component is probably present, amount not determined.
NP = Component is probably not present.
Component volume % is given on a relative basis to all other
components that have a value for volume % listed.
Slurry Preparation Vent Gas (Stream No. 9) - This gaseous
discharge stream will be composed of water and fine coal
particles which become airborne due to agitation of the
slurry in the preparation tank. Any volatile components in
the water used to prepare the slurry (Stream No. 8) may
also be present in the vent gas stream. The coal fines in
this stream can be removed with filters, cyclones, or
scrubbers. If any volatile components are present in this
A-140
-------
stream, they can be controlled by incineration of the
stream in a flare or boiler.
Slag Lock Gas (Stream No. 7) - This gaseous discharge
stream is created when the slag lock is depressurized in
order to discharge the accumulated slag. This stream may
contain any of the components in the raw gas (Stream No. 5)
which dissolve in the quench water, plus any volatile
components in the slag quench water (Stream No. 13), plus
entrained slag particles. Depending on the composition of
the slag lock gas, it may be first passed through a cyclone
to remove particulates and then vented to the atmosphere
or it may be incinerated in a flare or boiler.
Process Condensate and Gas Quenching Liquor (Stream No. 11) -
This liquid stream is composed of the raw gas scrubbing liquor
plus raw gas condensate from the scrubbing cooler. This
stream will be composed of water plus the constituents of
the raw gas (Stream No. 5) which condense or dissolve in
the quench water. The components most likely to be present
in this stream are:
H20 • Organic sulfur compounds
Particulates • Thiocyanates
(char fines, ash) • HCN
NH3 • Trace elements
• H2S
The amounts of these components will be dependent on the
raw gas composition and the gas quenching and cooling
processes used. Processes that can be used to remove these
contaminants are described in the water pollution control
section.
Slag Slurry (Stream No. 4) - This stream will contain
liquid and solid components. The liquid in this stream
will be composed of the slag quench water (Stream No. 13)
plus any components from the raw gas in the gasifier which
dissolve in the quench water. The solids in this stream
will be slag particles which consist of the mineral matter
present in the feed coal with a small amount of unreacted
carbon. The exact composition of the slag is dependent on
the composition of the feed coal and the gasifier operating
conditions. Processes described in the suspended solids
removal section can be used to dewater the slag slurry,
The recovered water could be recycled to the process con-
densate and gas quenching liquor (Stream No. 11). The
dewatered slag or slag slurry is a solid waste product
which requires ultimate disposal. Methods that can be used
for slag slurry disposal are described in the solid waste
treatment section.
A-141
-------
REFERENCES NOT CITED
L-98 American Gas Association, Proceedings of the Fifth
Synthetic Pipeline Gas Symposium. Chicago. TL, October
1573. Washington. DC. im.
L-227 Bituminous Coal Research, Inc. , Gas Generator Research
and Development , Bi-Gas Process, Annual Report, June
1974 - June 1975. Report No. FE-1207-1, ERDA Contract
No. E(49-18)-1207. Monroeville, PA, August 1975.
L-245 Bodle, W. W. , and K. C. Vyas, "Clean Fuels from Coal -
Introduction to Modern Processes", in Clean Fuels From
Coal, Symposium Papers, Chicago, IL, September 1973.
Chicago, IL, Inst. of Gas Technology, December 1973.
L-613 Grace, R. J., and E. K. Diehl, "Environmental Aspects
of the Bi-Gas Process", in Symposium Proceedings: En-
vironmental Aspects of FuelConversion Technology, St.
Louis, MO, May 197ZT Report No. EPA-650/2-74-118, EPA
Contract No. 68-02-1325, Task 6. Research Triangle
Park, NC, Research Triangle Inst., EPA, October 1974.
(pp. 131-34).
L-693 Institute of Gas Technology, Clean Fuels From Coal,
Symposium Papers, Chicago, IL, 10-14 September 1973.
Chicago, IL, December 1973.
L-706 Jahnig, C. E. , Evaluation of Pollution Control in Fossil
Fuel Conversion ProcessesT Gasification, Section 5;
Bi-Gas Process. Final Report. Report No. PB-243 694,
EPA-650/2-74-009g, EPA Contract No. 68-02-0629. Linden,
NY, Exxon Research & Engineering Co., May 1975.
L-1256 Grace, R. J., R. A. Glenn and R. L. Zahradnik, "Gasi-
fication of Lignite by BCR Two-Stage Super-Pressure
Process", Ind. Eng. Chem. , Process Des . Develop. 11(1),
95-102 (1972T: - —
L-1635 American Gas Association, Proceedings of the Sixth
Synthetic Pipeline Gas Symposium, Chicago. IL. October
1974. Washington, DC. 1374 - - - ' -
L-1915 Glenn, R. A., "Status of the BCR Two-Stage Super-
Pressure Process", Presented at the Third Synthetic
Pipeline Gas Symposium, Chicago, IL, 17-18 November
1970.
A-142
-------
L-1920 Grace, R. J. and R. L. Zahradnik, "Bi-Gas Program
Enters Pilot Plant Stage", Presented at the Fourth
Synthetic Pipeline Gas Symposium, Chicago, IL,
30-31 October 1972.
L-5449 Bituminous Coal Research, Inc., Gas Generator Research
and Development - Bi-Gas Process"! Report No. FE-1207-9,
ERDA Contract No. E(49-18)-1207. Monroeville, PA,
January 1976.
L-8584 American Gas Association, Proceedings of the Fourth
Synthetic Pipeline Gas Symposium. Chicago. IL, 30-31
October WTT. Arlington, VA, 1972.
L-9092 Miles, John M. , "Status of the Bi-Gas Program. Part I.
Pilot Plant Activities", Presented at the Eighth
Synthetic Pipeline Gas Symposium, Chicago, IL, 18-20
October 1976.
A-143
-------
COAL GASIFICATION OPERATION GASIFICATION MODULE
ENTRAINED-BED GASIFIERS
Texaco Gaslfier
GENERAL INFORMATION
Process Function - High-pressure coal gasification in an
entrained bed by injection of oxygen or air and coal plus
steam with co-current gas/solid flow.
De ve 1opmen t S ta tug - Pilot plant.
Licensor/Developer - Texaco Development Corporation
135 East 42nd Street
New York, New York 10017
Commercial Applications - A gasifier of similar design was
operated from 1956 to 1958 by Olin Mathieson Co. at Morgan-
town, West Virginia to produce synthesis gas.
Applicability to Coal Gasification - The gasifier has been
operated successfully with lignite and bituminous coals.
Operation with air instead of oxygen has not been demonstrated.
The pilot plant is located at Texaco's Montebello Research
Laboratory at Montebello, California.
PROCESS INFORMATION
Equipment (149, 150, 151) -
Gasifier construction: vertical, cylindrical steel
pressure vessel with refractory lining.
Gasifier dimensions: (Projected commercial-size gasifier)
- 2.7 meters (9 ft.) outside shell diameter
- 4.6 meters (15 ft.) approximate overall height
Bed type and gas flow: Entrained bed; continuous co-^
current downward gas flow; lateral gas outlet near the
middle of the gasifier, at the top of the slag quench
chamber.
A-144
-------
Heat transfer and cooling mechanism: Direct gas/solid
heat transfer; water jacket at the top of the gasifier
provides cooling of the burner section.
Coal feeding mechanism: Continuous injection of a slurry
of pulverized coal and water at the top of the gasifier.
Gasification media introduction: Continuous injection of
pre-heated oxygen or air at the top of the gasifier.
Ash removal mechanism: A slurry of slag and water is
pumped out of the slag quench chamber.
Special features:
Gas quenching and cooling and slag removal are
accomplished simultaneously in the slag quench
chamber.
Slurry feeding mechanism eliminates any moisture
content restrictions for coal feed.
Flow Diagram - See Figure 1.
Operating Parameter Ranges (Refs. 152, 153, 154, 155, 156) -
• Gas outlet temperature: 478 to 533°K (400 to 500°F)
• Maximum coal bed temperature: 1256 to 2089°K (1800 to
3300°F)
• Gasifier pressure: 1.48 to 8.38 MPa (215 to 1215 psia)
Coal residence time in gasifier: Several seconds.
Normal Operating Parameters (Refs. 157, 158) -
• Gas outlet temperature: 478°K (400°F)
• Maximum coal bed temperature: 1533°K (2300°F)
• Gasifier pressure: 2.5 MPa (365 psia)
Coal residence time in gasifier: Several seconds.
-•%
Raw Material Requirements (Refs. 159, 160, 161) -
Coal feedstock requirements:
- Type: lignite, bituminous
A-145
-------
VENT
COAL GAS WATER FLUE GAS
STEAM
AIR
FUEL i <^
QUENCH WATER
LOW/MEDIUM
BTU GAS
<^ »- CONDENSATE
ASH & WATER
Figure 1. Texaco Gasifier
-------
- Size: 70% less than 0.074 ram (0.003 in)
- Rate: %410 g/sec-m2 (300 lb/hr-ft2)
- Pretreatment required: crushing, pulverizing, slurry
preparation.
Steam requirements: 0.1 to 0.6 kg/kg coal
Oxygen requirements: 0.6 to 0.9 kg/kg coal
Air requirements: Data not available.
Quench water make-up requirements: Data not available.
Utility Requirements - Data not available.
Process Efficiency - Basis: oxygen-blown operation; quenched
and cooled product gas; reference temperature = 300°K (80°F)
• Cold gas efficiency: 77%
[ = ] [Product gas energy output] -, nn
[Coal energy Input]x iuu
Overall thermal efficiency: data not available.
[= 1 [Total energy output (product gas + HC by-products + 8team)]
[Total energy input (coal + electric power)]
Expected Turndown Radio (Ref. 162) - 100/15
[=] [Full capacity output]
[Minimum sustainable output]
Gas Production Rate - Data not available
PROCESS ADVANTAGES
Coal type: Gasifier can accept all types of coal
feedstocks.
Gasification media: Gasifier can be operated with air
or oxygen.
By-products produced: No by-products which require
additional processing are produced.
A-147
-------
Environmental considerations: The absence of tars, oils
naphthas and phenols in the raw gas simplifies control
technology requirements.
Operating pressure: Pressurized operation will be an
advantage for gas transmission by pipeline and utilization
as a synthesis gas or combined-cycle fuel.
Feed mechanism:
without drying.
Slurry feeding allows use of any coal
Feed size: Gasifier used pulverized fuel, which eliminates
rejection of fine coal particles.
PROCESS LIMITATIONS
Gasification media: Pressurized operation with air has
not been commercially demonstrated.
Process efficiency: High temperature of exit gases and
slurry requires heat recovery in order to maintain
satisfactory thermal efficiency.
Ash carryover: Large amounts of high-temperature slag
in the raw product gas may cause operation problems in
the waste heat boiler.
INPUT STREAMS (Refs. 163, 164) -
Coal (Stream No. 1)
- Type:
- Size: mm (in)
- Rate:
Illinois #6 High
Volatile C
Bituminous
70% <0.074
(,003)
Illinois #6 High
Volatile C
Bituminous
70% < .074
(.003)
Data not available Data not available
- Composition:
- HHV: (dry)
J/kg (Btu/lb)
Data not available Data not available
3.02 x 107 Data not available
(13,000)
A-148
-------
- Swelling number: Data not available Data not available
- Caking index: Data not available Data not available
• Steam: (Stream No. 2):
kg/kg coal MD.15 M).15
• Oxygen (Stream No. 3): ^0.75 Not applicable
• Air (Stream No. 3): Not applicable Data not available
DISCHARGE STREAMS AND THEIR CONTROL
The Texaco gasifier will produce the following discharge
streams. Stream numbers refer to Figure 1.
Gaseous Discharge Streams -
Low/mediurn-Btu gas (Stream No. 14)
Slurry preparation vent gas (Stream No. 6)
Slurry steam purge (Stream No. 7)
Preheater flue gases (Stream No. 8)
Liquid Discharge Streams -
Process condensate and gas quenching liquor (Stream No. 12)
Solid Discharge Streams -
Slag slurry (Stream No. 4)
The following text discussed the compositons of these discharge
streams, using as a basis the INPUT STREAM data given above and
the following gasifier conditions:
• Coal type: High Volatile Data not available
C Bituminous
• Gasifier pressure: 2.5 (365) 1.55 (225)
MPa (psla)
• Steam/Oj (kg/kg): 0.2 Data not available
• Steam/Air (kg/kg): Not applicable Data not available
A-149
-------
• Gas outlet temperature 506 (450) Data not available
°K (°F):
• Gas production rate: Data not available Data not available
NmVkg coal (scf/lb
coal)
Low/Medium-Btu Gas (Stream No. 14) - The composition of the
low/medium-Btu gas from the Texaco gasifier will be dependent
on the composition of the coal feed, gasifier operating
conditions, and the gas cooling operations applied to the
raw gas stream. The compositions given below lis.t the
components in the raw gas (Stream No. 5) for oxygen- and
air-blown operation. Because this gas stream contains
significant amounts of H2S, organic sulfur compounds, C02 ,
and water, further treatment may be required prior to utili-
zation of the gas. Processes that can be used to remove
these contaminants are described in the acid gas removal
section.
Coal Type
High Volatile Data Not
C Bituminous Available
Component Component Vol % Component Vol %
CO 37.6 27.5
H2 39.0 25.3
OH* 0.5 0.5
CjjHn ND ND
C2H6 ND ND
C02 20.8 1.0
N2 + Ar 0.6 37.2
02 NP ND
H2S 1.5 ND
COS + CS2 ND ND
Mercaptans ND ND
Thiophenes ND ND
S02 ND ND
H20 PR 8.5
Naphthas ND ND
Tar NP NP
Tar Oil NP NP
Crude Phenols ND ND
NH3 ND ND
HCN ND ND
Particulates (coal fines, ash) PR PR
Trace Elements PR PR
A-150
-------
HHV (Dry basis) 9.4 x 106 6.52 x 106
Joule/Nm3 (Btu/scf) (253) (175)
Gasification Media: Steam/02 Steam/Air
ND * presence of component not determined
PR » component is probably present, amount not determined
NP = component probably not present
Component volume % is given on a relative basis to all other components
that have a value for volume % listed.
Slurry Preparation Vent Gas (Stream No. 6) - This gaseous
discharge stream will be composed of water and fine coal
particles which become airborne due to the agitation of the
slurry in the preparation tank. Any volatile components in
the water used to prepare the slurry (Stream No. 2) may
also be present in the vent gas stream. The coal fines in
this stream can be removed with filters, cyclones, or scrub-
bers. If any hazardous volatile components are present in
this stream, they can be controlled by incineration of the
stream in a flare or in the preheater furnaces.
Slurry Steam Purge (Stream No. 7) - This gaseous discharge
stream is composed, of steam plus entrained coal fines. This
stream is the off-gas from the cyclone which is used to
adjust the steam/coal ratio in the slurry feed to the gasi-
fier. Since the slurry is heated to 533°K (500°F) upstream
of the cyclone, this stream may also contain some of the
volatile matter in the coal feed or in the slurry preparation
water (Stream No. 2). A potential control technology for this
stream would be to recycle it to the coal slurry preparation.
If this stream were to be discharged to the atmosphere in-
stead of being recycled, the coal fines could be removed
with filters, cyclones, or scrubbers.
Preheater Flue Gases (Stream No. 8) - This gaseous discharge
stream is composed o,f the combustion products from the direct-
fired coal slurry and oxygen or air preheaters. The composi-
tion of this stream will be dependent on the composition
of the fuel (Stream No. 10) and the operating conditions in
the preheaters. The components most likely to be present in
this stream are:
A-151
-------
• C02
• H20
• CO
* SOX
• NOX
If the fuel used is coal, this stream may also contain fly
ash particles. The process that can be used to remove these
contaminants are described in the air pollution control
section.
Process Condensate and Gas Quenching Liquor (Stream No. 12)
This liquid stream will be composed of the ash quench water
plus the raw gas scrubbing liquor, plus raw gas condensate
from the waste heat boiler. Slag particles which are re-
moved from the raw gas in the gasifier quench section, the
waste heat boiler, and the raw gas scrubber are separated
from the process condensate and gas quenching liquor in a
settler. Some slag particles may be carried along in the
process condensate stream. The other components in this
stream will be the constituents of the raw gas in the gasi-
'fier which condense or dissolve in the quench liquor plus
any components present in the quench water makeup (Stream
Nos. 11 & 13). The components most likely to be present
in this stream are:
• H20
Particulates (coal fines, slag)
• NH3
• H2S
Trace elements
Most of this stream will probably be recycled to the slag
quench or raw gas scrubber, with a small blowdown discharge
stream. The process that can be used to remove the contami-
nants in this stream are described in the water pollution
control section.
Slag Slurry (Stream No. 4) - This stream contains the slag
which is separated from the process condensate and gas
quenching liquor (Stream No. 12) in the settler. The slag
particles will consist of the mineral matter present in the
feed coal with approximately 2% unreacted carbon. The slag
slurry may also contain any of the components present in
the raw gas (Stream No. 5) or in the process condensate
and gas quenching liquor (Stream No. 11). The suspended
solids removal processes described in Appendix D can be
used to dewater the slag slurry. The recovered water could
A-152
-------
be recycled to the process condensate and gas quenching
liquor (Stream No. 12). The dewatered slag or slag slurry
is a solid waste product which requires ultimate disposal.
Processes that can be used for slag slurry disposal are
described in the solid waste treatment section.
A-153
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COAL GASIFICATION OPERATION GASIFICATION MODULE
ENTRAINED-BED GASIFIERS
Coalex Gasifier
GENERAL INFORMATION
Proces s Funct ion - Atmospheric pressure, slagging ash coal
gasi£icat:ion in an entrained bed by injection of air plus
a solid additive with co-current gas/solid flow.
Development Status - Pilot plant since 1976.
Licensor/Developer - Inex Resources, Inc.
7475 W. Fifth Ave.
Lakewood, Colorado 80226
Commercial Applications - None; one commercial scale
(60 x 106 Btu/hr) producer is being designed for a sugar
beet manufacturer.
Applicability to Coal Gasification - The gasifier has been
operated successfully with various types of coal feedstocks.
The Coalex pilot plant (2.5 x 106 Btu/hr) is located at the
Inex Resources Test Facility in Wheat Ridge, Colorado. The
cost of producing a 150 Btu/scf product gas with this
system is estimated by Inex to be approximately $2.50 per
106 Btu.
PROCESS INFORMATION
Equipment -
Gasifier construction: vertical, cylindrical steel
vessel.
Gasifier dimensions: data not available.
Bed type and gas flow: entrained - bed, continuous
co-current gas flow; vertical gas outlet through the
top of the gasifier.
Heat transfer and cooling mechanism: direct gas/solid
heat transfer; specific cooling technique used is the
steam generated from the ash quench.
A-154
-------
Coal feeding mechanism: continuous injection of
pulverized coal entrained in air at the top of the
gasifier.
Gasification media introduction: continuous injection
of air with suspended coal and additive particles at
the top of the gasifier. Steam is generated by vaporizing
water from the ash quench tank.
Ash removal mechanism: slag quench tank and slurry pump
at the bottom of the gasifier.
Special features:
Chemical additive removes sulfur compounds from the
product gas. Sulfur removal ranges between 89 to
99+% have been achieved (Ref. 165).
Chemical additive reduces the ash fusion temperature
thereby, allowing the ash to be removed as slag.
A precombustion chamber is required to preheat the
coal/air/additive feed before it enters the reactor.
Flow Diagram - See Figure 1.
Operating Parameter Ranges -
• Gas outlet temperature: 1200 to 1220°K (1700 to 1740°F)
Maximum coal bed temperature: Approximately 1370°K
(2000°F).
Gasifier pressure: Atmospheric.
Coal residence time in gasifier: Data not available.
Normal Operating Parameters -
• Gas outlet temperature: 1200 to 1220°K (1700 to 1740°F)
Maximum coal bed temperature: Approximately 1370°K
(2000"F), depending on the ash fusion temperature of the
feed coal.
Gasifier pressure: Atmospheric.
Coal residence time in gasifier: Data not available.
A-155
-------
PULVERIZED COAL
VENT GAS
Ul
AIR
ADDITIVE
REACTOR
HOT
SLAG QUENCH
LOW MEDIUM BTU-GAS
QUENCH WATER
MAKEUP
SLAG SLURRY
Figure 1. Coalex Gasifier
-------
Raw Material Requirements -
Coal feedstock requirements:
Type: All types (lignite has not yet been tested in
the pilot plant).
- Size: Less than 0.07 mm (0.003 in)
Rate: Data not available.
Pretreatment required: Crushing and pulverizing.
Additive requirements: Depends upon the sulfur content
of the coal and the ash fusion temperature.
Steam requirements: Steam is generated by vaporizing
the water in the slag quench tank.
Oxygen requirements: Not applicable.
Air requirements: 2.7 to 6.1 kg/kg coal
Ash quench water make-up requirements: Data not available.
Utility Requirements - Data not available.
Process Efficiency -
Basis: Pilot plant data on several unreported coal
types.
• Overall thermal efficiency: 88 to 93%
[ = ] [Energy output with (product gas 4- HC by-products + steam) 1 y -i nn
[Energy input with (coal + electric power)]
Expected Turndown Ratio - Data not available.
Gas Production Rate - Gasifier can be designed to produce
between 20 x lOs and 250 x 10s Btu/hr of low-Btu gas.
PROCESS ADVANTAGES
Coal type: gasifier can accept all types of coals.
Environmental considerations: the absence of tars and
oils in the raw gas simplifies control technology
A-15 7
-------
- HHV: Joule/kg 2.7 x 107
(Btu/lb) (11,877)
Swelling number: Data not available
Caking index: Data not available
Steam Data not available
Oxygen Not applicable
• Air (Stream No. 3) 6.1 kg/kg coal
Additive (Stream No. 2) Data not available
DISCHARGE STREAMS AND THEIR CONTROL
The Coalex Gasifier will produce the following discharge
streams. Stream numbers refer to Figure 1.
Gaseous Discharge Streams
Low-Btu gas (Stream No. 5)
Additive hopper vent gas (Stream No. 6)
Liquid Discharge Streams
Slag slurry (Stream No. 4)
Solid Discharge Streams
Slag slurry (Stream No. 4)
The following text discusses the compositions of these discharge
streams, using the basis given above as INPUT STREAMS, and the
following gasifier conditions:
Coal type: Data not available
Gasifier pressure: Atmospheric
Steam/0?: (kg/kg) Data not available
Steam/air: (kg/kg) Data not available
A-159
-------
Gas outlet temperature
Gas production rate:
Nm3/kg coal
(scf/lb coal)
1210
(1710)
Data not available
Low-Btu Gas (Stream No. 5) - The composition of the low-Btu
gas from the Coalex Gasifier will be dependent on the
composition of the coal and additive feeds, and gasifier
operating conditions. The composition given below lists the
components present in the raw gas (Stream No. 5) for a
typical coal feedstock. Because this gas stream may contain
significant amounts of H2S, organic sulfur compound, COa,
and water, further treatment may be required prior to utili-
zation of the gas. The acid gas removal processes that can
be used to remove those contaminants are described in
Appendix B.
Component
CO
H2
C2HS
CO 2
N2 + Ar
02
H2S
COS + CS2
Mercaptans
Thiophenes
S02
H?0
Naphthas
Tar
Tar Oil
Crude Phenols
NH*
HCN
Particulatew (coal fines, ash)
Trace elements
HHV (Dry basis):
J/Nm3 (Btu/scf)
Gasification media
Component Vol%
20.7
10.8
0.5
ND
ND
4.4
62.8
0.8
PR
PR
ND
ND
PR
PR
ND
ND
ND
ND
PR
PR
PR
PR
4.9 X 106
(133)
Air plus additive
A-160
-------
ND = presence of component not determined
PR = component is probably present, amount not determined
NP « component is probably not present
Component volume % is given on a relative basis to all other components
that have a value for volume % listed.
Additive Hopper Vent Gas (Stream No. 6) - This stream may
contain entrained particles of additives and coal. However,
the additive feed hopper is normally closed during gasifier
operation; therefore, emissions from this source should be
minimal.
Slag Slurry (Stream No. 4) - This stream contains the slag
which is removed from the gasifier by means of an internal
quench bath. The slag particles will consist of the mineral
matter present in the feed coal, some unreacted carbon and
additive, and compounds formed by reactions of the chemical
additive and raw gas constituents. The liquid portion of
this stream will contain any components present in the
quench water make-up (Stream No. 7) and possibly dissolved
gases. The suspended solids removal processes described in
Appendix D can be used to dewater the slag slurry and the
recovered water could be recycled to the quench water
make-up stream. The dewatered slag or slag slurry is a
solid waste which requires ultimate disposal. The solid
waste treatment processes that can be used for slag slurry
disposal are described in Appendix E.
A-161
-------
APPENDIX B
GAS PURIFICATION OPERATION
-------
GAS PURIFICATION OPERATION LOW-TEMPERATURE
ACID GAS REMOVAL
Rectisol I Process
GENERAL INFORMATION
Process Function - Physical absorption of acid gases (C02,
H2S, COS, CS2, mercaptans, etc.) using methanol as a sorbent
Development Status - Commercially available.
Licensor/Developer - Lurgi Mineraloltechnik GmbH
American Lurgi Corporation
377 Rt. 17 South
Hasbrouck Heights, New Jersey
Commercial Applications -
Purification of low/medium-Btu gas produced in coal
gasification plants
Carbon dioxide removal and drying for ammonia synthesis
gas
Carbon dioxide removal from a low-temperature fraction-
action unit feed gas
Carbon dioxide and water removal from a feed gas to an
LNG plant
Applicability to Coal Gasification - The Rectisol I process
is a proven acid gas removal process for low/medium-Btu gas
produced in gasification plants in the following locations:
Sasolburg, South Africa
• Westfield, Scotland
Pristina, Yugoslavia
B-2
-------
PROCESS INFORMATION
Equipment - Absorbers, flash towers, distillation columns
Flow Diagram - See Figure 1.
Control Effectiveness - Product gas concentrations of less
than 1 ppmv of sulfur and C02
Operating Parameter Ranges - 210 to 240°K (-30 to -80°F);
2.07 to 6.89 MPa (300 to 1000 psia)
Normal Operating Parameters - 230°K (-50°F); 294 MPa
(425 psia)
Raw Material Requirements - 2.4 gmole/sec': (19.2' Ibmole/hr)
of makeup metHanoi solvent based on 9480 gmole/sec (75,180
Ibmole/hr) product medium-Btu gas (440 Btu/scf)
Utility Requirements - Based on 9480 gmole/sec (75,180 Ibmole/
hr) of medium-Btu (440 Btu/scf) product gas.
. Cooling = 124 MJ/sec (422 x 106 Btu/hr)
. Steam (sat'd, 100 psig) = 97 MT/hr (107 short tons/hr)
. Steam (750°F, 550 psig) = 103 MT/hr (113 short tona/hr)
Electricity (including refrigeration) = 9550 kW
PROCESS ADVANTAGES
Solvent - Good selectivity between acid gases and product
_gases (see Figure 2)
- Low freezing point
- Chemical stability
- Unlimited solubility in water
- Inexpensive
Process^ - Proven acid gas removal process
- Operates at high pressures
- Product gas having less than 1 ppmv sulfur and
CO2 can be produced
B-3
-------
Cd
I
-O
COOIEO
GAS
WATER
PRODUCT GAS EXPANSION GAS
PREWASH
FLASH
NAPHTHA
SEPARATOR
fCOOlJMG
|A2EOTHOPE
COLUMN
ABSORBER
d
FLASH
REGEK-
ERATOR
RICH H2S GAS
METUAWOS.
WATER
STILL
HOT
REGEN-
ERATOR
COOLINQ
WATER
STEAM
MAKEUP
METHANCL
PROCESS
COHDEHSATE
Figure 1. Typical flow diagram - Rectisol acid gas removal process
-------
PROCESS LIMITATIONS
Solvent - Retains heavy hydrocarbons (Ca ) (see Figure 2)
- Solvent losses may be high and create problems in
subsequent sulfur recovery processes
Process - High utility requirements for refrigeration
- Does not selectively remove H2&/C02 which
will limit its use in combined-cycle systems
- Operates at high pressures which may limit its
use with atmospheric pressure gasifiers
INLET GAS STREAM
Typical Flow - 13,500 gmole/sec (106,800 Ibmole/hr) from
24 oxygen-blown Lurgi gasifiers
Typical Composition -
Component Vol %
CO 2
CO
CM*
H2S
COS
DISCHARGE STREAMS
Component
27.9
20.2
11.1
0.4
N2+Ar
H2
Naphtha
Vol %
1.0
0.3
38.9
0.2
The Rectisol I process has both gaseous and liquid discharge
streams. These discharge streams are:
' Gas
- Product gas (Stream No. 2)
- Lean H2S flash gas (Stream No. 4)
- Rich H2S gas (Stream No. 5)
- Expansion gas (Stream No. 6)
• Liquid
- Process condensate (Stream No. 7)
- Naphtha (Stream No. 3)
The following text discusses the compositions of these streams,
using the Inlet Gas Stream composition given above as a basis.
B-5
-------
10* I
o>
Naphtha
. * -.-« —
« .-.«— J —
I •
£ 10''
*•* -100 -90 -80 -70 -60 -50 -40 -30
Hethanol Temperature (9F)
Figure 2. Published Lurgi data on the solubility of gases in
methanol at a gas partial pressure of 1 atm (Refj 166)
B-6
-------
Product Gas - The product gas exiting the Rectisol I process
Is mainly comprised of CO, H2, CHi,, C2H4, and C2H6. Small
amounts of C02, H2S, COS, and organic sulfur will also be
present in this stream. The amounts of these components
will vary depending on the product gas specifications, A
typical product gas composition is as follows: ....,.._,
Component
CO 2
H2S
CO
Vol %
3.1
trace
0.5
16.9
Component
H2
Vol
C2H6
N2+Ar
63.5
14.9
0.7
0.4
Lean H2S Flash Gas - The lean H2S flash gas is the combined
flash gases from the pr.ewash flasih and the main flash
regenerator. These gases are mainly comprised of C02 with
small amounts of CO, H2, CHi>, C2Hif , C2H6 , H2S, COS, and
other organic sulfur compounds. The amounts of these minor
gases depend on the inlet gas composition and the main
absorber operating parameters such as temperature, pressure,
and methanol flow rate. A typical composition of the lean
HaS flash gas is shown below:
Component
CO 2
H2S
C2Hi|
CO
Vol 7,
97.5
0.8
0.2
0.2
Component
H2
CH4
N2+Ar
Vol %
0.4
0.6
0.3
trace
Rich H2S Gas - The off-gases from the hot regenerator are
comprised primarily of COa, CO, H2, CH\ , H2S, COS, and other
organic sulfur compounds. This stream may also contain
substantial amounts of methanol, depending upon the overhead
temperature and pressure of the hot regenerator. The effect
of these parameters on the mole fraction of methanpl in this
gas stream is illustrated in Figure 3. A typical overhead
hot regenerator gas coa$>osition is shown below:
Component
CO 2
H2S
CO
COS
Vol %
78.8
12.6
trace
trace
trace
Component
H2
OK
C2He
N2+Ar
Methanol
Vol
trace
trace
trace
trace
8.6
Further treatment of this stream is necessary because of
the high concentrations of H2S and methanol.
B-7
-------
1.0
3
V)
CM
u
•f—
Oi
o
u
-------
Expansion Gas - The gases released during the first stage
o£ tlash regeneration are comprised of COg, CO, CH^ CalU,
CzHe, H2, and N2 and Ar7 with trace amounts of HYS,*
COS, and other organic sulfur compounds. The amount of
each of these constituents in the expansion gas depends
upon the flash pressure and the concentration of each
component in the methanpl feed to the flash regenerator,.
A typical composition of the expansion gas stream is shown
below:
Component Vol % Component Vol %
C02 31.1 CO 12.6
H2S trace H2 18.6
C2IU 1.6 cm 33.4
C2H6 2.4 N2+Ar 0.3
COS , trace
Since this gas stream contains such hj.j;h concentrllrfoliis pf__
desirable gases, it is normally combined with product gages
exiting the Rectisol I process.
Process Gondensate - The bottoms stream from the metbaaol/
water still consists primarily of water with trace amounts
of phenols, cyanides, ammonia, sulfides, and hydrocarbons
such as naphthas and methanol. This water, which ultimate-
ly ends up as process condensate blowdown, comes from the
water absorbed by the methanol from the inlet gas and the
water added to the naphtha/methanol separator. A typical
composition of the contaminants in this effluent stream is
shown below (Ref. 167):
Component ppm (weight)
Phenol 18
Cyanide (as CN) 10.4 (includes thiocyanate)
Ammonia (as N) 42
Sulfides (as S) trace
Because of these contaminants, this effluent stream must be
treated before discharge.
B-9
-------
Naphtha By-Product - The by-product naphtha stream consists
mainly of C6 to Ce (predominantly aromatic) hydrocarbons
removed in the prewash column. Some of the major and minor
compounds which are expected to be in this stream are listed
below t&ef. 168):
Major Components (>10% each) Minor Components (<10% each)
Paraffins and Olefins Thiophenes
Benzene Styrene
Toluene Ethyl Toluene
Xylenes - Ethyl Benzene Indane
Trimethyl Benzenes Indene
Naphthalene
Benzofutan
Fugitive Emissions - Fugitive air and liquid emissions from
the Rectisol I acid gas removal process arise from leaks
around pump seals, valves, flanges, etc. High pressures
like those encountered in this process enhance fugitive
leaks from equipment. These fugitive emissions could con-
tain any of the various components found in the process
streams.
DISCHARGE STREAMS AND THEIR CONTROL
The following discharge streams from the Rectisol I process
require further treatment:
Lean HzS flash gas
. Rich HZS gas
Process condensate
The following text discusses why further treatment is necessary
and the types of control devices that can be used to treat these
streams.
Lean H,S Flash Gas - Since this gas stream contains signifi-
cant amounts o£J HzS, organic sulfur, and hydrocarbons, it
needs to be treated before it is discharged to the atmosphere,
The control technologies that can be used to control these
sulfur emissions include a Stretford process and/or a tail
gas treating process (Beavon, SCOT, etc.). Incineration
can be used to control the hydrocarbon emissions. Data
sheets for these control processes are presented in Appendix
C.
B-10
-------
Rich Hj>S Gas - The off-gases from the hot regenerator con-
tain HaS, organic sulfur compounds, methanol, and other
hydrocarbons. Techniques that can be used to control these
sulfur emissions include a Glaus process followed by a Strat-
ford and/or a tail gas treating process. Hydrocarbons can
be controlled by incineration. The presence of hydrocarbons,
including methanol, can result in lower H2S removal efficien-
cies in the Glaus process due to the formation of organic
sulfur compounds. These compounds must then be treated by
a tail gas treating process. Data sheets for the Glaus,
Stretford, and tail gas treating processes are presented in
Appendix C.
Process Condensate - Expected contaminants in the process
condensate stream include phenols, cyanides, ammonia, hydro-
carbons, sulfides, etc. This stream requires treatment to
reduce the concentrations of these components before it can
be recycled or disposed of. The wastewater treatment pro-
cesses which can be used to treat this stream are discussed
in Appendix D.
B-ll
-------
GAS PURIFICATION OPERATION LOW-TEMPERATURE
ACID GAS REMOVAL
Selexol Process
GENERAL INFORMATION
Process Function. - Physical absorption of acid gases (H2S,
C02, COS, etc.)using Selexol solvent (polyethylene glycol
dimethyl ether).
Development Status - Commercially available.
Licensor/Developer - Allied Chemical Corporation
Gas Purification Department
P.O. Box 1013 R
Morristown, New Jersey
Commercial Applications - C02 removal from natural gas.
Applicability to Coal Gasification - Technically feasible.
PROCESS INFORMATION
Equipment - Absorbers, flash vessels, stripping columns,
Flow Diagram - See Figure 1.
Control Effectiveness - Can reduce acid gas concentrations
to 1 ppmv H2S,1 ppmv COS, 1 ppmv mercaptan, C02 to any
desired level.
Operating Parameter Ranges -
• Temperature - 265 - 310°K (20 - 100°F)
• Pressure - 3.5-6.9 MPa (500-1000 psia)
NormalOperating Parameters -
• Temperature - 277°K (40°F)
• Pressure - 6.9 MPa (1000 psia)
B-12
-------
CW
AGIO
GASES
PRODUCT GAS
ABSORBER
RAW
LOW/MED
TU GAS
REFRIGERATION
FLASH
VESSEL
SEPARATOR
STRIPPER
STEAM
,. SOLVENT
-<4>—^- SLOWDOWN
Figure 1. Typical flow diagram - Selexol Acid Gas Removal Process.
-------
Raw Material Requirements - Selexol solvent makeup - 0.23
kg/28,300 Nm3 (0.5 lb/106 scf) gas at 3.5 MPa (500 psia).
Utility Requirements - Basis: 28,300 Nm3 (106 scf) of feed
gas at 3.5 MPa (500 psia); feed gas composition of 0.5 vol 7.
H2S and 35 vol % C02. (Ref. 169)
• Steam - 1362 kg (3000 Ib)
• Cooling Water - 132 m3 (35,000 gal)
• Electrical Power - 3.2 x 109 joule (900 kWh)
PROCESS ADVANTAGES
Low solvent vapor pressure minimizes solvent loss.
Regeneration can be accomplished by flashing, inert
gas stripping and/or heat regeneration.
Relatively noncorrosive system.
PROCESS LIMITATIONS
Expensive solvent.
Absorbs heavier hydrocarbons (C3 ).
Not effective at low pressures.
Not designed to treat gas with low acid gas concentrations
INLET GAS STREAM
Typical Flow - 33 Nm'/sec (100 x 106 scf/d) of raw natural
gas (Ref. 170).
Typical Composition -
Component Vol % Component yoi %
C02 43.0 C3H8 0 1
CH4 55.7 N2 0'6
0.6 H2S 60 ppmv
B-14
-------
DISCHARGE STREAMS
The Selexol process has both gaseous and liquid discharge
streams. These discharge streams are:
• Gas
- Product gas (Stream No. 2)
- Acid gas (Stream No. 3)
• Liquid
- Slowdown solvent (Stream No. 4)
The following text discussed the compositions of these streams,
using the Inlet Gas Stream composition given above as a basis.
Product Gas - The product gas stream exiting a Selexol unit
in a natural gas plant is composed primarily of methane with
smaller amounts of C02> N2, C2H6, C3H8 and traces of H2S. The
amounts of these components will vary depending on the feed
gas composition and the process operating conditions. A
typical product gas composition is as follows:
Component Vol % Component Vol %
C02 2.8 C3H8 0.1
CEU 95.3 N2 1.0
C2H6 0.8 H2S 5.4 ppmv
Acid Gas - The acid gas stream produced during solvent
regeneration is composed primarily of C02, H2S, organic sul-
fur , and hydrocarbons. The concentrations and amounts of
each of these components will depend upon the feed gas com-
position and the process operating conditions. This stream
will require treatment to control emissions of sulfur com-
pounds and possibly hydrocarbons.
Solvent Blowdown - This stream will be composed primarily
of solvent with traces of solvent degradation products and
other components scrubbed from the process gas stream. The
disposition of this stream (further treatment to recover
solvents, incineration, etc.) will be determined by the
nature of the impurities present.
B-15
-------
GAS PURIFICATION OPERATION LOW TEMPERATURE
ACID GAS REMOVAL
Purisol Process
GENERAL INFORMATION
Process Function - Physical absorption of acid gases
C02, and organic sulfur) using N-methyl pyrrolidone as a
sorbent.
Development Status - Commercially available.
Lidensor/Developer - Lurgi Gesellschaft fur Warme und
Chemotechnik m.b.H.
American Lurgi Corporation
377 Route 17
Hasbrouck Heights, NJ
Commercial Applications -
Purification of natural gas
Purification of hydrogen-rich gas streams
Applicability to Coal Gasification - Technically feasible.
PROCESS INFORMATION
Equipment - Absorbers, stripping column, flash vessels.
Flow Diagram - See Figure 1.
Control Effectiveness - Can reduce acid gas concentrations
to 2 pptnv H2S and 10 ppmv C02.
Operating Parameter Ranges -
• Temperature - 311 - 317°K (100 - 110°F)
Normal Operating Parameters -
• Temperature: 311°K (100°F)
• Pressure: 6.9 MPa (1000 psia)
B-16
-------
M
I
PRODUCT
GAS
AW LOW/
MEDIUM
BTU GAS
ACID OASES
STEAM
SOLVENT
SLOWDOWN
Figure 1. Typical flow diagram - Purisol Acid Gas Removal Process.
-------
Raw Material Requirements - N-methyl pyrrolldone makeup -
0.95 Kg (2.1 Ib) per 28,300 Nm3 (10 scf) gas at 7.4 MPa
(1070 psia) (Ref. 171).
Utility Requirements - Basis: per 28,300 Nm3 (106 scf)
gas at 7.4 MPa (1070 psia) containing 6 vol % HzS and 15
vol % C02 (Ref. 172).
• Steam - 1418 kg (3125 Ib)
• Electricity - 9.5 x 108 joule (264 kWh)
• Cooling Water - 50 m3 (13,300 gal)
PROCESS ADVANTAGES
Low solvent vapor pressure minimizes solvent loss
Regeneration can be accomplished by flashing, inert gas
stripping and/or heat regeneration
Relatively noncorrosive system
PROCESS LIMITATIONS
Absorbs heavier hydrocarbons (C3 )
Not effective at low pressure
INLET GAS STREAM
Basis - Typically the inlet gas is high-pressure natural gas
stream with a composition such as that shown below:
Component Vol %
C02 15.0
H2S 6.0
CHH 75.0
N2 4.0
B-18
-------
DISCHARGE STREAMS
The Purisol process has both gaseous and liquid discharge
streams. These discharge streams are:
• Gas
Product gas (Stream No. 2)
- Acid gas (Stream No. 3)
• Liquid
- Solvent blowdown (Stream No. 4)
The following text discusses the compositions of these streams,
using the Inlet Gas Stream composition given above as a basis.
Product Gas - The product gas stream is composed primarily
of methane and C02 with small amounts of N2 and almost no
H2S. Typical Purisol product gas composition is as follows:
Component Vol %
C02 13.6
H2S 2 ppm
C1U 82.0
N2 4.4
Acid Gas - The acid gas stream produced during solvent
regeneration is composed primarily of C02, H2S, organic sul-
fur, and hydrocarbons. The concentrations and amounts of
each of these components will depend upon the feed gas com-
position and the process operating conditions. This stream
will require treatment to control emissions of sulfur com-
pounds and possibly hydrocarbons.
Solvent Blowdown - This stream will be composed primarily
of solvent with traces of solvent degradation products and
other components scrubbed from the process gas stream. The
disposition of this stream (further treatment to recover
solvents, incineration, etc.) will be determined by the
nature of the impurities present.
B-19
-------
GAS PURIFICATION OPERATION LOW TEMPERATURE
ACID GAS REMOVAL
Estasolvan Process
GENERAL INFORMATION
Process Function - Physical absorption of acid gases (H2S,
CO2, and organic sulfur) using tributyl phosphate as a sorbent,
Development Status - Commercially available.
Licensor/Developer - Institut Francais du Petrole
Friedrich Uhde, GmbH
Commercial Applications -
Desulfurization of natural gas
Desulfurization and liquid hydrocarbon recovery from
natural gas
Applicability to Coal Gasification - Technically feasible.
PROCESS INFORMATION
Equipment - Absorbers, flash vessels, stripping columns.
Flow Scheme - See Figure 1.
Control Effectiveness - Can reduce H2S content in product gas
to less than 3 ppmv, C02 content to less than .25 vo!70.
Operating Parameters Ranges -
• Temperature - 300°K (85°F)
• Pressure - Up to 6.9 MPa (1000 psia)
Normal Operating Parameters -
• Temperature - 300° K (85° F)
• Pressure - 6.9 MPa (1000 psia)
B-20
-------
PRODUCT ©AS
W
I
'V ACID
,3> ^- GA SE S
SOLVENT
REGENERATOR
RAW
LOW/
MEDIUM
TU GA
STEAM
SOLVENT
SLOWDOWN
Figure 1. Typical flow diagram - Estasolvan Acid Gas Removal Process.
-------
Raw Material Requirements - Tributyl phosphate solvent makeup
Utility Requirements - Basis: 28,300 Nm3 (106 scf) at
579 MPa (1000 psia) (Ref. 173).
• Steam - 1.26 kg/s (5 ton/h)
• Electricity - 1.6 x 109 joule (438 kWh)
• Cooling Water - 56 m3 (15,000 gal)
PROCESS ADVANTAGES
Low solvent vapor pressure minimizes solvent loss
Regeneration can be accomplished by flashing, inert gas
stripping and/or heat regeneration
PROCESS LIMITATIONS
Not effective at low pressures
Absorbs heavier hydrocarbons (C2+)
INLET GAS STREAMS
Typical Composition - (raw natural gas; (Ref. 174)
Component Vol %• Component Vol %
H2S 10.0 N2 7.5
COS 500 mg/Nm3 CH,, 75.5
RSH 1500 mg/Nm3 C2+ trace
C0? 7.0
DISCHARGE STREAMS
The Estasolvan process has both gaseous and liquid discharge
streams. These discharge streams are:
Gas
Product gas (Stream No. 2)
B-22
-------
- Acid gas (Stream No. 3)
• Liquid
- Solvent blowdown (Stream No. 4)
The following text discusses the compositions of these streams,
using the Inlet Gas Stream composition given above as a basis.
Product Gas - The product gas contains almost no sulfur
compounds and heavier hydrocarbons; C02 can also be re-
moved if desired. A typical Estasolvan process product
gas composition is as follows:
Component Vol *%, Component Vol %
H2S <3 ppmv N2 8.0
COS <6 mg/Nm3 CIU 85.6
RSH <50 mg/Nm3 C2+
C02 6.4
Acid Gas - This stream can be treated in a Glaus unit to
recover elemental sulfur. The tail gas from the Glaus
unit can be treated to further reduce sulfur emissions using
any one of several tail gas treating processes. A typical
acid gas stream composition is given below:
Component Vol %
H2S 85.75
COS A £C
RSH °'65
C02 11.40
CH, 2.20
Solvent Blowdown - This stream will be composed primarily of
solvent with traces of solvent degradation products and
other components scrubbed from the process gas stream. The
disposition of this stream (further treatment to recover
solvents, incineration, etc.) will be determined by the
nature of the impurities present.
B-23
-------
GAS PURIFICATION OPERATION LOW-TEMPERATURE
ACID GAS REMOVAL
Fluor Solvent Process
GENERAL INFORMATION
Process Function - Physical absorption of acid gases (H2S,
C02, and organic sulfur) using propylene carbonate as a
sorbent.
Development Status - Commercially available.
Licensor/Developer - Fluor Engineers and Constructors, Inc.
Subsidiary of Fluor Corporation
Los Angeles, California
Commercial Applications -
Seven natural gas cleanup installations.
One ammonia production installation.
Two hydrogen production installations.
Applicability to Coal Gasification - Technically feasible.
PROCESS INFORMATION
Equipment - Absorbers, flash vessels, stripping columns.
Flow Diagram - See Figure 1.
Control Effectiveness - Can reduce HsS level in product gas to
less than 4 ppmv and C02 level to less than 0.3 vol % (Ref. 175)
Operating Parameter Ranges -
Temperature - Ambient temperature or lower.
• Pressure - 5.9-6.9 MPa (850-1000 psia)
Normal Operating Parameters
• Temperature - 300°K (80°F)
• Pressure - 6.9 MPa (1000 psia)
B-24
-------
NJ
Ui
PRODUCT GAS
ACID GAS
RAW
LOW/
MEDIUM | < 1 )
BTUGAS
COMPRESSOR
ABSORBER
FLASH
VESSELS
Figure 1. Typical flow diagram - Fluor Solvent Acid Gas Removal Process.
-------
Raw Material Requirements - Propylene carbonate solvent
makeup.
Utility Requirements - Data not available.
PROCESS ADVANTAGES
Low solvent vapor pressure minimizes solvent loss.
Regeneration can be accomplished primarily by flashing.
Relatively noncorrosive system.
PROCESS LIMITATIONS
Absorbs heavier hydrocarbons (C3 ).
Primarily for treating high-pressure gases with high-H2S
concentrations.
INLET GAS STREAM
The inlet gas stream (Stream No. 1) to this process in a coal
gasification plant will contain,varying amounts of CO, C02, H2,
CH^, N2, H2S, COS, NH3, H20, C2 hydrocarbons, and perhaps other
components (e.g. trace elements).
DISCHARGE STREAMS
The Fluor Solvent process has both gaseous and liquid dis-
charge streams. These discharge streams are:
Gas
Product gas (Stream No. 2)
- Acid gas (Stream No. 3)
Liquid
- Solvent blowdown (Stream No. 4)
B-26
-------
Although no quantitative information on these streams could be
found, each of these streams is qualitatively discussed in the
following text.
Product Gas - The product gas stream will contain very small
amounts of sulfur compounds and COz. It will be composed
primarily of CO, Hz, and N2 with smaller amounts of CHi, and
H20.
Acid Gas - The acid gas stream produced during solvent
regeneration is composed primarily of C02, H2S, organic sul-
fur, and hydrocarbons. The concentrations and amounts of each
of these components will depend upon the feed gas composition
and the process operating conditions. This stream will re-
quire treatment to control emissions of sulfur compounds and
possible hydrocarbons.
Solvent Slowdown - This stream will be composed primarily
of solvent with traces of solvent degradation products
and other components scrubbed from the process gas stream.
The disposition of this stream (further treatment to recover
solvents, incineration, etc.) will be determined by the nature
of the impurities present.
B-27
-------
GAS PURIFICATION OPERATION LOW-TEMPERATURE
ACID GAS REMOVAL
MEA (Monoethanolamine) Process
GENERAL INFORMATION
Process Function - Chemical absorption of acid gases (H2S,
CO2, and organic sulfur) using MEA as a sorbent.
Development Status - Commercially available.
Licensor/Developer - Not applicable.
Commercial Applications - Widely used to remove H2S and C02
from refinery gas.
Applicability to Goal Gasification - Technically feasible.
PROCESS INFORMATION
Equipment - Absorbers, distillation columns.
Flow Diagram - See Figure 1.
Control Effectiveness - Can reduce H2S content in treated
gas to less than 1 ppmv, C02 to less than 0.1 vol%.
Operating Parameter Ranges -
• Temperature - 311 - 322°K (100 - 120°F)
Pressure - Not highly pressure sensitive.
Utility Requirements - Basis: 33 Nm3/s (100 x 106 scf/d) of
gas, composition - 90 vol % CH,» , 5 vol % CO , and 5 vol %
H2S, with 4 ppmv H2S and 0.1 vol % C02 in product gas (Ref. 176)
Steam - 144 kg/m3 solvent (1.2 Ib/gal)
PROCESS ADVANTAGES
Low solvent cost.
B-28
-------
ACID GASES
O3
I
to
PRODUCT GAS
SEPARATOR
SOLVENT
SLOWDOWN
Figure 1. Typical flow diagram - MEA Acid Gas Removal Process (Rcf. 177)
-------
High capacity for acid gases (low solvent circulation
rates).
Not pressure sensitive
PROCESS LIMITATIONS
Forms nonregenerable compounds as a result of reaction
with organic sulfur.
Requires steam regeneration.
• Corrosion and foaming problems.
High solvent vapor pressure can cause excessive solvent
losses.
INLET GAS STREAM
Typical Composition - (raw natural gas; Ref. 178)
Component Vol % Component Vol %
N2 0.5 1C i, 0.1
C02 1.9 nCi, 0.2
H2S 0.6 iC5 0.1
G! 92.9 nCs 0.1
C2 2.2 C6+ 0.7
C3 0.7
DISCHARGE STREAMS
The
streams
e MEA process has both gaseous and liquid discharge
. These discharge streams are (Ref. 179):
Gas
Product gas (Stream No. 2)
- Acid gas (Stream No. 3)
Liquid
- Solvent blowdown (Stream No. 4)
B-30
-------
The following text discusses the composition of these streams,
using the Inlet Gas Stream composition given above as a basis.
Product Gas - The product gas contains very small amounts of
sulfur compounds and almost no C02. Typical composition is
as follows:
Component
N2
CO 2
H2S
Ci
C2
C3
Vol %
0.6
trace
4 ppmv
95.9
2.2
0.1
Component
Vol
iC5
nC5
C6+
0.1
0.1
0.1
0.2
Acid Gas - The acid gas stream produced during solvent re-
generation is composed primarily of C02, H2S, organic sulfur,
and hydrocarbons. The concentrations and amounts of each of
these components will depend upon the feed gas composition
and the process operating conditions. This stream will
require treatment to control emissions of sulfur compounds
and possibly hydrocarbons.
Solvent Slowdown - This stream will be composed primarily
of solvent with traces of solvent degradation products and
other components scrubbed from the process gas stream. The
disposition of this stream (further treatment to recover
solvents, incineration, etc.) will be determined by the nature
of the impurities present.
B-31
-------
GAS PURIFICATION OPERATION LOW TEMPERATURE
ACID GAS REMOVAL
MDEA (Methyldiethanolatnine) Process
GENERAL INFORMATION
Process Function - Chemical absorption of acid gases (H2S,
CO2, and organic sulfur) using MDEA as a sorbent.
Development Status - Commercially available.
Licensor/Developer - Dow Chemical Co.
Patent Department
Freeport, Texas
Commercial Applications - Has been widely used in refinery
gas cleanup applications.
Applicability to Coal Gasification - Technically feasible.
PROCESS INFORMATION
Equipment - Absorbers, stripping columns.
Flow Diagram - See Figure 1.
Control Effectiveness - Can reduce HaS level in product gas
to 4 ppmv, CO2 level to 10 vol %.
Operating Parameter Ranges -
• Temperature - 300 - 316°K (80 - 110°F)
Normal Operating Parameters -
• Temperature - 314°K (105°F)
Pressure - 0.4 MPa (60 psia)
Raw Material Requirements - MDEA solvent makeup-0.23 kg/
28,300 Nmb of natural gas (0.5 lb/106 scf).
B-32
-------
CO
CO
PRODUCT
GAS
SEPARATOR
RAW
LOW/
MEDIUM
BTU
GAS
ACID
GASES
STEAM
SOLVENT
SLOWDOWN
Figure 1. Typical flow diagram - MDEA Acid Gas Removal Process.
-------
Utility Requirements - Basis: Per 28,300 Nm3 (106 scf) gas
at 314°K (105°F) and 0.4 MPa (60 psia). Feed gas composed of
0.6 vol % H2S and 10 vol % C02 with 50 ppmv H2S and 3-3 vol %
C02 in treated gas. (Ref. 180)
• Steam - 4858 kg (10,700 Ib)
Cooling Water - Data not available.
• Electrical Power - 5.4 x 107 joule (15 kwh)
Basis: As above but to meet 965 ppmv H2S and 7.3 vol % C02
in treated gas.
• Steam - 2270 kg (5000 Ib)
Cooling Water - Data not available.
• Electrical Power - 2.9 x 107 joule (8 kwh)
PROCESS ADVANTAGES
Can be operated over a wide range of pressures
Removes most organic sulfur compounds without degrading,
Chemically stable solvent
PROCESS LIMITATIONS
Does not remove mercaptans
Relatively noncorrosive system
INLET GAS STREAM
The inlet gas stream (Stream No. 1) to this process in a coal
gasification plant will contain varying amounts of CO, C02, H2,
CH.,, N2, H2S, COS, NH3, H20, C2+ hydrocarbons, and perhaps other
components (e.g., trace elements).
B-34
-------
The MDEA process has both gaseous and liquid discharge
streams. These discharge streams are:
• Gas
- Product gas (Stream No. 2)
- Acid gas (Stream No. 3)
• Liquid
- Solvent blowdown (Stream No. 4)
Although no quantitative information on these streams could be
found, each of these streams is qualitatively discussed in the
following text.
Product Gas - The product gas stream will contain very small
amounts of sulfur compounds and C02 . It will be composed
primarily of CO, Ha, and Na with smaller amounts of CKU and
Acid Gas - The acid gas stream produced during solvent
regeneration is composed primarily of C02 , H2S, organic sul-
fur, and hydrocarbons. The concentrations and amounts of
each of these components will depend upon the feed gas
composition and the process operating conditions. This
stream will require treatment to control emissions of
sulfur compounds and possibly hydrocarbons.
Solvent Blowdown - This stream will be composed primarily
o f" s olven t wl th t r ac es of solvent degradation products and
other components scrubbed from the process gas stream. The
disposition of this stream (further treatment to recover
solvents, incineration, etc.) will be determined by the nature
of the impurities present.
B-35
-------
GAS PURIFICATION OPERATION LOW-TEMPERATURE
ACID GAS REMOVAL
PEA (Diethanolamine) Process
GENERAL INFORMATION
Process Func t i on - Chemical absorption of acid gases
(HZS, C02, and organic sulfur) using DBA as a sorbent.
Licensor/Developer - Ralph M. Parsons (SNPA-DEA Process)
617 W. Seventh Avenue
Los Angeles, California
Commercial Applications -
Removing E^S and COa from raw natural gas.
Applicability to Coal Gasification - Technically feasible.
PROCESS INFORMATION'
Equipment - Absorbers, distillation columns.
Flow Diagram - See Figure 1.
Control Effectiveness - Can reduce acid gas concentrations
to less than 3 ppmv H2S and 500 ppmv C02 (Ref. 181).
Operating Parameter Ranges - Data not available.
Normal Operating Parameters - Data not available.
Raw Material Requirements - DEA solvent makeup.
Utility Requirements - Data not available.
PROCESS ADVANTAGES
COS does not degrade the solvent.
Solvent has lower vapor pressure than MEA •
B-36
-------
u>
•xj
PRODUCT GAS
y\.
-< '
ABSORBER
,
I \
ACID GASES
VENT
RATOR
i
^>.
M)~
r
L
1
J
<
1
"" r .
L
^
r> ) STE
^^r
\ k
SEPARATOR
SOLVENT
SLOWDOWN
Figure 1. Typical flow diagram - DEA Acid Gas Removal Process.
-------
PROCESS LIMITATIONS
• Not effective at low pressures.
• Requires filtration to remove fine particulates which
cause foaming.
INLET GAS STREAMS
• The inlet gas stream (Stream No. 1) to this process in a
coal gasification plant will contain varying amounts of
CO, C02, H2, CM,,, N2, H2S, COS, NH3, H20, C2+ hydro-
carbons , and perhaps other components (e.g., trace elements)
DISCHARGE STREAMS
• The DEA process has both gaseous.and liquid discharge
streams. These discharge streams are:
Gas
- Product gas (Stream No. 2)
- Acid gas (Stream No. 3)
• Liquid
- Solvent blowdown (Stream No. 4)
Although no quantitative information on these streams could be
found, each of these streams is qualitatively discussed in the
following text.
Product..Gas - The product gas stream will contain very
small amounts of sulfur compounds and COa. It will be
composed primarily of CO, H , and N with smaller amounts
of CH^ and H20.
Acid Gas - The acid gas stream produced during solvent
regeneration is composed primarily of C02, H2S, organic
sulfur, and hydrocarbons. The concentrations and amounts
of each of these components will depend upon the feed gas
composition and the process operating conditions. This
stream will require treatment to control emissions of
sulfur compounds and possibly hydrocarbons.
B-38
-------
Solvent Slowdown - This stream will be composed primarily
of solvent with traces of solvent degradation products
and other components scrubbed from the process gas stream.
The disposition of this stream (further treatment to
recover solvents, incineration, etc.) will be determined
by the nature of the impurities present.
B-39
-------
GAS PURIFICATION OPERATION LOW-TEMPERATURE
ACID GAS REMOVAL
DIPA (Diisopropanolamine) Process
GENERAL INFORMATION
Process Function - Chemical absorption of acid gases
(H2S, C02, and organic sulfur) using DIPA as a sorbent.
Development Status - Commercially available.
Licensor/Developer - Shell Development Company (ADIP Process)
One Shell Plaza
P. 0. Box 2463
Houston, Texas 77001
Commercial Applications -
Removal of acid gases from natural gas, refinery gas,
synthesis gas or LPG.
Applicability to Coal Gasification - Technically feasible.
PROCESS INFORMATION
Equipment - Absorbers, flash towers, distillation columns.
Flow Diagram - See Figure 1.
Control Effectiveness - Can reduce Hi;S content in synthesis
gas (0.5 MPa) to less than 100 ppmv; in natural gas (6.9 MPa)
to 5 ppmv.
Operating Parameter Ranges -
. Temperature - 310°-333°K (100°-140°F)
. Pressure - 0.1-6.9 MPa (15-1000 psia)
Normal OperatingParameters -
. Temperature - 310°K (100°F)
Pressure - 1.9 MPa (270 psia)
B-40
-------
ACtO OASES
w
I
PRODUCT GAS
RAW
LOW/
MEDIUM
»TU GAS,
1
—
—
S.TRIPPER
*n
STEAM
SOLVENT
SLOWDOWN
SEPARATOR
Figure 1. Typical flow diagram - ADIP (DIPA) Acid Gas Removal Process.
-------
Raw Material Requirements - DIPA solvent makeup: 0.8 g/sec
per z»,:5uo Nm UO6 set) of gas at 1.9 HPa (270 psia) (Ref. 182)
Utility Requirements - Basis: Per 28,300 Nm3 (106 scf) of
gas at 1.9 MPa (270 psia). Feed gas composed of 10 vol %
HZS and 2.5 vol 7» C02 with 2 ppmv H2S and 0.2 vol % COz in
treated gas (Ref. 183).
. Steam - 10,000 kg (22,000 Ib)
Cooling Water - Data not available.
*
. Electrical Power - 3.1 x 108 joule (85 kWh)
PROCESS ADVANTAGES
DIPA solvent is noncorrosive.
Solvent is not degraded by COS.
Low steam consumption.
PROCESS LIMITATIONS
High pressure needed to meet extremely low H2S levels
(5 ppmv).
INLET GAS STREAMS
The inlet gas stream (Stream No. 1) to this process in a
coal gasification plant will contain varying amounts of CO, C02,
H2, CH.*, N2, H2S, COS, NH3, H20, C2 + hydrocarbons, and perhaps
other components (e.g., trace elements).
DISCHARGE STREAMS
The DIPA process has both gaseous and liquid discharge
streams. These discharge streams are:
• Gas
Product gas (Stream No. 2)
- Acid gas (Stream No. 3)
B-42
-------
Liquid
Solvent blowdown (Stream No. 4)
Although no quantitative information on these streams could
be found, each of these streams is qualitatively discussed in the
following text.
Product Gas - The product gas stream will contain very small
amounts of sulfur compounds and COz. It will be composed
primarily of CO, H2, and N2 with smaller amounts of CH^ and
H20.
Acid Gas - The acid gas stream produced during solvent re-
generation is composed primarily of COa, HgS, organic sul-
fur , and hydrocarbons. The concentrations and amounts of
each of these components will depend upon the feed gas com-
position and the process operating conditions. This stream
will require treatment to control emissions of sulfur com-
pounds and possibly hydrocarbons.
Solvent Blowdown - This stream will be composed primarily
of solvent with traces of solvent degradation products and
other components scrubbed from the process gas stream. The
disposition of this stream (further treatment to recover
solvents, incineration, etc.) will be determined by the na-
ture of the impurities present.
B-43
-------
GAS PURIFICATION OPERATION LOW- TEMPERATURE
ACID GAS REMOVAL
PGA (Diglycolamine) Process
GENERAL INFORMATION
Pr oce SB Func t ion - Chemical absorption of acid gases
S, COT, and organic sulfur) using DGA as a sorbent.
Development Status - Commercially available.
Licensor /Developer - Jefferson Chemical /Fluor
(Economine process)
Austin, Texas.
Commercial Applications -
Several in use in refineries to purify sour gas.
Applicability to Coal Gasification - Technically feasible
PROCESS INFORMATION
Equipment - absorbers, stripping columns.
Flow Diagram - See Figure 1.
Control Effectiveness - Can reduce HaS content in product
gas to less than 4 ppmv, CQ2 content to less that 0.01 vol %.
Operating Parameter Ranges -
• Temperature - 305°-325°K (908-130°F)
Normal Operating Parameters -
• Temperature - 305°K (90°F)
• Pressure - Not pressure sensitive
Raw Material Requirements - DGA solvent makeup.
B-44
-------
ACID GASES
Ul
ABSORBER
GAS
X
* 1
1 t
\ 1
\ 1
\ t
\ 1
V
A
''\
/ \
\
' \
i i
Y
J
CW ^
SOL\
REGENEF
i
f
I
1
fENT
1ATOH
L
>
I
ri^< _
A
—
—
V
i
<
^y '
cw /^^^\
1 *
( \-
y
^
^> ] STEAM
^*—S
i
^
SOLVENT
SLOWDOWN
SEPARATOR
Figure 1. Typical flow diagram - DGA Acid Gas Removal Process (Ref. 184)
-------
Utility Requirements - Basis: 33 Nm3/s (100 x 106 scf/d) at
3"05°K (90° F). Feed gas composed of 5% H2S, .5% C02.
• Steam - 22 kg/s (177,000 Ib/hr)
Electricity - data not available
Cooling Water - data not available
PROCESS ADVANTAGES
Low absorption of heavy hydrocarbons .
PROCESS LIMITATIONS
Forms nonregenerable compounds with organic sulfur
compounds
Requires a minimum of 1.5 to 2.0 percent acid gases
in feed gas
INLET GAS STREAM
Typical Composition -(Raw natural gas; Ref . 185)
Component Vol %
90
H2S 5
C0 5
DISCHARGE STREAMS
The DGA process has both gaseous arid liquid discharge
streams. These discharge streams are:
Gas
- Product gas (Stream No. 2)
- Acid gas (Stream No. 3)
B-46
-------
Liquid
- Solvent Blowdown (Stream No. 4)
The following text discusses the compositions of these streams,
using the Inlet Gas Stream composition given above as a basis.
Product Gas - Treated natural gas meets pipeline specifica-
tions of 4 ppmv H2S and .3 vol % C02. Typical DGA product
gas composition is as follows:
Component Vol %
CH,, 99.99
H2S 4 ppmv
C02 0.01
Acid Gas - The acid gas stream produced during solvent regen-
eration is composed primarily of COa , HaS, organic sulfur,
and hydrocarbons. The concentrations and amounts of each
of these components will depend upon the feed gas composi-
tion and the process operating conditions. This stream
will require treatment to control emissions of sulfur com-
pounds and possibly hydrocarbons.
Solvent Blowdown - This stream will be composed primarily
of solvent with traces of solvent degradation products
and other components scrubbed from the process gas stream.
The disposition of this stream (further treatment to recover
solvents, incineration, etc.) will be determined by the
nature of the impurities present.
B-47
-------
GAS PURIFICATION OPERATION LOW-TEMPERATURE
ACID GAS REMOVAL
Benfield Process
GENERAL INFORMATION
Process Function - Chemical absorption of acid gases
(H2S, CO2 and organic sulfur) using hot potassium
carbonate as a sorbent.
Development Status - Commercially available.
Licensor/Development - The Benfield Corporation
615 Washington Road
Pittsburgh, PA 15228
Commercial Applications -
Removal of COa, HzS, and COS from sour natural gas.
Applicability to Coal Gasification - The Benfield process
is a proven acid gas removal process for low/medium-Btu
gas produced in gasification plants in the following locations
• Westfield, Scotland
PROCESS INFORMATION
Equipment - Absorbers, distillation columns.
Flow Diagram - See Figure 1.
Control Efficiencies - Can reduce HzS and COS level in
product gas to 2 ppmv, CO2 to 0. 017o.
Operating Parameter Ranges -
• Temperature - up to 410°K (280°F)
• Pressure - 0.7 to 13.8 MPa (100-2000 psia)
Normal Operating Parameters -
• Temperature - 395"K (25Q*F)
• Pressure - 4.2 MPa (615 psia)
B-48
-------
PRODUCT GAS
ABSORBER
/
CW
cw
>sX
s)
$r
^
^
—
—
—
^ y
T-T
x* >
f -
SOLVENT /-^
REGENERATOR
-^ .
A
/vv
I > n
V
ACID
GASES
SEPARATOR
STEAM
SOLVENT
SLOWDOWN
Figure 1. Typical flow diagram - Benfield Acid Gas Removal Process
-------
Saw Material Requirements - Potassium carbonate solvent
makeup.
Utility Requirements - Basis: Per 28,300 Nm3 (106 scf)
of gas at 395"K (2508F) and 4.2 MPa (615 psia). Feed gas
composition of 1.5 vol % H2S, 5.4 vol % C02 , with 2 ppmv
H2S and 0.01 vol % C02 in product gas (Ref. 186).
Steam - 7128 kg (15,700 Ib)
Cooling Water - 114 m3 (30,000 gal)
Electrical Power - 5.0 x 108 joule (138 kWh)
Basis: Per 28,300 Nm3 (106 scf) of gas at 395°K (256°F)
and 4.2 MPa (615 psia). Feed gas composition of 45 vol %
C02 with 0.1 vol % C02 in product gas (Ref. 187).
Steam - 17,300 kg (38,200 Ib)
Cooling Water - 114 m3 (30,000 gal)
Electrical Power - 2.6 x 109 joule (735 kWh)
PROCESS ADVANTAGES
Removes organic sulfur and hydrogen cyanide.
Can be operated selectively with respect to H2S and C02
removal.
PROCESS LIMITATIONS
If operated selectively, the C02- rich stream will con-
tain sufficient JUS to require further control.
INLET GAS STREAM
Typical composition of product gas from an air-blown
Lurgi gasifier (Ref. 188).
B-50
-------
Component
Vol
Component
Vol %
CO 2
CO
H2
N
9.5
18.4
13.1
3.4
52.3
H2S
COS
NH3
H20
0.4
0
0
1
1
2.7
DISCHARGE STREAMS
The Benfield process has both gaseous and liquid discharge
streams. These discharge streams are:
Gas
- Product gas (Stream No. 2)
- Rich H2S gas (Stream No. 3)
Liquid
- Solvent blowdown (Stream No. 4)
Along with these discharge streams there will be fugitive emissions,
The following text discusses the compositions of these streams,
using the Inlet Gas Stream composition given above as a basis.
Product Gas - the product gas stream contains small quanti-
ties of pollutants such as HaS, COS and Nth . These can be
removed to almost any level desired. A typical product gas
composition is given below.
Component
C02
CO
H2
cm
N2
Vol %
7.2
18.4
13.1
3.4
52.3
Component
H2S
COS
NH3
H20
Vol
51 ppmv
25 ppmv
0.1
5.7
Rich H2S Gas - The rich H2S gas stream produced during solvent
regeneration is composed primarily of C02, H2S, COS, and H20.
A typical composition is shown below:
B-51
-------
Component Vol %
CO2 76.2
H2S 13.1
COS 3.2
H20 7.5
Solvent Slowdown - This stream will be composed primarily
of solvent with traces of solvent degradation products
and other components scrubbed from the process gas stream.
The disposition of this stream (further treatment to
recover solvents, incineration, etc.) will be determined
by the nature of the impurities present.
B-52
-------
GAS PURIFICATION OPERATION LOW TEMPERATURE
ACID GAS REMOVAL
Sulfinol Process
GENERAL INFORMATION
Process Function - Combination chemical/physical absorption
of acid gases(HaS, C02, and organic sulfur) using a sulfo-
lane/DIPA solvent.
Development Status - Commercially available.
Licensor/Developer - Shell Development Company
One Shell Plaza
P.O. Box 2463
Houston, Texas
Commercial Applications -
Removal of H2S and COa from natural gas.
Purification of refinery gases, synthesis gases, LNG
feedstocks, and hydrogen.
Applicability to Coal Gasification - Technically feasible.
PROCESS INFORMATION
Equipment - Absorbers, flash vessel, stripping column.
Flow Diagram - See Figure 1.
Control Effectiveness - Can reduce acid gas concentrations to
<1 ppmv H2S; C02 to <50 ppmv and H2S+COS to <2 ppmv.
Operating Parameter Rangeja -
• Temperature - 311°-325°K (100°-125°F)
B-53
-------
ACID GASES
I
Ol
SOLVENT
BLOWDOWN
Figure 1. Typical flow diagram - Sulfinol Acid Gas Removal Process
-------
Normal Operating Parameters -
• Temperature - 295°K (72°F)
Pressure - 2.7 MPa (400 psia)
Raw Material Requirements - Solvent makeup: less than
16 kg sulfinol/28,300 Nm3 C02 (35 lb/106 scf).
Utility Requirements - Basis: per 28,300 Nm3 (106 scf) of
gas at 2.7 MPa (397 psia) and 295°K (72°F). Feed gas com-
posed of 0.46 vol % H2S and 4.9 vol % C02.
• Steam - 454 kg (10,000 Ib)
• Electricity - 2.2 x 108 joule (60 kWh)
PROCESS ADVANTAGES
Low corrosion and foaming problems.
Low heat capacity of solvent.
Little degradation by organic sulfur compounds.
Lower circulation rates than typical amine process.
Lower steam requirements than typical amine process.
Low vapor pressure limits evaporation loss.
PROCESS LIMITATIONS
Expensive solvent.
Some hydrocarbons are soluble.
INLET GAS STREAM
Typical Flow - 33 Nm3/sec (100 x 106 scf/d) of raw natural
gas (Ref. 189).
B-55
-------
Typical Composition
Component Vol
H2S
CO 2
N2
Ci
COS
20.1
2.0
1.4
71.5
155 ppmv
Component
C2
C3
C4
C5+
RSH
Vol %
2.0
1.7
1.1
0.2
>100 ppmv
DISCHARGE STREAMS
The Sulfinol process has both gaseous and liquid discharge
streams. These discharge streams are:
• Gas
Product gas (Stream No. 2)
Acid gas (Stream No. 3)
Liquid
- Solvent blowdown (Stream No. 4)
The following text discusses the compositions of these streams,
using the Inlet Gas Stream composition given above as a basis.
Product Gas - The product gas stream is composed primarily
of CH^ with small amounts of C02, H2$, and organic sulfur
compounds. A typical composition is as follows:
Component
H2S
CO 2
COS+RSH
Vol %
99.0+
<4 ppmv
<1.0
<15 ppmv
Acid gas - The acid gas stream produced during solvent
regeneration is composed primarily of C02, H2S, organic
sulfur, and hydrocarbons. The concentrations and amounts
of each of these components depend upon the feed gas
composition and product gas specification. This, steam will
require control for sulfur compounds and possibly hydrocarbons
B-56
-------
Solvent Slowdown - This stream will be composed primarily of
solvent with traces of solvent degradation products and other com-
ponents scrubbed from the process gas stream. The disposition of
this stream (further treatment to recover solvents, incineration,
etc.) will be determined by the nature of the impurities present.
B-57
-------
GAS PURIFICATION OPERATION LOW TEMPERATURE
ACID GAS REMOVAL
Amisol Process
GENERAL INFORMATION
Process Function - Combination physical /chemical absorption
of acid gases (H2S, C02 and organic sulfur) using methanol
and DGA (Diglycolamine) as a sorbent.
Development Status - Commercially available.
Li cens or J Dey e loper - Lurgi Mineraltttechnik GmbH
American Lurgi Corporation
377 Rt 17 South
Hasbrouck Heights, New Jersey
Commercial Applications -
Removal of HzS and CO 2 from an ammonia and methanol
plant.
Applicability to Coal Gasification - Technically feasible.
PROCESS INFORMATION
Equipment - Absorber, stripping columns, flash vessels.
Flow Diagram - See Figure 1.
Control Effectiveness - Can reduce acid gas concentrations
to less than 0.1 ppm sulfur compounds and less than 5 ppm
Normal Operating Parameters -
• Temperature - 305°K (90°F)
• Pressure - 1.4 MPa (200 psia)
B-58
-------
PRODUCT GAS
ACID OASES
W
I
Ul
VO
ABSORBER
LOW/
MEDIUM
BTU GAS
f-
\
\
\
\
\
1
1
1
I
1
f
l\
1
1
1
1
V,
\
\
\
\
\
^
j
^
•
,*-"•
1
t
Lx
/AA
hc-M
v\v
Aj
cw
^x
—
• .
_
•— -
<^
k 1
-^_
-
— >
REQj
-^
(
cw
SOLVENT
REGENERATOR
STEAM
SEPARATOR
SOLVENT
SLOWDOWN
Figure 1. Typical flow diagram - Amisol Acid Gas Removal Process
-------
Raw Material Requirements - Amiaol solvent makeup: 160 kg/
1000 Nm3 gas (Ref. 190).
Utility Requirements - Data not available.
PROCESS ADVANTAGES
• Can be regenerated by simple flashing to meet less
stringent product specifications.
PROCESS LIMITATIONS
• Must have significant acid gas partial pressure in feed
gas to be economical.
INLET STREAMS
Basis - Inlet gas produced from residual oil by pressure
gasification (Ref. 191).
Composition -
Component
C02
H2S
COS
CO
DISCHARGE STREAMS
Vol %
6.6
0.38
152 ppm
44.9
Component
H2
N2
cm
Vol %
47.6
0.2
0.3
The Amisol process has both gaseous and liquid discharge
streams. These discharge streams are:
* GaJ
Product gas (Stream No. 2)
Regenerator off gas (Stream-Ho. 3)
B-60
-------
Liquid
- Solvent Blowdown (Stream No. 4)
The following text discusses the compositions of these streams,
using the Inlet Gas Stream composition given above as a basis.
Product Gas - The product gas stream contains practically
no sulfur compounds and very little C02. The typical
composition is shown below:
Component
H2S
COS
CO 2
H2
CO
voi y,
0.3 ppm
0.1 ppm
10 ppm
51.3
48.2
Regenerator Offgas -The typical composition of the offgas
produced during flash and subsequent hot water regeneration
is shown below.
Component
H2S
COS
C02
H2
CO
Vol %
4.4
0.15
90.7
2.4
2.3
Solvent Blowdown - This stream will be composed primarily
of solvent with traces of solvent degradation products
and other components scrubbed from the process gas stream.
The disposition of this stream (further treatment to re-
cover solvents, incineration, etc.) will be determined
by the nature of the impurities present.
B-61
-------
APPENDIX C
AIR POLLUTION CONTROL
-------
AIR POLLUTION CONTROL OPERATION SULFUR RECOVERY
AND CONTROL
Glaus Process
GENERAL INFORMATION
Process Function - The Glaus process Is a catalytic oxida-
tion process for recovering elemental sulfur from gas
streams containing H2S.
Development Status - Commercially available.
Licensor/Developer - Ralph M. Parsons (and others)
617 W. Seventh Avenue
Los Angeles, California
Commercial Applications - Control of sulfur emissions and
recovery of elemental sulfur from gas streams containing
high concentrations (at least 10-157o) of hydrogen sulfide.
Typical feed gases for a Glaus unit are the acid gases
stripped from regenerable liquids used for purifying sour
gases.
Applicability to Coal Gasification - The Claus process.has
not been used in a coal gasification plant. However, if a
selective acid gas removal process is used in a coal
gasification plant, the Claus process should be suitable
for treating the rich H2S stream generated by the acid gas
process.
PROCESS INFORMATION
Equipment - Reaction furnace, sulfur condensers, reheaters,
catalytic converters, waste heat boiler.
Flow Diagram - There are two variations of the Claus process:
the split stream and the partial combustion process. Figure
1 is a simplified flow scheme which shows the major features
of both of these process options. In the partial c&aibustiafi
process, all of the feed gas is directed to the reaction fur-
nace, wherein enough oxygen (as air) is introduced to oxidise
one-third of the H2S to S02. It is at this point tfeat any
hydrocarbons or C02 present in the feed gas may react with
the H2S-rich vapors to form COS and CS2. In the split stream
process, only one-third of the feed gas is directed to the
C-2
-------
I SULFUR
I CONDENSER
STM
SULFUR
CONDENSER
SULFUR
CONDENSER
\
1
J
REACTION
FURNACE
-------
reaction furnace where the H2S is combusted completely to
form S02. Since complete combustion of this stream takes
place in the split stream version of this process, all
hydrocarbons are destroyed and organic sulfur fqrmatipn is
minimized. The reaction furnace effluent is then rfecombined
with the bypass stream. Further processing steps are iden-
tical in both variations of this process.
Sulfur Conversion Effectiveness - Elemental sulfur is pro-
duced in the Glaus process by the oxidation-reduction
reaction shown in Reaction 1.
2H2S + S02^2H20 + 3/e S + 54.5 Mjoule (1)
e
As mentioned previously, the S02 may be formed either by
partial combustion of the entire feed gas stream or by
complete combustion of one-third of the feed. Reaction 2
shows this oxidation reaction while Reaction 3 shows the
overall Glaus reaction.
H2S + 3/2 02 + S02 + H20 + 247 Mjoule (2)
3H2S + 3/2 02 ^ 3H20 + 3/e S + 302 Mjoule (3)
fci
Since Reaction 1 is reversible, equilibrium considerations
limit the conversion of H2S to sulfur, with lower tempera-
tures favoring the product side as illustrated in Figure 2.
Because of the exothermic nature of the Glaus reaction,
thermal constraints limit the amount of conversion which
can be achieved in a single reactor. Thus, when high sulfur
conversion values are desired, a series of reactors and
sulfur condensers must be used. With this approach, the
sulfur condensers serve the dual purpose of lowering the gas
temperature (which shifts the equilibrium of Reaction 1 to
the right) and removing product sulfur from the gas phase
(which lowers the sulfur back pressure). The reheaters shown
in Figure 1 are necessary to raise the converter gas feed
temperature above the sulfur dew point so that the bauxite
catalyst at the reactor inlet does not become fouled with
sulfur. A theoretical optimum temperature profile for a
partial combustion Glaus process employing four catalytic
converters is shown in Figure 3. The theoretical conversion
efficiency for this temperature profile is 99.5% (see Figure
4).
In actual practice, efficiencies of only 90-95% are normally
achieved. This is mainly because of the inability to con-
trol the 2:1 ratio of H2S to S02 required by the oxidation-
reduction reaction shown in Reaction 1. This can be caused
by the presence of oxidizable compounds such as ammonia or
C-4
-------
100
90
IU
1
o
60
50
CURVE IS FOR A TOTAL SYSTEM 1 ATM
PRESSURE AND NO SULFUR REMOVAL
THERMAL
REGION
CATALYTIC
• REGION
127 327
527 727 927
TEMPERATURE ,"C
It 27 1327
Figure 2. Theoretical conversion of H2S to sulfur vapor
(Ref. 192)
C-5
-------
o
I
u.
o
UJ
(T
tr
iu
a.
2
ai
i-
o
H
UJ
OC
O
UJ
I
600
500
400
300
200
AUXILIARY
BURNER
REHEAT
INDIRECT
REHEAT
INDIRECT
REHEAT
INDIRECT
REHEAT
SULFUR DEWPOINT
TEMPERATURE
OPERATING
TEMPERATURE
I
COND1 CONV1 COND2 CONV2 COND3 CONV3 COND4 CONV4 COND5 CONV5
Figure 3. Theoretical optimum Glaus plant temperature profile (Ref. 193).
-------
o
I
100
99
98
07
y'
96
1-
2
Ul
O
111
a.
^*
>-
o
2
- 95
O
VL
u.
Ul
tu
g
LU
I
92
91
90
2-STAGE CONVERSION 98.4%
3-STAGE CONVERSION 99.3%
4-STAGE CONVERSION 99.6%
CONVERSION EFFICIENCY
FURNACE CONVERSION
66.3%
2-STAGE RECOVERY 97.8%
3-STAGE RECOVERY 99,1%
4-STAGE RECOVERY 99.5%
RECOVERY EFFICIENCY
CONDENSER 1 RECOVERY 62.1%
I I I I
COND 1 CONV 1 COND 2 CONV 2 COND 3 CONV 3 COND 4 CONV 4 COND 5
Figure 4. Theoretical optimum Glaus plant conversion and recovery efficiencies
fRpf 1Q4^
-------
hydrocarbons in the feed gas. Additional factors which may
lower the sulfur conversion efficiency are:
Portions of the feed gas sulfur may be in the focm
of organic sulfur compounds, such as COS and CS2,
which are not readily converted to sulfur in the
Glaus process.
Hydrocarbons and C02 present in the feed gas may
react with vapor phase sulfur or H2S to form COS
and CS2.
While COS and CS2 can be hydrogenated or hydrolyzed to H2S
by Glaus catalysts (see Figures 5 and 6), high conversions
occur only at temperatures above 640°K (700°F) (Ref* 195). At
these temperatures the main Claus reaction, Equation 1, has
an unfavorable equilibrium position (see Figure 2 - 640°K -
367°C). To overcome this drawback and yet convert most of
the COS and CS2 to H2S, the first catalytic reactor in a
Claus unit is often operated around 560-640°K (550-700°F)
while the remaining reactors are operated at significantly
lower temperatures (see Figure 3).
The operating temperature for a Claus plant, and hence its
sulfur recovery efficiency, will be, among other things,
dictated by the feed gas composition, the availability of a
tail gas cleanup process capable of removing COS and CS2
(i.e., it may not be necessary to remove these species in
the Glaus unit), and process economics.
Operating Parameter Ranges (Refs. 196, 197, 198) -
Temperature:
- Reaction furnace - 1370-1920°K (2000-3000°F)
- Catalytic converters - 400-650°K (260-710°F)
• Pressure: 0.1-0.2 MPa (15-30 psia)
Raw Material and Utility Requirements - Basis: recovery of
0.454 kg (1 Ib) of sulfur from an inlet gas stream containing
40% H2S and 60% C0? (Refs. 199, 200).
Catalyst (typically bauxite)
• Air
• Boiler feed water: 0.003 m3 (0.75 gal)
C-8
-------
0
t
COBALT ^COBAL
MOLY I *•
COBALT
MOLY III
IV
100 r
225 250 275 300 325 350 375 400°C
436 482 527 572 617 662 707 752T
TEMPERATURE
GAS 2%
2%
1%
0.5%
28%
66.5%
GHSV
250 275 300 325 350 375 400"C
482 527 572 617 662 707 752 °F
TEMPERATURE
Figure 5. Conversion of COS to H2S
over sulfated catalysts
(Ref. 201)
Figure 6. Conversion of CS2 to H2S
over sulfated catalysts
(Ref. 202)
-------
• Electric power: 0.04 kWh
• Cooling water duty: 6.7 x 105 joule (6-40 Btu)
By-Products or Utility Credits -
Elemental Sulfur
• Steam: 2.7 Kg (6.06 Ib)
PROCESS ADVANTAGES
A commercially proven process for bulk H2S removal.
Produces high-purity readily salable elemental sulfur.
Split stream process configuration destroys one-third of
any organic sulfur compounds and hydrocarbons present in
the feed gas. The reduction in hydrocarbons also reduces
potential for forming organic sulfur compounds in down-
stream processing equipment.
PROCESS LIMITATIONS
Requires a feed stream containing at least 10-15% H2S to
be economical.
Equilibrium considerations limit process from being a
"final" sulfur control process; therefore, a tail gas
cleanup process is required for removal of residual
sulfur compounds.
Hydrocarbons and C02 in the feed gas enhance the formation
of organic sulfur compounds which are not readily conver-
ted to elemental sulfur.
Carbonaceous matter, trace elements and high concentrations
of ammonia (>3%) in the feed gas may cause catalyst
deactivation and/or may form solids which can cause equip-
ment fouling problems (Ref. 203).
Corrosion can be a problem, especially in the sulfur
condensers (Ref. 204).
The use of too little or too much air in the reaction
furnace will decrease the sulfur removal effectiveness.
C-10
-------
INLET GAS STREAM
Basis - The feed gas to a Glaus unit is composed of H2S
and other components removed in an acid gas removal system.
The composition of a Glaus plant feed gas, typical of those
generated in the coking industry, is shown below (Ref. 205):
Component Vol % Component Vol %
H2S 75.11 S02 0.05
C02 18.20 Hydrocarbons 2.07
HCN 0.45 !J2 3.41
CS2 0.29 Ar 0.07
COS not reported H2 0.33
DISCHARGE STREAMS AND THEIR CONTROL
The Glaus process generates gaseous, liquid and solid
discharge streams. These discharge streams are:
• Air Emissions:
- Tail gas (Stream No. 2)
Liquid Effluents:
By-product sulfur (Stream No. 3)
Solid Wastes:
Spent catalyst (Stream No. 4)
The f611owing text discusses the compositions of these streams
using the INLET GAS STREAM composition given above as a basis.
Tail Gas - The Glaus unit tail gas, which contains signifi-
cant quantities of sulfur species such as H2S, S02, COS and
CS2, requires further treatment before discharge. There are
many processes commercially available that are capable of
removing these residual sulfur compounds from the Glaus unit
tail gas. A typical Glaus unit tail gas composition is
shown below:
C-ll
-------
Component Vol 7, Component Vol %
H2S 0.22 S02 0.13
COz 11.57 Hydrocarbons not reported
HCN 0.0 N2 86.18
CS2 0.11 Ar 1.22
COS 0.15 H2 0.42
By-Product Sulfur - The elemental sulfur by-product generated
by the Glaus unit is typically of a salable quality (99+%
pure). Carbon is the most frequent contaminant present in
the sulfur by-product, but if the Glaus unit is operated
within its design limits, carbon contamination is not a
problem.
Spent Catalyst - Bauxite is the most commonly used Glaus
catalyst.It is subject to thermal and hydrothermal aging
as well as poisoning by ammonia, carbonaceous matter and
sulfur. To reduce deactivation from sulfur poisoning, the
catalytic converters are operated above the sulfur dew point
of the gas. However, sulfur may still be retained on the
catalyst surface due to adsorption. Because of the presence
of ammonia, carbon and/or sulfur compounds on the spent
catalyst, it may require treatment prior to disposal.
C-12
-------
AIR POLLUTION CONTROL OPERATION SULFUR RECOVERY
AND CONTROL
Stratford Process
GENERAL INFORMATION
Process Function - Sulfur recovery process; based upon the
liquid phase oxidation of H2S to elemental sulfur in an
alkaline solution of tnetavanadate and anthraquinone disul-
fonic acid (ADA) salts.
Development Status - Commercially available.
Licensor/Developer - Peabody Engineered Systems
39 Maple Tree Avenue
Stamford, Connecticut
Commercial Applications -
Removing H2S from natural gas.
Purifying coke oven gas.
Purifying producer gas.
Applicability to Coal Gasification - The Stretford process
should be a technically feasible process for removing H2S
from:
The tail gases from an acid gas removal process
Process vent gases
Other gaseous streams containing H2S.
PROCESS INFORMATION
Equipment - Absorber, oxidation tank, surge tank, and
elemental sulfur recovery equipment.
Flow Diagram - Figure 1 is a simplified flow scheme for the
Stretford process. The overall process reaction is repre-
sented by Equation 1.
C-13
-------
TAIL GAS
o
1
OXIOiZER VENT
1
MAKE-UP MAKE-UP
WATER CHEMICALS
ELEMENTAL
SULFUR TO
RECOVERY
SORBENT
SLOWDOWN
Figure 1. Typical flow diagram - Stretford Sulfur Recovery Process
-------
2H2S + 02 + 2S + 2H20 (1)
However, the process actually utilizes the following reaction
sequence:
Absorber
H2S + Na2C03 ** NaHS + NaHC03 (2)
• Reaction Hold Tank
4NaV03 + 2NaHS + 2H20 ^ Na2Vt»09 + 2S + 4NaOH (3)
Na2V,»09 + 2NaOH + H20 + 2ADA v* 4NaV03 4- 2ADA (reduced) (4)
Oxidation Tank
2ADA (reduced) + 02 ^ 2ADA 4- 2H20 (5)
The rate of absorption of H2S is pH dependent, which in turn
is strongly influenced by the C02 content of the fe6d gas
(see Figure 2). Complexing agents such as sodium potassium
tartrate or citric acid are sometimes used to prevent
vanadium deposition in systems operating beyond their design
H2S removal levels. Solubilized iron with Bellasol S.C.S.
or EDTA may also be present in the Stretford solution to
speed up the reoxidation of some unwanted colored by-*
products (Ref. 206).
Several side reactions which form nonregenerable compounds
are possible in a Stretford unit. If the sodium hydrosulfide
contacts absorbed oxygen in either the absorber or in the
oxidation tank (implying the system is removing H2S at levels
above design), sodium thiosulfate will form according to
the following reaction:
2NaHS 4- 202 •* Na2S203 + H20 (6)
Since the amount of dissolved 02 is dependent upon the pH of
the liquor, the rate of Reaction 6 is also dependent upon pH
and will decrease as pH decreases (see Figure 3), Any
hydrogen cyanide present in the feed gas will form sodium
thiocyanate via the overall reaction shown in Reaction 7,
HCN + NaHS 4- 1/202 -»• NaCNS 4- H20 (7)
Any S02 present in the feed gas will also be absorbed and
eventually oxidized to form sulfate. These unwanted by-
products can build up without harm to the process chemistry,
but they must eventually be purged from the system to avoid
precipitation problems.
C-15
-------
2.0
2
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oc<
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EQUILIBRIUM PH VALUE OF WASH LIQUOR
Figure 2. Effect of C02 on Stretford operation
(Ref. 207)
C-16
-------
-------
Control Effectiveness - The Stretford process can reduce
the h2s content ot a gas to less than 1 ppmv. However,
organic sulfur compounds (COS, CS2, thiopnenes, etc.) are
not removed at all except for minor portions of methyl
mercaptans (Ref. 209). Essentially all HCN and S02 are
removed, but in a nonregenerable fashion, forming thiocya-
nate and sulfate, respectively.
Operating Parameter Ranges (Ref. 210) -
• Temperature: 300-322°K (80-120°F)
Pressure:
- Absorber: 0.1-6.9 MPa (15-1000 psia)
- Oxidation tank: 0.1 MPa (15 psia)
• pH: 8.5-9.5
Raw Material and Utility Requirements - Basis: Treatment of
28,300 Nm3 (10" scf) of gas containing 0.74 vol % H2S
and 30 ppmv HCN (Refa. 211, 212).
Chemicals:
- ADA 0.73 Kg (1.6 Ib)
- NaV03 0.44 Kg (1.0 Ib)
- Na2C03 9.6 Kg (21 Ib)
• Cooling water duty - 3.6 x 109 joule (3.4 x 106 Btu)
Electric power - 278 kWh
• Makeup water
PROCESS ADVANTAGES
Can reduce the H2S content of a gas to less than 1 ppmv.
Extremely flexible process, capable of high turndown
ratios.
« A properly designed system has low makeup chemical
requirements.
C-18
-------
Low maintenance requirements.
...;• • « i . .. .. . ... -.,.. .... ..,«,!»,.«. It*. -
Not pressure sensitive.
PROCESS LIMITATIONS
Does not remove organic sulfur compounds, except for
minor quantities of methyl mercaptans.
High C02 concentrations in the feed gas caiT cause> fh*
system to operate at lower pH's, reducing the efficiency
of the process.
Generally not economical for treating very large volumes
of gas, due to equipment size considerations.
If system becomes overloaded, i.e., H2S removal fate is
greater than the design rate, the undesirable side
reaction forming nonregenerable thiosulfate (Reaction 6)
can become significant causing excessive scrubbing liquor
blowdown rates to be required.
Not usually economical for treating gas streams containing
greater than 15 percent H2S (Ref.213).
INLET GAS STREAM
The feed gas to a Stretford unit usually contains less
than 15 percent H2S. A typical feed gas generated bjkJLJKJf?
selective acid gas removal process is shown below (Ref. 214,
Component
C02
H2S
COS
CS2
HCN
CO
Vol %
96.0
0.74
77 ppmv
2 ppmv
30 ppmv
0.17
Component
CH,,
C2Hit
C2H6
H2
H20
Vol %
0.53
0.22
0.30
0.43
1.6
C-19
-------
DISCHARGE STREAMS AND THEIR CONTROL
The Stretford process has both air and liquid discharge
streams. These discharge streams are:
• Air Emissions
- Tail gas (Stream No. 2)
Oxidizer vent (Stream No. 5)
• Liquid Effluents
Sorbent blowdown (Stream No. 3)
By-product sulfur (Stream No. 4)
The following text discusses the compositions of these streams,
using the INLET GAS STREAM composition given above as a basis.
Tail Gas - The treated gat from a Stretford unit can be
essentially free of H2S but will contain all of the organic
compounds present in the feed gas. In addition, no HCN,
SOz, NH3 and heavy hydrocarbons are normally present in the
treated gas. There are several organic sulfur control pro-
cesses capable of treating the Stretford tail gas. However,
if these species are present in significant quantities,
common practice is to convert them to H2S, e.g., in a Holmes-
Maxted, Carpenter-Evans, or British Gas Council unit, prior
to their being treated in the Stretferd unit*. A typical
tail-gas composition is given below (lef. 215):
Component Vol % Component Vol %
C02 94.0 CH,, 0.52
H2S 8 ppmv C2Hi, 0.22
COS 75 ppmv C2H6 0.29
CS2 2 ppmv H2 0.42
HCN 0 H20 4.32
CO 0.16
Oxidizer Vent - The oxidizer vent consists mainly of Q2, N2,
water vapor and small amounts of C02 stripped from the
scrubbing liquor. However, if ammonia is present 4m £he
feed gas, if will be absorb£d with the H2S, strip»e*f out
in the oxidizer, and lefttre with the vent ga»es.
C-20
-------
Solvent Slowdown Stream - The sorbent blowdown stream i*
necessary to prevent an excessive buildup of tJonregeneraole
by-products in the recirculating liquors. These by-products
include thiosulf ates, thiocyanates and sulfates. The purge
may be withdrawn continually or the system may be allowed to
build up very high concentrations of salts and then be com-
pletely discarded. A typical sorbent blowdown stream compo-
sition, based on a continual blowdown, is given below
(Ref. 216):
Component wt % Component wt %
H20 80.0
Ha2S203 10-8 ADA
4.4 HaHCQ3+Na2C03
Several methods are being developed to recover the vanadium
present in the blowdown stream, but at the present time,
operational data on these processes are not available.
Because of the presence of vanadium compounds, ADA, thio-
cyanates in the blowdown stream, it must be directed to the
water pollution control operation for treatment before being
discharged or reused.
By-Product Sulfur - The sulfur product from the Stretford
process is nominally 99.5% sulfur with small amounts of
components such as vanadium salts, sodium thiocyanate and
sodium thiosulfate being present as impurities.
C-21
-------
AIR POLLUTION CONTROL OPERATION SULFUR RECOVERY
AND CONTROL
Beavon Process
GENERAL INFORMATION
Process Function - The Beavon process is a tail gas cleanup
process based on the catalytic conversion of sulfur species
to H2S (via hydrogenation and hydrolysis) followed by re-
covery of the H2S as elemental sulfur in a Stretford unit.
Development Status - Commercially available.
Licensor/Developer - Ralph M. Parsons
617 W. Seventh Avenue
Los Angeles, California
Commercial Applications -
Glaus unit tail gas treatment.
Applicability to Coal Gasification - The Beavon process
has been shown to be a technically feasible process for
treating the tail gas from a Glaus unit. The Beavon pro-
cess should be suitable for treating the tail gas from a
coal gasification Glaus unit.
PROCESS INFORMATION
Equipment - Burner, catalytic reactor, coolers, absorber,
oxidation tank, surge tank.
Flow Diagram - Figure 1 is a simplified flow scheme of the
Beavon process. Sulfur species are converted to H2S in
the catalytic reactor via the following reactions.
S + H2 ** H2S (1)
S02 + 3H2 ** H2S + 2H20 (2)
COS + H20 ** H2S + C02 (3)
CS2 + 2H20 ** 2H2S + ,C02 (4)
C-22
-------
o
I
ro
co
LINE
BURNER
COOLER
• • ' • -•• »»
X'-'-X.
X'
l^_ _i
1 J
SORBENT
BLOWOOWN
COHDEHSATE TO
SOUR WATER
STRIPPER
Figure 1. Typical flow diagram - Beavon Tail Gas Treating Process
-------
The hydrogen for Reactions 1 and 2 can be supplied by
substoichiometric combustion of fuel gas (which,JiltUr
supplies heat for the above reactions) , if suflicittiit
hydrogen is not present in the feed gas. After being
cooled, the converted gases are treated in a Stretford
unit for recovery of the H2S as elemental sulfur (See
Fact Sheet for Stretford Process for details of this por-
tion of the Beavon Process). No undesirable side re-
actions occur in the catalytic converter. Since trace
elements are normally not present in the Glaus tail gas,
the catalyst should remain active for extended periods of
time (Ref. 217).
Control Effectiveness - The effectiveness of the Beavon
process for removing sulfur species is dependent upon
two factors: 1) the conversion efficiencies obtained in
the catalytic reactor and 2) the removal efficiency of the
Stretford unit. The equilibrium constants for Reactions
1 and 2 are very high and hence essentially complete con-
version of S and S02 occurs. The extent of hydrolysis of
COS and CS? is also very high as illustrated in Figures 2
and 3. Normally, less than 100 ppmv of non-H2S sulfur com-
pounds are present in the reactor effluent (Ref. 218). The
Stretford process is capable of reducing the H2S content
of a gas to less than 1 ppmv. Therefore, the Beavon pro-
cess should be able to produce a treated gas with less than
100 ppmv of total sulfur species and less than 1 ppmv of
H2S.
Operating Parameter Ranges (Refs. 219> 22Q) -
Temperature:
- 560-670°K (550-750'F) Catalytic (hydrogenation) reactor
- 300-322°K (80-120°F) (Stretford)
Pressure: Atmospheric
Raw Material and Utility Requircjaqats - Basis: Treatment
of the tail gas from a i.03 kg/s (100 tpd) Glaus sulfur
plant (Ref. 221):
• Electrical power: 283 kW
• Fuel gas: 0.04 Nm3/s (125 x 103 scf/d)
• Boiler feed water: 0.0005 m3/s (12 x 103 gal/d)
C-24
-------
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60
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40
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BAUXITE
100 r
GAS 2%
1%
28%
67.5% No
GHSV 1000
225 250 275 300 325 350 375 400°C
436 482 527 572 617 662 707 752"F
TEMPERATURE
250 275 300 325 350 375 400"C
482 527 572. 617 662 707 752 °F
TEMPERATURE
Figure 2. Conversion of COS to H2S
over sulfated catalysts
(Ref. 222)
Figure 3. Conversion of CSz to H2S
over sulfated catalysts
(Ref. 223)
-------
Makeup chemicals for Stretford unit (see Stretford
Process fact sheet)
Cooling water
Makeup water
Utility Credits and By-products (Ref. 224):
• Steam 0.3 kg/s (2500 Ib/hr)
Sulfur from Stretford unit
PROCESS ADVANTAGES
Recovers organic sulfur compounds and SOa as elemental
sulfur.
Can utilize existing Stretford plant, if available.
PROCESS LIMITATIONS
Data not available on catalytic reactor section (See
Fact Sheet on Stretford process for limitations on the
sulfur recovery section).
Requires some type of fuel gas to supply heat and to pro-
duce a reducing gas for the catalytic reactor.
INLET GAS STREAM
The composition of a typical Glaus tail gas which may be
treated in a Beavon unit is as follows (Ref. 225):
Component Vol % Component Vol %
H2 2.5 S 0.7
CO 1-0 H2S 2.0
C02 10.0 S02 1.0
N2 56.2 COS 0.3
H20 26.0 CS2 0.3
0-2 6
-------
DISCHARGE STREAMS AND THEIR CONTROL
The Beavon process has both air and liquid discharge streams
These discharge streams are:
Air Emissions
- Treated tail gas (Stream No. 2)
- Oxidizer vent (Stream No. 5)
• Liquid Effluents
- By-Product sulfur (Stream No. 4)
- Stretford sorbent blowdown (Stream No. 6)
Condensate (Stream No. 3)
The following text discusses the compositions of these streams,
using the INLET GAS STREAM composition given above as a basis.
Treated Tail Gas - The treated gas from the Beavon process
can contain less than 1 ppmv H2S. A typical treated gas
composition is as follows:
Component Vol % Component Vol %
H2 varies S
CO 0.2 H2S
C02 14.2 S02
N2 80.8 COS <250 ppm
H20 5.0 CS2
Oxidizer Vent - The oxidizer vent contains N2, 02 , HaO and
C"0~2~iIf NH3 is present in the feed gas to the Beavon unit
it will be removed in the H2S absorber, stripped out by
the air in the oxidizer, and exit with the vent gases.
By-Product Sulfur - The by-product sulfur stream is normally
at 1east 99.5% pure sulfur, with the main impurities being
chemicals present in the Stretford solution such as meta-
vanadate, anthraquinone disulfonic acid (ADA), carbonate,
bicarbonate, thiosulfate and thiocyanate salts.
C-27
-------
Stretford Sorbent Slowdown - This stream contains high con-
centrations of salts such as Na2S203, NaCNS, NaV03, ADA,
NaHC03 and Na2C03. The Stretford Process Fact Sheet gives
further details on this discharge stream.
Condensate Stream - The condensate stream will contain
dissolved H2S.However, if this component is stripped out,
the water should be suitable for reuse (Ref. 226).
C-28
-------
AIR POLLUTION CONTROL OPERATION SULFUR RECOVERY
AND CONTROL
SCOT (Shell Glaus Offgas Treating) Process
GENERAL INFORMATION
Process Function - The SCOT process is a tail gas cleanup
process based on the catalytic conversion of sulfur species
(COS, CS2, SO 2, S, etc.) to H2S (via hydrogenation and
hydrolysis) followed by removal and recovery of the H2S in
an alkanolamine scrubbing system.
Development Status - Commercially available.
Licensor /Developer - Shell Development Co. (USA)
One Shell Plaza
P.O. Box 2463
Houston, Texas 77001
Commercial Applications -
Claus unit tail gas treatment.
Applicability to Coal Gasification - The SCOT process has
been shown to be a technically feasible process for treating
the tail gas from a Claus unit. The SCOT process should be
suitable for treating the tail gas from a coal gasification
plant, Claus unit or Stretford unit.
PROCESS INFORMATION
Equipment - Catalytic reactor, cooler, absorber, stripper.
Flow Diagram - Figure 1 is a simplified flow scheme of the
SCOT process. In this process, sulfur species are converted
to H2S in the catalytic reactor via the following reactions.
S + H2 «-» H2S (1)
S02 + 3H2 ** H2S + 2H20 (2)
COS + H20 *•* H2S + C02 (3)
CS2 + 2H20 ** 2H2S + C02 (4)
C-29
-------
LINE
BURNER
COOLER
+.
^
^
/ \
^ \
J
/\1
v^N
c.w j
ABSORB)
ALK
2
/*^^*\
ER vr~/ "
\ /
X
/\
L N
^— i-—*'^
(\\
X-
ALKANOLAMINE SCRUBBING SYSTEM
TREATED
TAIL GAS
MAKE-UP
SORBENT
RICH H2S STREAM
TO CLAUS UNIT
\ /
/ M
STRIPPER
CONDENSATE TO
SOUR WATER
STRIPPER
•5 y ^. SORBENT
BLOWDOWN
Figure 1. Typical flow diagram - Scot Tail Gas Treating Process
-------
The hydrogen for Reactions 1 and 2 can be supplied by
substoichiometric combustion of a light hydrocarbon (which
also supplies heat for the above reactions), if sufficient
hydrogen is not present in the feed gas. After being cooled,
the converted gases are sent to an alkanolamine scrubbing
unit for removal of the H2S which can be subsequently
recovered and recycled to the Glaus unit.
Control Effectiveness - The effectiveness of the SCOT process
for removing sulfur species is dependent upon two factors:
1) the conversion efficiencies obtained in the catalytic
reactor and 2) the removal efficiency of the alkanolamine
unit. The equilibrium constants for reactions 1 and 2 are
very high and hence essentially complete conversion of S and
S02 occurs. The extent of hydrolysis of COS and CS2 is also
very high, as illustrated in Figures 2 and 3. Normally,
less than 100 ppmv of non-H2S sulfur compounds are present
in the reactor effluent. The alkanolamine process is capable
of reducing the H2S content of a gas to less than 10 ppmv.
Therefore, the SCOT process should be able to produce a
treated gas with around 100 ppmv or less of total sulfur
species and less than 10 ppmv of H2S. However, repotted
data indicate 200-500 ppmv is a more typical concentration
level for the sulfur species in the treated tail gas (Ref.
227, 228).
Operating Parameter Ranges (Ref. 229) -
Temperature:
- Catalytic reactor: around 575*K (575°F)
- Absorber: 290-310°K (60-100°F)
- Stripper: around 395°K (250°F)
Pressure: Atmospheric
Raw Material and Utility Requirements - Basis: removal of
0.45 Kg (1 Ib) of sulfur (Ref. 230).
• Steam: 5.2 kg (11.4 Ib)
• Cooling water: 0.39 m3 (103 gal)
• Electric power: 0.042 kWh*
• Fuel gas: 4.6 x 10e joule (4.4 x 103 Btu)
• Makeup alkanolamine
C-31
-------
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100
90
80
70:
60
50
40
30
20
10
CATALYST
S-501
BAUXITE
COBALT _£OBAL
MOLYI -"7MOLY
COBALT
• MOLY III
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28%
67.5%
GHSV
Si
col
Hf
1000
225 250 275 300 325 350 375 400°C
436 482 527 572 617 662 707 752"F
TEMPERATURE
Figure 2. Conversion of C02 to H2S
over sulfated catalysts
(Ref. 231)
100
GAS 2%
2%
1%
0.5%
28%
250 275 300 325 350 375 400°C
482 527 572. 617 662 707 752 °F
TEMPERATURE
Figure 3. Conversion of CSa to H2S
over sulfated catalysts
(Ref. 232)
02-iaei-t
-------
PROCESS ADVANTAGES
Utilizes proven sulfur recovery equipment.
System should be capable of higher removal efficiencies
if desirable.
PROCESS LIMITATIONS
Requires some type of fuel gas to supply heat and to
produce a reducing gas for the catalytic reactor.
INLET GAS STREAM
The composition of a typical Glaus plant tail gas which may
be treated in a SCOT unit is (Ref. 233):
Component Vol % Component Vol %
H2S .85 CO .22
S02 .42 C02 2.37
S .05 H2 1.6
COS .05 H20 33.1
CS2 .04 N2 61.3
DISCHARGE STREAMS AND THEIR CONTROL
The SCOT process has both air and liquid discharge streams.
These discharge streams are:
Air Emissions
- Treated tail gas (Stream No. 2)
- Rich HZS stream (Stream No. 4)
Liquid Effluents
- Process condensate (Stream No. 3)
Sorbent blowdown (Stream No. 5)
C-33
-------
The following text discusses the compositions of these streams
using the INLET GAS STREAM composition given above as a basis.
Treated Tail Gas - The tail gas is normally fed to an
incinerator to convert all remaining sulfur compounds to
S02. A typical tail gas composition is as follows (Ref. 234)
Component Vol 70 Component Vol %
H2S .03 CO
S02 - C02 3.05
S H2 .96
COS 10 ppm H20 7.0
CS2 1 ppm N2 90.0
Rich H2S Stream - The rich H2S stream generated by the
alkanolamine stripper is normally recycled to the Glaus
unit for sulfur recovery. This stream will also contain
some CO2, with the amount depending upon the alkanolamine
system used.
Process Condensate - The condensate stream will contain
dissolved H2S.However, if this component is stripped
out, the water should be suitable for reuse (Ref. £35).
Sorbent Slowdown - The sorbent blowdown stream contains
primarily H20, alkanolamine and alkanolamine degradation
products. Although the flow rate of this stream should be
minimal, this stream would normally be directed to the water
pollution control operation for treatment.
C-34
-------
AIR POLLUTION CONTROL OPERATION HYDROCARBON CONTROL
Direct-Flame Afterburners
GENERAL INFORMATION
Process Function - Hydrocarbon control device which converts
combustible materials to C02 and H20 through direct com- ;
bustion.
Development Status - Commercially available.
Licensor/Developer - Not applicable.
Commercial Applications -
• Widely used in various industries to control hydro-
carbon emissions
__.pil, and grease.
carbon emissions from operations involving solvents,^
Applicability to Coal Gasification - Catalytic mftrnx-
burners should be a feasible process for controlling
hydrocarbon emissions in the tail gases from sulfur
recovery processes, streams produced by acid gas re-
moval systems during regeneration or other waste streams
containing hydrocarbons.
INFORMATION
Flow Diagram - See Figure 1.
Control Effectiveness - Dependent upon flame temperature and
other factors. See Figure 2 and Tables 1 and 2.
Operating Parameter Ranges -
• Temperature - See Table 3.
• Pressure - Atmospheric
C-35
-------
AIR*-
HYDROCARBON-FREE
QAS
/ x
COMBUSTION
CHAMBER
SFUEL
Figure 1. Typical Flow Diagram - Direct Flame Afterburner
C-36
-------
loor-
o
i
80
z
o
IT
t-
m
ta
o
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Z
< 4G
O
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20
600
1 SECOND
INCREASING
RESIDENCE
TIME
I
I
I
J
800
1OOO
1200
1400
1600
1800
2000
Figure 2. Effect of flame temperature and residence time on the control of hydro-
carbons emissions by direct flame afterburner.
-------
TABLE 1. TYPICAL ANALYSIS OF EMISSIONS ENTERING AND LEAVING
LARGE DIRECT-FIRED AFTERBURNER
CO 2, ppm
CO, ppm
Organics as
C02, ppm
Volume (dry basis),
Nm3/s (scfm)
Organics (as
(Ib/hr)
Afterburner
carbon) ,g/s
efficiency, %
Temperature
1030°K(1400°F)
In
6,300
59
1,568
5.7(12,000)
4.5(35.6)
Out
22,000
230
235*
5.6(11,800)
0.66(5.26)
85
1090°K(1500°F)
In
6,600
65
1,591
5.7(12,000)
4.6(36.2)
Out
27,000
21
70
'5.6(11,800)
0.20(1.6)
96
* Includes increase of CO across afterburner,
(Ref. 236)
TABLE 2. TYPICAL ANALYSIS OF EMISSIONS ENTERING AND LEAVING
SMALL DIRECT-FIRED AFTERBURNER
CO 2, ppm
CO, ppm
Organics as C02, ppm
Volume (dry basis) ,
NmVs (scfm)
Organics (as carbon) ,g/s
(Ib/hr)
Afterburner efficiency, %
. Temperature :
980°K(1300°F)
In
1,950
8
521
1.1(2,240)
0.28(2.21)
Out
19,000
110
122*
1.0(2,200)
0.06(0.50)
77
1030°K(1400°F)
In
2,000
9
408
1.1(2,240)
0.22(1.74)
Out
23,500
24
33a
1.0(2,
0.02(0
200)
.14)
92
*Includes increase of CO across afterburner.
XRef. 237)
C-38
-------
Raw Material and Utility Requirements -
Typical supplemental fuel requirements are shown in
Figures 3 and 4.
Dependent upon the composition of the stream to be
treated and the required control efficiency.
TABLE 3. THERMAL AFTERBURNER CONDITIONS
Afterburner
Abatement Category , Residence Time (sec) Temperature, °K(°F)
Hydrocarbons 0.3 - 0.5 &70-950 (1100-1250)
(90% + destruction)
Hydrocarbons + CO 0.3 - 0.5 95°-1090 (1250-1500)
(90% + destruction of HC + CO)
Odor
(50-90% destruction) 0.3 - 0.5 810-920 (1000-1200)
(90-99% destruction) 0.3 - 0.5 870*-980 (1100-1300)
(99% + destruction) 0.3 - 0.5 920-1090 (128&-1500)
(Ref. 238)
PROCESS ADVANTAGES
• Proven process for reducing the emission of hydrocarbons
and other combustibles.
May use existing boiler or furnace.
PROCESS LIMITATIONS
Normally requires supplemental fuel to raise gas stream
to combustion temperature.
C-39
-------
S.B
2.4
CO
5
8>0
*
2
IL
o
CO
£ 1.6
Q.
CO
(9
CC
£
U
CO
O.Br
0.4 h
BASIS:
OPERATING TEMPERATURE 1400'F
FUEL: NATURAL QAS
STOICIOMETRIC COMBUSTION AIR
FROM OUTSIDE
PPM C1 = 6x(PPM HEXANE)
200 400 600 800
AFTERBURNER INLET TEMPERATURE <*F)
*LEL - Lower Explosion Limit
Figure 3.
Supplemental fuel requirements (natural gas)--Direct
Flame Afterburners (Ref. 239)
C-40
-------
20
16-
3
01
3 12
u. '•
O
«1
Z
e
O 8
BASIS:
OPERATING TEMPERATURE: 14QO°F
FUEL: OIL
STOICHIOMETRIC COMBUSTION AIR
FROM OUTSIDE
PPM C1 : Bx(HEXANE)
200 400 600 800
AFTERBURNER INLET TEMPERATURE ("F)
*L1L - Lower Explosion Limit
Figure 4. Supplemental fuel requirements (fuel oil)--Direct
Flame Afterburners (Ref. 240)
C-41
-------
INLET GAS STREAM
The inlet gas stream to this process is composed of hydro-
carbons, H2, CO, C02, H20, and possibly small amounts of sulfur
compounds such as H2S and COS. These streams may be the tail
gas from sulfur recovery processes or streams produced by acid
gas removal systems during regeneration.
DISCHARGE STREAMS
The use of direct flame afterburners for hydrocarbon control
produces only one discharge stream, the treated gas (Stream No. 2)
This stream contains primarily C02, H20, N2, with possibly small
amounts of hydrocarbons and S02. It should be ventable to the
atmosphere with no further treatment.
C-42
-------
AIR POLLUTION CONTROL OPERATION HYDROCARBON CONl?ROL
Catalytic Afterburners
GENERAL INFORMATION
Process Function - Hydrocarbon control device which converts
combustible materials to C02 and H20 through catalytic
oxidation.
Development Status - Commercially available.
Licensor/Developer - Not applicable.
Commercial Applications -
• Paint drying ovens
• Wire enameling ovens
• Varnish cookers
Applicability to Coal Gasification - Catalytic afterburners
should be a feasible process for controlling hydrocarbon
emissions in the tail gases from sulfur recovery processes,
streams produced by acid gas removal systems during re-
generation or other waste streams containing hydrocarbons.
PROCESS INFORMATION
Equipment - A preheat burner section, a catalyst chamber,
heat recovery equipment.
Flow Diagram - See Figure 1.
Control Effectiveness - Function of many variables such as:
• Catalyst surface area
• Catalyst type
T*
• Flow uniformity through catalyst
• Qxygen concentration
C-43
-------
\
PREHEAT
BURNER
CATALYST
CHAMBER
SPENT
CATALYST
-$FUEL
HYDROCARBON-FREE
GAS
Figure 1. Typical flow diagram - Catalytic Afterburner
-------
• Temperature
• Volume of gases per volume of catalyst per unit time
• Presence of catalyst poisons in inlet gas
Typically, 90 percent removal of combustibles can be
achieved (see Figure 2).
Operating Parameter Ranges -
• Temperature - see Table 1
• Pressure - atmospheric
Raw Materials and Utility Requirements -
• Catalyst makeup - A typical catalyst would consist
of an active noble metal deposited on a support
material such as alumina.
* Fuel - Typical supplemental fuel requirements are
shown in Figures 3 and 4.
TAiU 1. TBffWAWWS FOR CATALYTIC OXIDATION
Component
Hz
CO
Propane
n-Pentane
n-Heptane
a-Decane
Benzene
Toulene
Xylene
Methane
Thiophene
Ignition Temp. Minimum Preheat Temp, for 90% conversion with
F organic concentration 10% LEL*
68
300
320
320
320
320
355
340
390
750
635
Acres
68
300-390
480-570
480-570
480-570
480-570
480-570
480-570
480-570
840-930
750-840
Miller &
Sowards
480
480
480
480
572
Thomiades
250
500
500
575
575
575
932
Romeo &
Harsh
32
600
660
570'
570 ' a
570-
500
570 '
800
(Kef. 241)
* - Lower Bxploiicm Level
• - Naphtha •
Note: AlaOi base catalyst
•K - <»? + 460)/1.8
C-45
-------
too
8O
6O
i
-P-
at
ff
ui
o
u
40
600
800
1000
Figure 2,
0 '200 400
TEMPERATURE. °F
Catalytic Afterburner performance for Pt/Al203 catalyst CRef. 242)
1200
-------
1.4
1.2
Ul
CO
a
u.
O
(0
w
CO
cc
£
O
w
1.0
0.8
0.6
0.4
0.2
BASIS:
TEMPERATURE OUT OF BED: 900°F
FUEL: NATURAL GAS
STOICHIOMETRIC COMBUSTION AIR
FROM OUTSIDE
PPM C1 = 6x(PPM HEXANE)
200 400 600 800
AFTERBURNER INLET TEMPERATURE CF)
1000
Figure 3. Fuel consumption (natural gas)--Catalytic Afterburners
(Ref. 243)
C-47
-------
to
to
o
E
E
Ul
0.
TEMPERATURE OUT OF BED: 900°F
FUEL: OIL
STOICHIOMETRIC AfR FROM OUTSIDE
PPM CV6X(PPM HEXANE)
200
400
600
600
1000
AFTERBURNER INLET TEMPERATURE, °F
Figure 4. Fuel consumption (fuel oil)--Catalytic Afterburners
(&ef. 244)
C-48
-------
PROCESS ADVANTAGES
Requires less supplementary fuel than direct
flame afterburners.
PROCESS LIMITATIONS (Ref. 245)
Catalyst degrades and requires periodic replacement.
Catalyst is susceptible to poisons such as mercury,
arsenic and lead.
Incomplete combustion can cause discharge of gases
that are odorous and eye irritating due to the
presence of aldehydes, ketones and organic acids.
INLET GAS STREAM
The inlet gas stream to this process is composed of hydro-
carbons, H2, CO, COz, H20, and possibly small amounts of sulfur
compounds such as H2S and COS. These streams may be the tail
gas from sulfur recovery processes or streams produced by acid
gas removal systems during regeneration.
DISCHARGE STREAMS
The use of catalytic afterburners for hydrocarbon control
produces two discharge streams. These discharge streams are:
Air Emissions
- Treated Gas (Stream No. 2)
Solid Wastes
- Spent catalyst (Stream No. 3)
These discharge streams are discussed below.
Treated Gas - The treated gas stream contains primarily
C02, HaC7, NV, with possibly small amounts of hydrocarbons and
S02. This stream should be ventable to the atmosphere with no
further treatment.
C-49
-------
Spent Catalyst - The spent catalyst may be sent to the
catalyst manufacturer for regeneration. If not, it represents
an environmental concern in the fbrm of a solid waste.
C-50
-------
AIR POLLUTION CONTROL OPERATION HYDROCARBON CONTROL
Carbon Adsorption
GENERAL INFORMATION
Process Function - Control process which removes hydro-
carbons from gas streams by carbon adsorption with subse-
quent thermal regeneration of the carbon.
Development Status - Commercially available.
Licensor/Developer - Not applicable.
Commercial Applications -
• Recovery of organics from manufacturing operations
• Removal of hydrocarbons and other contaminants
(e.g., sulfur compounds) from gas streams
Applicability to Coal Gasification - Technically feasible
process for controlling hydrocarbon emissions from 1) tail
gases from sulfur recovery processes, 2) streams produced
in acid gas removal systems during regeneration, or 3) other
waste streams containing hydrocarbons.
PROCESS INFORMATION
Equipment - Absorbers containing activated carbon beds,
coolers
Flow Diagram - See Figure 1.
Control Effectiveness - Typically, 99+ percent removal of
hydrocarbons can be obtained.
Operating Parameter Ranges -
• Temperature
- Sorption: less than 320°K (120°F)
Regeneration: highly dependent on gases
absorbed. Temperature up to 620°K (650°F)
C-51
-------
CLEAN AIR TO
ATMOSPHERE
ADSORBER
AIR COOLER
CW
o
i
FEED
-
CW
AIR BLOWER
-CX!
ADSORBER
ADSORBER
AIR COOLER
STEAM
XJ -
Vcxi —
/CXI— »-
TO
INCINERATOR/
BOILER
Figure 1. Simplified flow scheme - carbon adsorption
-------
may be required for complete regeneration of
some systems (Ref. 246)
• Pressure: Not pressure sensitive
Raw Material and Utility Requirements - Basis: Per
0.454 kg (1 Ib) of solvent recovered.
• Steam: 1.8 kg (4 Ib)
• Electricity: .082 kWh
• Cooling water: 0.03 m3 (8.75 gal)
• Activated carbon
makeup:
PROCESS ADVANTAGES
Highly efficient hydrocarbon removal process
• Also removes CO and sulfur compounds
PROCESS LIMITATIONS
• Regeneration produces a hydrocarbon rich stream which
must be disposed of.
• Normally only used for treating gas streams with low
hydrocarbon concentrations.
INLET STREAMS
Inlet Gas Stream - The inlet gas stream to a carbon
adsorption process is composed of hydrocarbons, N2, C02, with
smaller quantities of CO, H2, and some sulfur compounds. The
amounts of each compound present will depend upon the source
of the waste gas.
DISCHARGE STREAMS AND THEIR CONTROL
Treated Gas - The treated gas will contain C02, N2, H20 and
small quantities of contaminants (principally hydrocarbons)
C-53
-------
present in the feed gas. This stream should be ventable to the
atmosphere with no further treatment required.
Regenerator Offgas - The regenerator offgas will mainly con-
tain CO z* H20, and hydrocarbons. The amounts of each of these
components will depend upon the inlet gas composition and the
amount of steam used during regeneration. This stream may have
a high enough fuel value to sustain combustion in an incinerator
with no supplemental fuel required.
Spent Activated Carbon - Since activated carbon can be re-
cycled to the manufacturer for reactivation, it is not an
environmental problem with respect to the coal gasification plant,
C-54
-------
APPENDIX D
WATER POLLUTION CONTROL
-------
WATER POLLUTION CONTROL REMOVAL OF SUSPENDED
SOLIDS AND OILS
Flocculation-Flotation
GENERAL INFORMATION
Process Function - Flocculation involves the addition of
chemical additives to coagulate any finely divided solids
that are present in the wastewater. Flotation uses air
bubbles to raise the oil droplets to the water surface
where they are skimmed off.
Development Status - This process combination is widely
used to remove suspended solids and oils from water.
Licensor/Developer - Not applicable.
Commercial Applications - Presently used in the refining
industry when the removal of solids and free oils from
water1 is required.
Applicability to Coal Gasification - Because of its capabili-
ties, this technique should be applicable to the purification
of coal gasification plant wastewaters.
PROCESS INFORMATION
Equipment - Mixer, clarifier, air sparger. '}
Flow Diagram - See Figure 1.
Control Effectiveness - An example of the results that can
be obtained by flocculation-flotation is given below (Ref. 247).
• BOD reduced by 80%.
• COD reduced by 80%.
Suspended solids reduced by 75%.
Free oils reduced by 977o.
D-2
-------
MIXER
WASTE
FLOCCULATING
AGENT
OILY SCUM
FLOCCULATING
CHAMBER
FLOTATION
CHAMBER
WASTE
SLUDGE
AIR
•»• CLARIFIED EFFLUENT
Figure 1. Suspended oil removal by flocculation-flotation (Ref. 248)
-------
Operating Parameters (Ref. 249) -
Temperature - can effect this process, however, no
temperature or temperature ranges were specified
Pressure - usually atmospheric
pH - acidic level best (optimum ^5)
Raw Material Requirements - The raw materials required for
flocculation are listed below; however, the required amounts
of these chemicals are not specified (Ref. 250).
Alum
Lime
Polyelectrolyte
Utility Requirements -
Electricity - required for pumps, air compressor, skimmer
PROCESS ADVANTAGES
Effectively reduces the concentration of suspended oils
and solids in the wastewater.
Relatively inexpensive process for reducing suspended
solids and oils.
PROCESS LIMITATIONS
• Flocculation-flotation is sensitive to
- Temperature change.
- Wastewater pH
- Fluctuations in hydraulic or suspended solids loading
Type and size of mixing pump significantly affect results
obtained with flocculation.
D-4
-------
INPUT STREAMS
Wastewater containing suspended solids, non-emulsified
oils, dissolved organics, and dissolved inorganics
(Stream No. 1).
Chemical additive for coagulating suspended solids
(Stream No. 2).
DISCHARGE STREAMS AND THEIR CONTROL
Clarified Effluent (Stream No. 3) - This effluent is fret of
suspended solids but still contains dissolved organic and
inorganic contaminants that must be removed before the water
can be discharged. The treatment that will be required may
include solvent extraction, acid gas stripping, biological
treating, etc.
Waste Sludge (Stream No. 5) - This sludge is comprised of
solids and water. Before its disposal the sludge must be
dewatered, which is usually achieved by gravitational tech-
niques. Once the sludge is dewatered it can be disposed of
in a landfill. The water is usually sent to a holding pond
to allow the suspended solids to settle before the water is
discharged, reused or further treated.
Oily Scum (Stream No. 4) - This effluent stream contains
oil and flocculant that have been skimmed from the surface
of the wastewater. This material can be incinerated or
disposed of with the sludge in an evaporation pond.
D-5
-------
WATER POLLUTION CONTROL REMOVAL OF FREE OIL
AND SUSPENDED SOLIDS
Oil-Water Separators
GENERAL INFORMATION
Process Function - Gravity separators remove non-emulsified
oils and suspended solids that are present in the wastewaters
from chemical and petrochemical processes. Corrugated plate
interceptor separators use parallel plates to induce faster
settling.
Development Status - Extensively used in refineries.
Licensor/Developer - API Separator: developer unknown.
CPI Separator: patented by Shell Oil Co,
Commercial Applications - Presently used in any industry
which requires the separation of non-emulsified oils and
solids from water.
Applicability to Coal Gasification - Because oil and solids
are present in coal gasification wastewaters, gravity
separation should be an effective initial cleanup process.
API separators are presently used in the SASOL coal gasifica-
tion complex in South Africa.
PROCESS INFORMATION
Equipment - Separation pit, inlet weir, outlet weir, oil
skimmer7~corrugated plate interceptor (CPI).
Flow Diagram - See Figure 1, CPI Separator.
Control Effectiveness -
• General for API Separator (Ref, 251):
- Removes oils with 60-99% efficiency.
- Removes solids with 10-50% efficiency.
D-6
-------
O
i
ADJUSTABLE
OUTLET WEIR
VENT GAS
OIL LAYER
ADJUSTABLE
INLET WEIR
CLEAN WATER
OUTLET CHANNEL
CONCRETE
SLUDGE PIT
... /
=*
-------
Specific for API Separator (Ref. 253):
- Reduces non-emulsified oil concentrations by 90%.
Reduces suspended solids concentrations by 90%.
- Reduces BOD by 80%.
Specific for CPI Separators (Ref. 254):
TABLE I
Distilling Unit CPI
"Set A"
Flow Rate,
GPM
Water Oil
215 0.40
150 0.36
150 0.25
230 0.67
315 0.17
686 2.32
900 2.09
1276 2.76
1200 2.47
1134 2.57
..
Flow Rate,
GPM
Water Oil
310 0.10
343 0.92
382 0.23
431 1.62
Calculated
Separated Oil
Influent Oil Effluent Oil
Content,
PPMV
1860
4170
1670
2910
540
3410
2370
2230
2160
2330
Catalytic
Calculated
Content,
PPMV
8
6
35
20
5
"Set B"
27
46
64
105
61
TABLE II
Cracking
Oil
Recovered ,
%V
99.6
99.9
97.9
99.3
99.1
99.2
98.1
97.1
95.1
97.4
Unit CPI
Grav.
°API
30.6
32.4
33.3
33.0
31.5
30.0
30.0
29.4
30.1
30.5
-
Water
Content
PPMV
255
250
480
765
830
1315
1540
2550
415
2580
— - -
Separated Oil
Influent Oil Effluent Oil
Content,
PPMV
340
2710
650
3780
Content,
PPMV
12
30
25
52
Oil
Recovered »
%V
96.5
98.9
96.2
98.6
Grav.
"API
34.5
29.3
25.9
25.3
Water
Content
PPMV
136
224
148
695
D-8
-------
TABLE III
International Lubricant Corp.
CPI
Calculated
Flow Rate, Influent Oil
GPM
Water
83.5
120
700
Oil
.209
.211
.74
Content,
PPM
2503
1758
1057
Effluent Oil
Content,
PPM
13
21
60
Oil
Recovered,
%
99.5
98.8
94.3
Recovered Oil
Water Content
%
3.5
3.5
3,5
Operating Parameters -
• Flowrates - See above.
Pressure - Generally atmospheric pressure.
• Temperature - Although this process can tolerate signi-
ficant temperature variations, high temperatures in-
fluence the viscosity and droplet size of the oil;
this will, in turn, affects the performance of the
separator.
Utility Requirements CRef. 255) -
Energy consumers
- Flight scrapers
- Oil skimmers
Sludge, oil, water pumps
• Typical energy consumption for gravity separation unit
(Ref. 256):
Equipment W (Hi>) , W-hr/m3/sec (Hp-hr/1000 GPM)
2 flight skim./sep. 559.5 (0.75 ea.) 295.61 (.025)
2 skimmed oil pumps 373.0 (.50) 484.8 (.041)
1 sludge pump 5595 (7.5) 744.93 (.063)
1 effluent pump 3730.0 (5.0) 2956.09 (.25)
4481.43 (.379)
D-9
-------
Process Sensitivity (Ref. 257) - Oil-water separation
efficiency is influenced by:
Wastewater temperature
• Density and size of oil droplets (settling velocity)
• Types of solids in the water
Attached is a graph (Figure 2) that correlates specific
gravity of the oil, plate surface area per unit flow and
concentration of oil in the effluent for a CPI separator.
This correlation shows the size of separator required at
a given flow rate to obtain an effluent having a specified
oil content.
PROCESS ADVANTAGES
• Simple and effective way to remove non-emulsified oils
and solids from wastewater
Low energy consumption
• High reliability
PROCESS LIMITATIONS
• Can require large amounts of space
Effluent streams require further control
• Only effective for separation of non-emulsified oils
INPUT STREAMS
The input stream consists of wastewater containing free oil,
emulsified oils, and suspended solids. Typical raw water charac-
teristics are (Ref. 258):
Suspended solids - 3500 ppm
• Non-emulsified oils - 1300 ppm
D-10
-------
A 6.84-086 Sp. Of.
00,87-0.89 Sp. Gr.
0.90-092 Sp. Gr
Q 0.93-0 55 Sp.Gr.
' »(00 *
SURFACE AREA/FLOW {SO.FT./CFM)
' 1,000
'10,000
Figure 2. Correlation of API effluent oil content with operating
factors (Ref. 259)
D-ll
-------
Phenol - 20 ppm
• BOD - 4000 ppm
DISCHARGE STREAMS AND THEIR CONTROL -
General - Discharge streams from an oil-water separator are:
• Vent gas from the separator (if the separator is enclosed)
(Stream No. 1)
• Effluent water (Stream No. 2)
Oil skimmed from water's surface (Stream No. 3)
Sludge (solids) (Stream No. 4)
Specific -
• Separator Vent Gases - These are gases that are relatively
insoluble in the was^tewater. The gases consist primarily
of C02, CHi,, N2, CgHe, and some H2S and NH3. Because the
volume of these gases is expected to be small at ambient
conditions, it is unlikely that any control will be re-
quired for this stream.
* CPI Separator Effluent Water - The effluent from the
separator will contain emulsified oil, some suspended
solids, and dissolved organics and inorganics.
Based upon the raw water composition shown above, a typi-
cal effluent water composition is:
Suspended solids - 100 ppm
Non-emulsified oils - 50 ppm
Phenol - 15 ppm
BOD - 200 ppm
Before its discharge or reuse this water must be treated
in subsequent processes (biological oxidation, acid gas
stripping, etc.) to further reduce the concentrations of
these components.
• Recovered Oil - This is the oil that is skimmed from
the surface of the water. In industry, this oil is
withdrawn and generally burned in an incinerator or a
boiler.
D-12
-------
Slud
ge - This waste is composed primarily of solids that
le out in the separator. This material is periodi-
settle out in the separator.
cally removed from the separator and is either sent
directly to a solar evaporator or to a mechanical de-
watering system, then to final disposal in a landfill.
D-13
-------
WATER POLLUTION CONTROL REMOVAL OF SUSPENDED
SOLIDS AND OILS
Filtration
GENERAL INFORMATION
Process Function - The primary function of filtration is to
reduce the concentrations of suspended contaminants in
aqueous streams so that problems caused by solids in
subsequent treatment processes are minimized.
Development Status - A well-developed technology.
Li censor/Developer - No licensor cited; however* commercially
available from numerous suppliers of filtration equipment.
C omme r c i a1 App1i cat ions - Filtration is extensively utilized
in many indusitrles such as the refinery industry to. remove
suspended oils and solids from wastewater.
Applicability to Coal Gasification - Filtration is presently
being utilized in the wastewater treatment system at the
SASOL Coal Gasification complex in South Africa.
PROCESS INFORMATION
Equipment - Pumps, vessels containing filter media.
Flow Diagram - See Figure 1.
Control Effectiveness - Although there are different types
of filter media, only the control effectiveness of sand
filtration is cited here (Ref. 260):
• BOD5 removal - 36%
• COD removal - 25 to 44%
Suspended oil removal - 52 to 83%
Suspended solids removal - 70 to 7570
Operating Parameters - Wide ranges of temperature and pressure
can be tolerated.
D-14
-------
i
M
Ui
To parallel system
(for use during
backwashing)
WASTEWATER
BACKWASH WATER
FILTER
MEDIA
FILTERED EFFLUENT
Figure 1. Scheme for suspended solids and oil removal by filtration
-------
Raw Material Requirements - Normally, no raw materials are
required; however, in some instances chemical additives may
be used.
Utility Requirements - Normally power, steam and water (for
backflushing);quantities will depend upon application.
PROCESS ADVANTAGES
Effectively reduces the concentration of suspended oils
and solids in the wastewater.
Easily maintained.
Relatively inexpensive.
Has been successfully applied in a coal gasification
complex.
PROCESS LIMITATIONS
• The system must be regenerated by backwashing, which
generates a stream contaminated with suspended solids
and oils.
Backwashing effluent can be disposed of by incineration
or landfilling; however, both must be closely controlled.
INPUT STREAMS
Wastewater (Stream No. 1) - This stream contains suspended
solids and oils, dissolved organics, and dissolved inorganics
DISCHARGE STREAMS AND THEIR CONTROL
Filtered Wastewater (Stream No. 2) - This stream, which con-
tains dissolved organics, dissolved inorganics, and residual
quantities of suspended solids and oils, will normally re-
quire further treatment prior to disposal or reuse. Poten-
tially applicable treatment processes include solvent
extraction, carbon adsorption, acid gas stripping aiid forced
evaporation.
D-16
-------
Backwash Water - This effluent consists of water and con-
taminants washed from the filter media. This stream can
be recycled to the process, treated further, or disposed of
by incineration or landfilling.
D-17
-------
WATER POLLUTION CONTROL SOLVENT EXTRACTION
Phenosolvan
GENERAL INFORMATION
Process Function - Removal of phenols from wastewater streams
by liquid-liquid extraction.
Development Status - 32 commercial installations since 1940.
Licensor/Developer - Lurgi Mineralotechnik GmbH
American Lurgi Corporation
377 Rt. 17 South
Hasbrouck Heights, New Jersey
Commercial Applications - Removal of phenols from coke oven
and gasification plant aqueous waste streams.
Applicability to Coal Gasification - Proven process; used in
coal gasification complexes located in:
• Sasolburg, South Africa (SASOL)
Kosovo, Yugoslavia
PROCESS INFORMATION
Equipment - Mixer-extractor; distillation column for solvent
recovery.
Flow Diagram - See Figure 1.
Control Effectiveness - (Ref. 261, 262) -
General -
99.5% removal of monohydric phenols
- 60.0% removal of polyhydric phenols
- 15.0% removal of other organics
Specifically -
- 95% total organics removed at SASOL
D-18
-------
GAS LIQUOR
o
i
h-«
VO
SOLVENT DISTILLATION COLUMNS
LEAN SOLVENT
GRAVEL BED FILTER
GAS LIQUOR
tc.
o
cr
ui
c
1
PHENOL-RICH
1 t
MIXER-SETTLER
SOLVENT
RAFFINATE
*"T
J
/•"
i
V
so
HEAT
xB>
LVE
NT
f
MAKE-UP
^n
SCRUBBING PHENOLS
N2 GAS
CRUDE
PHENOL STRIPPER
HEAT
PHENOL
PHENOLS
EFFLUENT
GAS SCRUBBER QAS SCRUBBER RAFFINATE STRIPPER
(PHENOL RECOVERY) (SOLVENT RECOVERY) (SOLVENT RECOVERY)
Figure 1. Phenosolvan process flow (Ref. 263)
-------
Normal Operating Parameters -
Pressure - Atmospheric
• Temperature - 343.2°K (158°F) at SASOL, otherwise dependent
on solvent.
Solvent Used (Ref. 264) -
Distribution
Locale Solvent Coefficient Boiling Point
Sasol butyl acetate 49 397.7"K (256.1°F)
Proposed U. S.
(New Mexico) Gasi-
fication Complexes isopropyl ether 20 337.7°K (148.0°F)
General light aromatic oil ^22 varies with solvent
Solvent Solubility (Ref. 265) -
Solvent Solubility in Water @ 308.2°K (95QF)
butyl acetate 17o by wt.
isopropyl ether . 87<> by wt.
Utility Requirements - Basis: Utilities per 3.79 m3 (1000
gal.) (Ref. 266).
• Cooling H20 - 5.68 m3 (1500 gal.)
• Electrical Power - 4-6 kWh
• Steam - 36.3-122.5 Kg
PROCESS ADVANTAGES
General - Economically attractive technique for phenol
removal and recovery
Specific - Solvent has:
- Relative low volatility.
- Low solubility in water.
- High distribution coefficient.
D-20
-------
PROCESS LIMITATIONS
Solvent - Soluble enough in water to require its recovery.
Process - Initial process investment is substantial.
INPUT STREAMS
Basis: Attached flow diagram (Figure 1), which is the
tentative design for two New Mexico complexes.
Phenol-rich gas liquor (Stream No. 1).
Steam for phenol, acid gas, and NH3 strippers (Stream
No. 2).
N2 makeup for solvent recovery (Stream No. 3)
DISCHARGE STREAMS AND THEIR CONTROL
The discharge streams generated by the Phenosolvan process
are listed below for both a general and a specific (WESCO) design .case,
General - Output streams are:
Dephenolized liquor - is the effluent wastewater,. and
contains traces of phenols, solvent, other dissolved
organics, and dissolved acid gases. Although the waste-
water has had the bulk of the dissolved phenols removed
from it, the resulting effluent will still require the
use of a polishing process such as carbon adsorption,
biological oxidation, or cooling tower air stripping.
The effluent may also contain significant gmountjs of
dissolved acid gases that will require further control
(Stream No. 5).
• By-product phenols - are high purity phenols obtained
when the solvent is regenerated (Stream No. 4).
Specific -
Flows -
.17 m3/sec dephenolized water
1.10 kg/sec extracted crude phenol
D-21
-------
Compositions -
w Influent Gas Liquar Composition (Stream Ho,...J»>.=
Monohydric phenols
Polyhydric phenols
Other organics
Ibs/hr
7475
1458
2913
(kg/hr)
3390.6
661.3
1321.3
PPM
5537
1080
2158
Totals (water-free)
11846 5146.5
- Dephenolized Liquor Composition (Stream No. 5):
Ibs/hr (kg/hr)
PPM
Monohydric phenols
Polyhydric phenols
Other organics
Totals (water-free)
By-Product Phenols (Stream
phenols which are disposed
approximate composition of
Monohydric phenols
Polyhydric phenols
Other organics
37
583
2476
3096
No. 4)
of as
these
Ibs/hr
7438
875
437
16.80
262.40
1114.20
1393.40
: These are
27
432
1834
the extracted
a by-product. An
phenols follows :
(kg/hr) Wtl
3347.1
393.8
196.7
85
10
5
Totals (water-free)
8750 3937.6
100
D-22
-------
WATER POLLUTION CONTROL DISSOLVED ORGANICS REMOVAL
Adsorption of Dissolved Organics
GENERAL INFORMATION
Process Function - In wastewater treating adsorption can be
adequately utilized as either a primary, secondary, or
tertiary treatment process.
Development Status - Adsorption is currently being used in
varied industrial applications.
Licensor/Developer - No specific developer cited; however
several companies market carbon adsorption processes com-
mercially.
Commercial Applications -
General - Used to remove dissolved organics from waste
streams regardless of their origin.
Specific - Applied to upgrading waste streams in the
following industries:
Detergent manufacturing in New Jersey.
- Oil refining in California and Pennsylvania.
Chemicals manufacturing in Alabama.
Resin manufacturing in New York.
- Herbicide manufacturing in Oregon.
- Coking plants in Pennsylvania.
PROCESS INFORMATION
Special Consideration for Coal Gasification Applicability -
Since phenols are a valuable by-product of coal gasification,
adsorption should be considered as only a tertiary (polishing)
process for coal gasification effluents because phenols are
essentially unrecoverable once they are adsorbed.
D-23
-------
Equipment Requirements -
Adsorbers
Hydraulic transfer system for regenerated adsorbent
Adsorbent regeneration facilities
Flow Diagram - See Figure 1.
Control Effectiveness (Ref. 267) - Adsorption .has performed
well in removing dissolved organics from waste-water streams.
Because of economic considerations it is normally used only
when a water of high quality is desired. Adsorptioti has
exhibited the following removal efficiencies:
• Phenol - 99%
• COD - 81%
• Cyanide - 1%
Production Rates - Quantity of water treated by adsorption
ranges from < .002 m3/sec to .21 m3/sec ( 35 gpm - 3300 gpra)
Operating Parameters -
• Pressure: atmospheric
Temperature: No operating temperature specified; however,
carbon adsorption is more effective at high temperatures
than at low temperatures.
Adsorbents -
General traits of good adsorbent (Ref. 268):
High selectivity
Regenerable
Chemically inert
Inexpensive
Specific adsorbents:
- Activated carbon
- Synthetic polymer
D-24
-------
MAKEUP CARBON
i-fX
INFLUENT
WATER
FILTER BEDS
OF
CLARIFIER
SURGE
STORAGE
_, suinRF.
O
i
K>
Ui
PRODUCT
WATER
FUEL
EXIT
QUENCH
WATER
Figure 1. Wastewater stream treatment by activated carbon adsorption (Ref. 269)
-------
Regeneration of Adsorbent (Ref. 270, 271) - The sp'ent ad--
sorbent is regenerated by subjecting it to a high temperature
(^1144°K) in order to oxidize the adsorbed organic pollutants,
The hot adsorbent is cooled with quench water and returned
to service. Regeneration of the adsorbent results in the
following:
'v»5-107o carbon loss if activated carbon is used as the
adsorbent (Ref. 272, 273)
Dirty water as the result of cooling the adsorbent
(Ref. 274).
High energy consumption.
Adsorption Sensitivity - Pressure does not significantly
affect the adsorption process. However, the adsorption of
dissolved organics can be enhanced by slightly lowering the
pH level of the waste stream. Higher temperatures also en-
hance the adsorption efficiency.
Utility Requirements - Specific utility information was
unavailable.The utilities required in general for an
adsorption process are identified below.
Electricity for:
- Hydraulic transfer pumps
Quench water pumps
- Wastewater pumps
Cooling water for quenching the regenerated adsorbent
Fuel required for heating the regeneration gas
Chemicals to adjust the pH level of the wastewater
Economics (Ref. 275) - Basis: Phenol reduced from 110 ppm to
1 ppm; .01 m3/sec throughput (150,000 gal/day).
Investment cost was $300,000
• Operating cost was $.094/m3 (35.6C/1000 gal)
D-26
-------
PROCESS ADVANTAGES
General - Adsorption makes it economically possible to
purify streams that contain only small amounts of im-
purities that would otherwise be impossible to clean
(Ref. 276).
Specific -
• Adsorption has high ability to reduce impurity concen-
tration at ambient conditions (Ref. 277).
Adsorption is not affected by slight temperature change,
fluctuations in organic loading or toxicity (Ref. 278;.
• Adsorption has wide applicability to many industrial
wastewater problems.
Adsorption is not upset by fluctuations in hydraulic
rates (Ref. 279).
PROCESS DISADVANTAGES
Since adsorption does not allow easy recovery of: .,
adsorbed dissolved organics, regeneration of the
adsorbent is necessary (Ref. 280).
Regeneration of adsorbent generates aqueous and gaseous
streams that may require further control.
Regeneration of adsorbent may not be complete,
therefore, the removal efficiency of the absorbent
may decrease with time (Ref. 281).
INPUT STREAMS
Wastewater (Stream No. 1) - This influent is a water stream
containing dissolved monohydric and polyhydric phenols.
It may also contain some suspended and dissolved inorganic
contaminants.
D-27
-------
DISCHARGE STREAMS AND THEIR CONTROL
Quench Water (Stream No. 5) - This stream is generated when
water is used to cool the regenerated carbon. Because of
the carbon losses experienced in regeneration, this stream
can become contaminated with suspended solids. The solids
can be removed by gravity separation.
Vent Gas (Stream No. 2) - This stream is generated when the
activated carbon undergoes thermal oxidation to destroy
adsorbed organics. This stream consists primarily of C02
and CO •'but may contain some hydrocarbons. It is not certain
that this stream will require control. However, if further
control is necessary, a scrubbing system will be necessary.
Treated Effluent (Stream No. 3) - This stream should be free
of dissolved organics and suspended contaminants. However,
it may contain some dissolved inorganic contaminants. The
desired quality of this effluent will dictate the need for
any further treating. Cooling tower oxidation or activated
sludge processes can be used to further treat this stream.
Backwash Water (Stream No. 4) - This stream is generated
when water is used to wash away any solids that have collec-
ted on the carbon. This stream must be reprocessed to
remove any contaminants that it contains.
D-28
-------
WATER POLLUTION CONTROL DISSOLVED ORGANICS REMOVAL
Biological Oxidation of Dissolved Organics
GENERAL INFORMATION
Process Function - Biological oxidation processes involve
the use of bacteria and other microbes for the removal of
dissolved organics from waste streams. For its application
to coal conversion processes, biological oxidation is best
suited for use as a tertiary treatment process because by-
product recovery is not economically practical with this
process.
Development Status - Various biological oxidation technique*
are presently being utilized for upgrading various industrial
waste streams.
Licensor/Developer -
Koppers: earliest known developer
Numerous available including:
- UNOX (by Union Carbide)
Reuse Bio-oxidation Process (Sun Oil)
Commercial Applications (Ref. 282) - This process is presently
used to remove dissolved organics from waste streams origina-
ting from:
• Petrochemical industry
• Paper mills
Pharmaceutical manufacturing
• Brewery
Meat packing
• Coke oven plants
Applicability to Gasification - Biological oxidation is
being used in the above industries to remove dissolved
organics that closely approximate those that are predicted
to exist in the waste streams from a low-Btu coal gasifica-
tion complex.
D-29
-------
Locations - A biological system is presently being
utilized at SASOL.
PROCESS INFORMATION
Flow Diagram - See Figura 1.
Special Consideration for Coal Gasification Applicability -
Because phenols are a valuable by-product of coal gasifica-
tion and should be recovered from waste streams, biological
oxidation should be considered for use as a polishing process
only.
Types of Biological Oxidation -
Aerobic
Anaerobic
Process Methods -
Activated sludge
• Trickling filter
Cooling tower oxidation (air stripping)
• Aerated lagoons
Waste stabilization ponds (aerobic)
Anaerobic digestor
Effectiveness of Methods (Ref. 283) -
Range of % Removal
Sulfides BOD COD S. Solids Oil Phenols
Activated sludge 97-100 88-90 60-85 95-99+
Trickling filters 60-85 30-70 50-80 50-80
Waste Stab. Ponds
(Aerobic) 40-95 30-65 20-70 50-90
Aerated lagoons 95-100 75-95 60-85 40-65 70-90 90-99
Cooling tower oxidation
(air stripping) 90+ 90+ 99.9
Note: Thiocyanates ^70% removed by all processes
D-30
-------
to
AERATION TANK
INFLOW
-S>r
BACTERIA
ORGANICS+O2
DIFFUSED AERATION
AIR <2
CLARIFIER
EFFLUENT
SLUDGE
Figure 1. Simplified schematic of conventional plug flow activated sludge
(Ref, 284)
-------
Operating Parameter Ranges (Activated Sludge) (Ref. 2B5) -
Information on others unavailable.
Pressure: atmospheric
• Temperature: optimum range 290-310°K (60-100°F)
Production Range (Activated Sludge) (Ref. 286) *"Information
on other biological treating processes unavailable.
Minimum flow: 2.19 x 10~6 m3/sec (50 gal/day)
• Maximum flow: .02 ma/sec (400,000 gal/day)
«
Process Sensitivity -
Temperature: Biological oxidation of dissolved organics
is optimum in the temperature range of 190-31Q°K (60-
100°F). In this range, as the temperature increjises
so does the oxidation of dissolved organics. However,
when the maximum temperature is exceeded the micro-
organisms are adversely affected and the stability
of the biological oxidation process is upset (Ref. 287).
pH: The pH level of the waste stream is the most im-
portant factor influencing the efficiency of biological
oxidation. The optimum pH level is ^7.0; when the pH
is below 5.5 or above 9.5 most micro-organisms can not
exist. The pH level also influences the efficiency of
thiocyanate removal (Ref. 288).
Presence of Oxygen: Oxygen is required for oxidation
of organics in the waste stream. The greater*theaamount
of 02 available, the more able the process is to resist
shock organic loadings (Ref. 289).
Organic and Hydraulic Loading: Biological oxidation
is highly dependent upon both organic and hydraulic
loadings. As the organic loading increases, the percent
organic oxidized decreases, but the amount oxidized
increases. The optimum feed to micro-organism ratio is
.2-.5:1.0. An excessive hydraulic loading results in
a foaming of trickling filters and a decrease in efficiency
of biological oxidation (Ref. 290).
Heavy Metals: The presence of heavy metals can have an
adverse effect on the efficiency of the biological oxi-
dation process, particularly if a rapid change in
their concentration occurs (Ref. 291).
D-32
-------
• Nutrients: Nitrogen (usually in the form of ammonia)
and phosphorus must be present in the waste stream in
order to keep phenol oxidation at its optimum level
(Ref. 292).
Utility Requirements - Specific information is unavailable.
General utilities required for specific biological processes
are listed below.
• Activated sludge
- Electricity for pumps, air or 02 compressor, sludge
mixers.
Trickling bed
- Electricity for pumps, compressor, waste distributor
• Aerated lagoon
Electricity for pumps, aerators
Cooling tower oxidation (air stripping)
- Electricity
Economics -
• Capital Investment (Ref. 293):
- Trickling filters - $1.58 x 107 per m3/sec for a .01
m3/sec plant ($1000/gpm for 100 gpm plant), $7.9 x 106
per m3/sec for a .03 m3/sec plant ($500/gpm for 500
gpm plant).
- Activated sludge - cost range for industrial applica-
tion $6.6 x 10* - 3.5 x 107 m'/sec ($420 - $2240/gpm);
cost range for municipal application $9.2 x 106 mVsec
for .04 m3/sec ($580/gpm for 700 gpm); $2.95 x 107
m3/sec for 4.4 x 10"" m3/sec ($l,860/gpm for 7 gpm)
- Oxidation ponds - $.25/m2 ($1000/acre)
• Operational Costs (Ref. 294):
- Trickling filters - $15,,850 per m3/sec ($l/gpm) of
waste flow per year
- Activated sludge - $2.4 x 105 per m3/sec ($15/gpm) of
waste flow per year
D-33
-------
PROCESS ADVANTAGES
Effectively reduces the BOD and phenol level in industrial
wastewater.1
Has wide applicability to industrial applications and has
been proven in several applications.
Comparatively inexpensive water"treating process.
Removes some amounts of trace metals, ammonia, and
cyanides that may be present in waste (small when compared
to phenol).
PROCESS LIMITATIONS
Highly sensitive to pH levels.
Highly sensitive to presence of heavy metals.
Strongly influenced by organic and hydraulic loadings;
consequently, susceptible to operational upsets.
In instances where ponds and lagoons are used/ large
tracts are required.
Highly dependent on oxygen supply.
Requires the presence of nutrients.
INPUT STREAMS
Influent Waste Stream (Stream No. 1) - This stream contains
dissolved organics, perhaps small amounts of ammonia, and
minute amounts of trace metals.
Air or Pure Oxygen (Stream No. 2) - In some instances of
vated sludge, compressed air or oxygen is used or surface
agitators.
Phosphoric acid - Sometimes added as a micro-organism nutrient,
D-34
-------
DISCHARGE STREAMS AND THEIR CONTROL -
Treated Waste Effluent (Stream No. 3) - This effluent should
be of fairly high quality and require only polishing treat-
ment; however, it is a good idea to monitor the treated
effluent for BOD content and amount of suspended solids.
During upset conditions these levels might not be environ-
mentally acceptable. If a higher quality effluent is
desired polishing processes can be utilized.
Sludge (Stream No. 4) - This effluent primarily consists of
water and suspended solids. It may also contain heavy
metals that are removed from the wastewater. All of these
contaminants can have a detrimental effect on the environ-
ment. This waste stream can only be sent to final disposal
(evaporation pond, sanitary landfill). The final disposal
technique most commonly used is an evaporation pond. Sani-
tary landfills are used when an evaporation pond cannot be
used. The sludge must be dewatered before a sanitary land-
fill can be used.
D-35
-------
WATER POLLUTION CONTROL DISSOLVED INORGANICS REMOVAL
Acid Gas Stripping
GENERAL INFORMATION
Process Function - Acid gas stripping is a process in which
a waste stream is contacted countercurrently with an inert
gas in order to facilitate the removal of acid gases (C02,
H2S, etc.) from the wastewater.
Development Status - Presently being utilized in numerous
refineries.
Licensor/Developer - Not applicable.
Commercial Application - Used to remove H2S, NH3 , and small
amounts o£ phenols from refinery waste streams prior to
their reuse or discharge.
Applicability to Coal Gasification - Since the process has
been successfully used in refineries and coke plants, it
should be applicable to coal gasification waste streams.
PROCESS INFORMATION
Equipment -
Sour water degasser
• Acid gas stripper
Flow Diagram - See Figure 1.
Control Effectiveness (Ref. 295, 296) - Acid gas stripping
achievesi
• Approximately 99% HzS removal
Approximately 90% NHa removal
• Approximately 20-40% phenol removal
Some cyanide removal
D-36
-------
u;
SOUR GAS
FLASH GAS
1) SOUR WATER
CO
SURGE
TANK
P<
H
en
* STEAM
"SWEET" WATER
(A)
Figure 1. Simplified schematic of acid gas stripping process
-------
Operating Parameters (Ref. 297) -
• Sour water feed temperature: 380.4°K (225"F)
• Stripper pressure range: 17.2-34.5 kPa (2.5-5.0 psig)
Utility Requirements -
Electricity required to drive pumps; specific requirements
not available.
Steam requirement range: 2.0 - 200 kg of steam/sec per m3/
sec of wastewater (1-100 Iba of steam/hr/gpm of waetewater
feed) (Ref. 298).
Process Economics (Ref. 299) - Basis: ,04 m3/s (1Q6 gal/day)
operating cost.
• Operating cost ^25.2 mil/m3 (4 mil/bbl)
PROCESS ADVANTAGES
Effectively removes H2S, NH3, and phenols from industrial
waste streams.
Inexpensive technique for acid gas removal.
Proven process.
PROCESS LIMITATION
• Stripping efficiency is dependent upon steam rates.
• NH3 and cyanide removal is sensitive to pH level.
• H2S in sour water and stripper overhead is corrosive.
Stripper overhead and stripper bottoms will probably
require further environmental control.
INPUT STREAMS
The feed to an acid gas stripping unit is an aqueous stream
that is contaminated with:
D-38
-------
• H2S
• NH3
Phenols
• Some light hydrocarbons (Ci, C2)
• C02
• Cyanides
No feed rates nor feed compositions were cited to use as a basis
DISCHARGE STREAMS AND THEIR CONTROL
Flash Gas (Stream No. 2) - This is the off-gas from the
sour water degasser, which predominately contains light
hydrocarbons such as CHt, and C2H6 that have a low solubility
in water. These gases can be recombined with the product
gas from the gasifier.
Stripper Overhead (Stream No. 3) - This stream contains
steam, approximately 99 percent of the H2S, 90 percent of
the NH3, and 30 percent of the phenols entering the stripper,
Some cyanides will also be present in this stream. Because
of its H2S, NH3 and phenol content, this stream will require
further control. In some cases, this stream is incinerated
which can cause air pollution problems. In other cases,
this stream undergoes further processing for recovery of NH3
and elemental sulfur.
Stripper Bottoms (Stream No. 4) - This "sweet" water con-
tains phenols and minute portions of cyanides and would
need further control before it could be discharged from the
plant. In some instances this water can be used for pro-
cess wash water, cooling tower makeup, and boiler makeup.
Fugitive Emissions - Fugitive air and water emissions from
acid gas stripping arise from leaks around pump seals,
process instrumentation, valves, etc. These emissions will
be prevalent in the areas of the discharge streams and will
contain components in those streams.
D-39
-------
WATER POLLUTION CONTROL DISSOLVED INORGANIC REMOVAL
Acid Gas Stripping (WWT)
GENERAL INFORMATION
Process Function - The WWT process basically achieves the
same results in regard to H2S and NH3 removal as does acid
gas stripping. However, this process also facilitates re-
covery of sulfur and NH3 by-products.
Development Status - Commercially available and currently
used in industrial applications.
Licensor/Developer - Chevron Research
576 Standard Ave.
Richmond, CA 94802
Commercial Applications - Used for removal of H2S and NH3
from refinery waste streams.
Applicability to Coal Gasification - Use in coal conversion
plants was explicitly considered when developed. Since the
process has been successful in refineries it should be
expected to perform successfully in conjunction with coal
gasification technology.
PROCESS INFORMATION
Equipment -
Sour water degasser
• Strippers (H2S and NH3)
NH3 scrubbers and compressor
Flowsheet - See. Figure 1.
Control Effectiveness (Ref. 300) - Dependent upon process
operation, however, typical results are as follows:
Stripped water is 99.9?0 water by wt.
• NHs in stripped water <50 ppm.
H2S in stripped water <10 ppm.
D-40
-------
HYDROGEN SULFIDE
O
i
-P-
COOLING
WATER
(ACCUMULATOR)
FOUL WATER
2 C1
S HYDROGEN-
SULFIDE
STRIPPER
GASSER
SURGE
TANK
h1
j
)
y
AMMONIA
STRIPPER
i— »
S
FEAM
J)
STe
J
< i
*"
I )
"^B^
I
AMMONIA
SCRUBBERS
LIQUID
AMMONIA
COMPRESSOR
STRIPPED WATER,
HYDROGEN-SULFIDE/AMMONIA RECYCLE
Figure 1. WWT acid gas stripping schematic (Ref. 301).
-------
Operating Parameter Ranges - Data not available.
Normal Operating Prameters (Ref. 302) -
Temperature Pressure
Ammonia 3110K(100°F) 1.37 MPa (200 psig)
H2S 311°K(200eF) .689 MPa (100 psig)
Stripped H20 311°K(100°F) .344 MPa (50 psig)
Raw Material Requirements - None specified.
Utility Requirements - No amounts specified, however, acid gas
stripping requires:
Steam
Cooling Water
• Electricity
Economics (Ref. 303) - Basis: .01 m3/s (170 gpm) throughput
Operating cost $1.OS/in* (^.4c/gal) treated
PROCESS ADVANTAGES
Process does not require high pressure.
Process facilitates the recovery of H2S and NH3 for
further processing as by-products.
Already proven in commercial applications.
• Capital and operating costs are moderate.
PROCESS LIMITATIONS
Process is proprietary and a royalty must be paid for
its use.
Discharge streams require further environmental control
D-42
-------
Phenol removal efficiency is low.
INPUT STREAMS
Wastewater (Stream No. 1) - This stream contains dissolved
inorganics, primarily H2S and NH3.
Stripping Medium - Steam.
DISCHARGE STREAMS AND THEIR CONTROL
General -
Flash gas from sour water stripper (Stream No. 4).
H2S in stripper overhead from H2S stripper (Stream No. 2).
• NH3 in stripper overhead from NH3 stripper (Stream No. 3).
Stripper water (Stream No. 5).
Specific - Basis (Ref. 304): The following input is used as
tne basis for the effluent concentrations reported below:
.01 m3/s (134 gal/min) wastewater to WWT process.
3.8% (wt.) of input is dissolved material.
- Typically 3-5%% (wt.) of dissolved material is NH3.
- Typically 4-5%% (wt.) of dissolved material is H2S.
Balance of dissolved materials is light hydrocarbons.
Resulting effluents
- Flash gas (Stream No. 4) - Is essentially all light
hydrocarbons and contains virtually all the light
hydrocarbons that enter the system in the sour water.
This stream can be incinerated to remove the light
hydrocarbons. It can also be recycled for further
processing to recover the hydrocarbon.
- Stripped HgS (Stream No. 2) - .22 Kg/s (20.6 tons/day)
generated with following composition:
D-43
-------
Component Wt%
H2S ^99.9
H20 .1
NH3 <30 ppm
Normally, the stripped H2S stream is fed to a. process
that will convert the sulfide to elemental sulfur.
Stripped NH3 (Stream No. 3) (Ref. 305) - 9344 Kg/day
(10.3 ton/day) generated with following compositions:
Component Wt%
NH3 99.9
H20 .1
H2S <1 ppm
The stripped NH3 can be further processed to produce
anhydrous NH3 or it can be incinerated,
Stripped water (Stream No. 5) - Has the following
composition:
Component Wt%
H20 99.9+
H2S <10 ppm
NH3 <50 ppm
90 percent of the water can be reused and 10
percent is discharged.
D-44
-------
WATER POLLUTION CONTROL REMOVAL OF
DISSOLVED SOLIDS
Forced Evaporation
GENERAL INFORMATION
• Process Function - Produces an effluent water that is
generally suitable for recycling to the process by removing
dissolved salts in the form of a concentrated sludg*.
Development Status - Coaancrcially available and presently
being used in industrial applications.
Developer/Licensor - Although 'Resources Conservation Co.,
Renton, Washington, developed and markets a specific evapora-
tor, the concept of forced evaporation is not new.
Commercial Applications - The RCC forced-evaporation system
is being used in three power stations in the southwest U.S.
Applicability to Coal Gasification - Since solar evaporation
ponds are not practical for use in certain areas of the
country, forced evaporation is being investigated for possible
use in coal gasification plants.
PROCESS INFORMATION
Flow Diagram - See Figure 1.
Control Effectiveness - Forced evaporation has been shown
to be very effective in removing dissolved solids from a
wastewater and reducing the waste to approximately 1-5% of
its original volume.
Operating Parameter Ranges -
• Temperature - 338.7 to 394.3°K
Pressure - Vacuum to atmospheric pressure
Normal Operating Parameters - Depends upon specific
application.
Raw Material Requirements - None.
D-45
-------
FEED
STRIPPING
STEAM
VENT
STEAM
STRIPPED •
DEAERATORl
PRODUCT
COHDENSATE
| STEAM
V^/COMPRESSOR
PRODUCT PUMP
RECIRCULATION
PUMP
TO WASTE
DISPOSAL
Figure 1. Simplified schematic of a brine concentrator system (Ref. 306).
-------
Utility Requirements (Ref. 307) - Theoretically the brine
concentrator requires 10.6 kWh/m3 (72 kWh/1000 gal).
Economics - General cost comparisons show that forced
evaporation costs can range from a 16.4 cent savings to a
.53 cent cost per m3 over the cost required by a solar evap-
oration pond (Ref. 308).
PROCESS ADVANTAGES (Ref. 309) -
It is environmentally acceptable because of its maximum
conservation of water and land.
It can be used where solar evaporation ponds are
impractical.
It utilizes less energy than does mechanical drying.
PROCESS LIMITATIONS (Ref. 310) -
High capital investment.
Low energy efficiency.
Generates a flash gas and a sludge that require
further treating.
INPUT STREAMS
Wastewater containing residual dissolved solids, organics,
and gases (Stream No. 1).
DISCHARGE STREAMS AND THEIR CONTROL
The discharge streams produced by a forced evaporator are
described below:
General -
• Stripped gases (Stream No. 2) - contains steam and small
quantities of H2S, NH3, C02 and ph«nols. Th« fInml
D-47
-------
disposition of these gases will depend on the concen-
tration of the contaminants. In most applications, this
stream is vented to the atmosphere. An alternate
disposition of this gas would be to process it for
ammonia or sulfur recovery.
Product water (Stream No. 4) - contains small amounts of
dissolved solids and should not require any further
control before being recycled.
Concentrated sludge (waste brine) (Stream No. 3) -
contains solids removed from water and some H207 Be-
fore it is sent to a landfill, this stream must undergo
a drying process for removal of remaining water.
'Specific -
• Product water
- Basis: product water from a power station brine
concentrator with the following feed (Ref". 311) :
Feed
Component Concentration (mg/Jl)
Sodium 155
Calcium 430
Magnesium 164
Carbonate 12
Bicarbonate 268
Sulfate 1,625
Chloride 92
Ortho Phosphate 3.4
Total Phosphate 7
Silica (as Si02) 50
Total Dissolved Solids (TDS) 2,806
Suspended Solids (SS)
pH .8.15
Calgon CL-77 22
Conductivity (micro-mhos)
D-48
-------
Product Condensate
Component Concentration
Sodium
Calcium
Magnesium
Carbonate
Bicarbonate
Sulfate
Chloride
Ortho Phosphate
Total Phosphate
Silica (as Si02)
Total Dissolved Solids (TDS) 0.5
Suspended Solids (SS)
pH 6.8
Calgon CL-77
Conductivity (micro-mhos) 3.5
Waste brine (Ref. 312)
Basis: waste brine produced in an oil refinery
having the following feed to a forced evaporator:
Brine
concentrator
feed composition
(mg/Q
Sodium 681
Calcium 110
Magnesium 21
Chloride 480
Bicarbonate 26
Sulfate 1,100
Silica (as Si02) 4
Oil 5
Phenol 7.5
Total Organic Carbon 56
Ammoni^ Nitrogen 27
Kjeldahl Nitrogen 29
TDS * 2,422
SS
pH 6.5
D-49
-------
Effluent Waste Brine Concentration
Concentration (mg/i)
Sodium 67,800
Calcium 603
Magnesium 2,100
Chloride 48,000
Bicarbonate 0
Sulfate 87,082
Silica 200
Oil 8
Phenol 1
Total Organic Carbon 1,800
Ammonia Nitrogen 26
Kjeldahl Nitrogen 1,150
TDS 205,785
SS 35,510
pH 6.5-7.5
Boiling Pt., Rise,°F 4.18
D-50
-------
WATER POLLUTION CONTROL DISPOSAL OF LIQUIDS
AND SEMISOLIDS
Evaporation Pond
GENERAL INFORMATION
Process Function - Ultimate disposal of liquid and semisolid
wastes generated in various processes. The water portion of
the semisolid wastes is allowed to evaporate in place.
Development Status - Being used in many industrial applica-
tions.
Developer/Licensor - None.
*
Commercial Applications - Commercial applications not depen-
dent on source of waste generation; consequently, used by
various industries.
Applicability to Coal Gasification - Since evaporation
ponds are used in refineries they should be applicable as
the ultimate disposal technique for coal gasification wastes.
PROCESS INFORMATION
Flow Diagram - See Figure 1.
Control Effectiveness - Evaporation ponds are effective as
an ultimate means of solids and liquids disposal.
Operating Parameters - Specific data not available; however,
operation is highly influenced by site conditions.
Utility Requirements - Negligible.
PROCESS ADVANTAGES
• As an ultimate disposal technique it has no effluent
streams requiring subsequent treating.
D-51
-------
EMULSIONS
SEPARATOR SLUDGES
BACKWASH WATER,
COOLING TOWER
SLOWDOWN
GASEOUS
EMISSIONS
i
EVAPORATION
POND
Figure 1. Evaporation pond - ultimate disposal technique,
D-52
-------
Effective technique for disposing of unprocessable
wastes.
Requires little maintenance.
PROCESS LIMITATIONS (Ref. 313) -
Necessitates substantial land allocations.
Care must be taken to insure that any contaminants the
pond contains do not leach into underground water sources.
Operation dependent upon climatological conditions.
Environmental acceptability dependent upon methods and
materials of construction, specific local hydrogeological
conditions, and types of wastes handled.
INPUT STREAMS
The influent is wastewater which cannot be economically
treated for reuse.! It may contain dissolved organics, dissolved
inorganics, small quantities of heavy metals, and suspended solids
DISCHARGE STREAMS AND THEIR CONTROL
Aqueous - Normally evaporation ponds do not generate any
effluents that require further treating. However, if the
evaporation pond is not managed correctly, run-off is
possible.
Air Emissions - Since the influent wastewater contains
some volatile matter, the ambient air above an evaporation
pond will contain some of these same volatiles. Since
evaporation ponds are usually used in conjunction with
processes that reduce the concentration of these volatiles
to a low level, control of these emissions is normally not
necessary.
D-53
-------
APPENDIX E
SOLID WASTE CONTROL
-------
SOLID WASTE CONTROL SOLIDS DISPOSAL
Sanitary Landfill
GENERAL INFORMATION
Process Information - A sanitary landfill serves as a final
disposal technique for solids and sludges generated by
solids handling or wastewater treating processes.
Development Status - This technique is employed by industry
and municipalities for disposing of their solid wastes.
Licensor/Developer - No particular developer cited.
Commercial Applications - Widely used by industry and
municipalities.
Applicability to Coal Gasification - Because this technique
has been applied to the disposal of a wide range of solid
materials, it should be applicable to handling coal gasifi-
cation plant residues.
PROCESS INFORMATION
Flow Diagram - See Figure 1.
Control Effectiveness - Effective ultimate disposal of solids,
and when designed properly, landfills will not contribute
to air or water pollution.
Utility Requirements - Specific utility usage was not avail-
able. Required utilities are:
Water for fire protection-)
Electricity
Economics - The costs of landfilling are generally about
$.006826 - ,00165/kg ($.75 - $1.50/ton).
E-2
-------
EMULSIONS
SEPARATOR
SLUDGES
i
U!
Figure 1.
SURGE
TANK
SURGE
TANK
VIBRATING
SCREEN
SOLIDS
SCROLL
CENTRIFUGE
SOLIDS
EMULSION
DISK
CENTRIFUGE
EMULSION
SOLIDS
SANITARY
LANDFILL
OIL
WATER
Schematic of dewatering pretreatment sometimes required
for sanitary landfill (Ref. 314).
-------
PROCESS ADVANTAGES
Effective ultimate disposal of solids
Does not create air or water pollution
PROCESS LIMITATIONS
High degree of maintenance required
Must be operated above the water table
Sludge must undergo pretreatment prior to disposal
INPUT STREAM,
Waste Sludge - This stream consists of solids with some
associated water and is generated when separator bottoms
are discharged.
DISCHARGE STREAMS
When managed properly a sanitary landfill has no discharge
streams. However, contamination of surface and ground waters
by leachable components may occur if the landfill is poorly
designed or managed.
E-4
-------
APPENDIX F
REFERENCES FOR VOLUME II
-------
REFERENCES FOR VOLUME II
1 • Dravo Corp . , Handbook of Gasifiers and Gas Treatment
Systems. Final Report. Report No. FE- 1772- 11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div. , February 1976.
L-8590
2. McDowell Wellman Engineering Co., "Wellman-Galusha
Gas Producers", Form No. 576, Company Brochure,
Cleveland, OH, 1976. L-5775
3. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report. Report No. FE- 1772- 11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
4. Ban, Thomas E. , "Conversion of Solid Fuels to Low-Btu
Gas", Amer. Chem. Soc. , Div. Fuel Chem. , Prepr. 19(1) ,
79-98 (1974). L-141
5. Dravo Corp. , Handbook of Gasifiers and Gas Treatment
Systems. Final Report. Report No. FE- 1772- 11, ERDA
Contract No. -E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
6. Ban, Thomas E. , "Conversion of Solid Fuels to Low-Btu
Gas", Amer. Chem. Soc. , Div. Fuel Chem., Prepr. 19(1) ,
79-98 (1974). E
7. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report. Report No. FE- 1772- 11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
8. McDowell Wellman Engineering Co., "Wellman-Galusha Gas
Producers", Form No. 576, Company Brochure, Cleveland,
OH, 1976. L-5775
F-2
-------
9. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
10. Ibid.
11. Ibid.
12. McDowell Wellman Engineering Co., "Wellman-Galusha Gas
Producers", Form No. 576, Company Brochure, Cleveland,
OH, 1976. L-5775
13. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
14. McDowell Wellman Engineering Co., "Wellman-Galusha Gas
Producers", Form No. 576, Company Brochure, Cleveland,
OH, 1976, L-5775
15. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
16. Lurgi Mineraloltechnik GmbH, "Lurgi Pressure Gasifica-
tion Performance Record -- Lurgi Express Information",
Company Brochure, Frankfurt, Germany, October 1975.
L-7843
17. Ibid.
18. Millett, H. C., "Lurgi Process for Complete Gasifica-
tion of Coal with Oxygen Under Pressure", J. Inst.
Fuel 10 15-21 (1936). L-1595
19. Woodall-Duckham, Ltd., Trials of American Coals in a
Lurgi Gasifier at Westfield. Scotland.Final Report.
Research & Development Report No. 105, FE-105. Craw-
ley, Sussex, England, November 1974. L-1164
20. Shaw, H., and E. M. Magee, Evaluation of Pollution Con-
trol in Fossil Fuel Conversion Processes. Gasification,
Section 1: Lurgi Process.Final Report.Report No.
EP~A-650/2-74-009c, EPA Contract No. 68-02-0629. Linden,
NJ, Exxon Research & Engineering Co., 1974. L-1016
F-3
-------
21. Hall, E. H., et al. , Fuels Technology. A State-of-the-
Art Review. Report No. PB-242 535, EPA-650/2-75-034,
EPA Contract No. 68-02-1323, Task 14. Columbus, OH,
Battelle Columbus Labs., April 1975.
22. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report"] RepoTFNo. FE- 1772- 11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div. , February 1976.
L-8590
23. El Paso Natural Gas Co., Application of El Paso Natural
Gas Co. for a Certificate~o^^
Necessity" Docket No. CP73~rT3T7™ El Paso, TX, 1973.
L-512
24. Shaw, H. , and E. M. Magee, Evaluation of Pollution
Control in Fossil Fuel Conversion Processes . Gasifi-
cation. Section 1: Lurgi Process. Final Report.
Report No. EPA-650/2-74-009c, EPA Contract No. 68-02-
0629. Linden, NJ, Exxon Research & Engineering Co.,
1974. L-1016
25. Rudolph, Paul F. H. , "Lurgi Process Route to Substitute
Natural Gas (SNG) from Coal", Chem. Age India 25(5),
289-99 (1974). L-1545
26. El Paso Natural Gas Co., Application of El Paso Natural
Gas, Co . for a Certificate of .Public Convenience and"
NecessityT Docket No. CP73-131. El Paso, TX, 1973.
L-512
27. Woodall-Duckham, Ltd., Trials of American Coals in a
Lurgi Gasifier at WestfTeld, Scotland. Final Report.
Research & Development Report No. 105, FE-105. Craw-
ley, Sussex, England, November 1974. L-1164
28. University of Kentucky, College of Engineering, Insti-
tute for Mining and Minerals Research, A Kentucky Coal
Utilization Research Program, Project 3 - Low-Btu Gai~
and Solid Desulfurized Fuel. Annual Report, 1 July
I9'72 - 30 June "ITTT. Lexington, KY\ November 1973".
"
29. American Gas Association, Proceedings of the Sixth
Synthetic Pipeline Gas Sympo¥Ium, Chicago. TL. Octob er
1574. Washington, fifi, 1575. L-1655 - ' -
F-4
-------
30. Dravo Corp., Handbook of Gasifiers and Gas Treatment
S_ys terns. Final Report. Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
31. Hahn, 0. J., Present Status of Low-Btu Gasification
Technology. Lexington, KY, Inst. for Mining and
Minerals Research, Univ. of Kentucky, January 1976.
L-9184
32. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
33. Woodall-Duckham, Ltd., Trials of American Coals in a
Lurgi Gasifier at Westfield. Scotland.Final Report.
Research & Development Report No. 105, FE-105. Craw-
ley, Sussex, England, November 1974. L-1164
34. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
35. Ibid.
36. Woodall-Duckham, Ltd., Trials of American Coals in a
Lurgi Gasifier at Westfield, Scotland.Final Report.
Research & Development Report No. 105, FE-105. Craw-
ley, Sussex, England, November 1974. L-1164
37. Lurgi Mineraloltechnik GmbH, "Lurgi Pressure Gasifica-
tion Performance Record -- Lurgi Express Information",
Company Brochure, Frankfurt, Germany, October 1975.
L-7843
38. El Paso Natural Gas Co., Application of El Paso Natural
Gas Co. for a Certificate of Public Convenience and
Necessity"Docket No. CP73-131.El Paso, TX, 1973.
L-Sl2
39. Woodall-Duckham, Ltd., Trials of American Coals in a
Lurgi Gasifier at Westfield, Scotland.Final Report.
Research & Development Report No. 105, FE-105. Craw-
ley, Sussex, England, November 1974.
F-5
-------
40. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report"Riport No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
41. Grant, Andrew J., "Two-Stage Coal Gasification -
Fluidized Coal Combustion", Presented at the Fourth
National Conference on Energy and the Environment,
AIChE and APCA, Cincinnati, OH, 7 October 1976.
L-8614
42. Williams, Ian, "Fuel Gas Plants for the Process Indus-
tries Burn Coal Cleanly, Efficiently", Process Eng. 73
52-53, 55, 57 (1974). L-3066
43. Grant, Andrew J., "Applications of the Woodall-Duckham
Two Stage Coal Gasification", Presented at the Third
Annual International Conference on Coal Gasification
and Liquefaction, School of Engineering, University of
Pittsburgh, Pittsburgh, PA, 3-5 August 1976. L-6028
44. Grant, Andrew J., "Two-Stage Coal Gasification -
Fluidized Coal Combustion", Presented at the Fourth
National Conference on Energy and the Environment,
AIChE and APCA, Cincinnati, OH, 7 October 1976. L-8614
45. Ibid.
46. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report". Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
47. Grant, Andrew J., "Two-Stage Coal Gasification ,-
Fluidized Coal Combustion", Presented at the Fourth
National Conference on Energy and the Environment,
AIChE and APCA, Cincinnati, OH, 7 October 1976.
48. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report. Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
49. Ibid.
50. Ibid.
51. Ibid.
F-6
-------
52. "Any Coal Will Work in Low-Btu Process", Hydrocarbon
Process. 54(2), 15 (1975). L-5336
53. Wilputte Corp., Wilputte Low-Btu Fuel Gas Process.
Bulletin No. 7662. Murray Hill, NJ, 1 June 1976.
L-8435
54. Wilputte Corp., "Economical Low-Btu Industrial Fuel
Gas Process (Yesterday's Experience Can Be Today's
Answer)", Company Brochure, Murray Hill, NJ, no date
given. L-8436
55. Riley Stoker Corp., "The Riley-Morgan Coal Gasification
System", Company Brochure, Worchester, MA, October 1975.
L-2138
56. Rawdon, A. H., R. A. Lisauskas and S. A. Johnson,
"Operation of a Commercial Size Riley-Morgan Coal
Gasifier", Presented at the American Power Conference,
Chicago, IL, 19-21 April 1976. L-2136
57. Ibid.
58. Ibid.
59. Ibid.
60. Riley Stoker Corp., "The Riley-Morgan Coal Gasification
System", Company Brochure, Worchester, MA, October 1975.
L-2138
61. Rawdon, A. H., R. A. Lisauskas and S. A. Johnson,
"Operation of a Commercial Size Riley-Morgan Coal
Gasifier", Presented at the American Power Conference,
Chicago, IL, 19-21 April 1976. L-2136
62. Ibid.
63. . Lewis, P. S., et al., "Low-Btu Fuel Gas for Power
Generation", Presented at the 1973 Lignite Symposium,
Grand Forks, ND, May 1973. L-776
64. Lewis, P. S., A. J. Liberatore, and J. P. McGee,
Strongly Caking Coal Gasified in a Stirred-Bed Producer.
U.S. Bur. Mines, Rep. Invest, No. 7644.Morgantown, WV,
Morgantown Energy Research Center, 1972. L-777
65. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh; PA, Chemical Plants Div., February 1976.
L-8590
F-7
-------
66. Lewis, P. S., A. J. Liberatore, and J. P. McGee,
Strongly Caking Coal Gasified in a Stirred-Bed Producer.
U.S. Bur. Mines, Rep. Invest. No. 7644.Morgantown, WV,
Morgantown Energy Research Center, 1972. L-777
67. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report. Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
68. Ibid.
69. Rahfuse, R. V., A. J. Liberatore and G. R. Friggens,
Gasification of Caking-Type Bituminous Coal at 75 to
150 psig in a Stirred-Bed Gas Producer"Report No.
MERC/TPR-75/3.Morgantown, WV, Morgantown Energy
Research Center, July 1975. L-4931
70. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
71. Ibid.
72. Ibid.
73. Rahfuse, R. V., A. J. Liberatore and G. R. Friggens,
Gasification of Caking-Type Bituminous Coal at 75 to
150 psig in a Stirred-Bed Gas Producer.Report No.
MERC/TPR-75/3.Morgantown, WV, Morgantown Energy
Research Center, July 1975.
74. Rahfuse, R. V., G. B. Goff and A. J. Liberatore,
Noncaking Coal Gasified in a Stirred-Bed Producer.
Report No. PB231-983, Clean Energy Program, Tech. Progr.
Rept. No. 77. Morgantown, WV, Morgantown Energy Research
Center, 1974. L-953
75. Rahfuse, R. V., A. J. Liberatore and G. R. Friggens,
Gasification of Caking"Type Bituminous Coal at 75 to
PJQ J?i-5 _?.% Stirred-Bed Gasi Producer.Report No.
MERC/TPR-75/3.Morgantown, WV, Morgantown Energy
Research Center, July 1975.
76. University of Pittsburgh, School of Engineering, Second
Annual Conference on Coal Gasification and Liquefaction.
Pittsburgh. PA. 5-7 August 1975, collection of papers
presented. • L-56^5
F-8
-------
77. Gronhovd, G. H. , et al. , Design and Initial Operation
of a Slagging, Fixed-Bed. Pressure Gasification Pilot
plant. U7S. Bur. Mines, Rep. Invest. No. 6085.
Washington, DC, U.S. Bur. Mines, 1962. L-8615
78- u-s- Energy Research & Development Admin., Quarterly
Technical Progress Report. April - June 1976. Grand
forks Energy Research Center. Report No. GFERC/QTR-
Brand Porks, ND, GFERC, September 1976. L-9077
79. Ibid.
80. Ibid.
81. Gronhovd, G. H. , et al., Design and Initial Operation
of a Slagging, Fixed-Bed. Pressure Gasification Pilot
Plant. U7S. Bur. Mines, Rep. Invest. No. 6085.
Washington, DC, U.S. Bur. Mines, 1962. L-8615
82. U.S. Energy Research & Development Admin., Quarterly
Technical Progress Report, April - June 1976, Grand
Forks Energy Research Center. Report No. GFERC/QTR-
76/4. Grand Forks, ND, GFERC, September 1976. L-9077
83. Gronhovd, G. H. , "Pilot-Plant Experiments in Slagging
Gasification", Chem. Eng. Progr.. Symp. Ser. 61(54),
104-13 (1965). L-9098 ~
84. U.S. Energy Research & Development Admin., Quarterly
Technical Progress Report, April - June 1976, Grand
Forks Energy Research Center. Report No. GFERC/QTR-
76/4. Grand Forks, ND, GFERC, September 1976. L-9077
85. Ibid.
86. Gronhovd, G. H. , "Pilot-Plant Experiments in Slagging
Gasification", Chem. Eng. Progr. , Symp. Ser. 61(54),
104-13 (1965). L-9'0981 ~~
87. Schora, Frank C. , Jr., Fuel Gasification. Advances in
Chemistry Series 69, A Symposium Sponsored by the
Division of Fuel Chemistry at the 152nd Meeting of ACS,
New York, NY, September 1966. Washington, DC, ACS,
1967. L-8527
88. American Gas Association,- Proceedings of the Sixth
Synthetic Pipeline Gas Symposium. Chicago, IL, Qetc
1974.Washington, DC, 1974.L-1635
F-9
-------
89. Schora, Frank C. , Jr., Fuel Gasification. Advances in
Chemistry Series 69, A Symposium Sponsored by the
Division of Fuel Chemistry at the 152nd Meeting of ACS,
New York, NY, September 1966. Washington, DC, ACS,
1967. L-8527
90. Sudbury, John D. , J. R. Bowden and W. B. Watson,
"Demonstration of the Slagging Gasifier Process",
Presented at the Eighth Synthetic Pipeline Gas
Symposium, Chicago, IL, 18-20 October 1976. L-9094
91. Hebden, D. , J. A. Lacey and A. G. Horsier, "Further
Experiments with a Slagging Pressure Gasifier", Pre-
sented at the 30th Autumn Res. Mtg. , Inst. of Gas
Engineers, London, England, 17-18 November 1964. Gas
Council Research Communication No. GC-122, 16 pp.
L-8616
92. Lacey, J. A., "The Gasification of Coal in a Slagging
Pressure Gasifier", Amer. Chem. Soc., Div. Fuel Chem. ,
Prepr. 10(4), 151-67~Tl966) . L-9100
93. Ibid.
94. Ibid.
95. Radian proprietary information. L-9861
96. Ibid.
97. Ibid.
98. Ibid.
99. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Rep~or~tT Report No. FE-1772-11, ERbA
Contract No. E(49-18)~1772 , Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
100. Flesch, W. , "Gasification of Finely Divided Solid Fuels
in a Whirling Bed", in AIME Symposium Papers. 1952.
Gasification and Liquefaction of'C'oal' New York, NY,
1952. (pp. 47-59) i ~~"~~
101. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. FinaTleport . Report No. FE-1772-11, ERbA
Contract No. E (49-18) -1772 , Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
F-10
-------
102. Davy Powergas, Power Gas from Coal Via the Winkler
Process. Lakeland, FL, 1974- L^4~3~8"~~
103. Banchik, I. N., "Clean Energy from Coal", Energy
Pipelines Svs. 1(2), 31-34 (1974). L-1370
104. ibid.
105. Corey, Richard C., "Coal Technology", in Riegel's
Handbook of Industrial Chemistry, Seventh edition,
James A. Kent, ed., New York, NY, Van Nostrand
Reinhold, 1974. (pp. 23-61) L-394
106. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
107. Banchik, I. N., "Clean Energy from Coal", Energy
Pipelines Sys. 1(2), 31-34 (1974). L-1370
108. Hall, E. H., et al., Fuels Technology. A State-of-the-
Art Review. Report No. PB-242 535, EPA-650/2-75-034,
EPA Contract No. 68-02-1323, Task 14. Columbus, OH,
Battelle Columbus Labs., April 1975.
109. Sherwin, Martin B., and Marshall E. Frank, Chemicals
from Coal and Shale - an R & D Analysis for National
Science Foundation.Final Report. Report No. PB-243
393, NSF Grant No. NSF-EN-43237. New York, NY, Chem
Systems, Inc., July 1975.
110. Hahn, 0. J., Present Status of Low-Btu Gasification
Technology. Lexington, KY,Inst. for Mining and
Minerals Research, Univ. of Kentucky, January 1976.
L-9184
111. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
112. Davy Powergas, Power Gas from Coal Via the Winkler
Process. Lakeland, FL, 1974.L-438
F-ll
-------
113. Sherwin, Martin B., and Marshall E. Frank, Chemicals
from Coal and Shale - an R & D Analysis for National
Science Foundation. Final Report. Report No. PB-243
393, NSF Grant No. NSF-EN-43237. New York, NY, Chem
Systems, Inc., July 1975. L-1024
114. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
115. Sherwin, Martin B., and Marshall E. Frank, Chemicals
from Coal and Shale -an R & D Analysis for National
Science Foundation.FinaF Report. Report No. PB-243
3"93, NSF Grant No. NSF-EN-43237. New York, NY, Chem
Systems, Inc., July 1975. L-1024
116. Kamody, John F., and J. Frank Farnsworth, "Gas from
the Koppers-Totzek Process for Steam and Power
Generation", Presented at the Industrial Fuel Con-
ference, Purdue Univ., West Lafayette, IN, October
1974. L-731
117. Wintrell, Reginald, "The K-T Process: Koppers Com-
mercially Proven Coal and Multi-Fuel Gasifier for
Synthetic Gas Production in the Chemical and Fertilizer
Industries", Presented at the 78th National AIChE Mtg.,
Salt Lake City, UT, August 1974, Pittsburgh, PA,
Koppers Co., Inc., 1974. (Paper No. 29A) L-1153
118. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
119. Kamody, John F., and J. Frank Farnsworth, "Gas From
the Koppers-Totzek Process for Steam and Power Genera-
tion", Presented at the Industrial Fuel Conference,
Purdue Univ., West Lafayette, IN, October 1974. L-731
120. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
121. Koppers Engineering & Construction, "Coal Gasification:
The Koppers-Totzek Process", Company Brochure, Pittsburgh,
PA, 1974. L-753
F-12
-------
122. Farnsworth, J. F., et al., "K-T: Koppers Commercially
Proven Coal and Multiple-Fuel Gasifier", Presented at
the 1974 Annual Convention of the Assoc. of Iron and
Steel Engrs., Philadelphia, PA, April 1974. Pittsburgh,
PA, Koppers Co., Inc., 1974. L-526
123. Franzen, Johannes E. , and Eberhard K. Goeke, "SNG Pro-
duction Based on Koppers-Totzek Coal Gasification",
Presented at the Sixth Synthetic Pipeline Gas Symposium,
Chicago, IL, October 1974. Heinrich Koppers GmbH,
1974. L-564
124. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
125. Farnsworth, J. F., et al., "K-T: Koppers Commercially
Proven Coal and Multiple-Fuel Gasifier", Presented at
the 1974 Annual Convention of the Assoc. of Iron and
Steel Engrs., Philadelphia, PA, April 1974. Pittsburgh,
PA, Koppers Co., Inc., 1974. L-526
126. Franzen, Johannes E., and Eberhard K. Goeke, "SNG Pro-
duction Based on Koppers-Totzek Coal Gasification",
Presented at the Sixth Synthetic Pipeline Gas Symposium,
Chicago, IL, October 1974. Heinrich Koppers GmbH, 1974.
L-564
12.7. Kamody, John F. , and J. Frank Farnsworth, "Gas From the
Koppers-Totzek Process for Steam and Power Generation",
Presented at the Industrial Fuel Conference, Purdue
Univ., West Lafayette, IN, October 1974. L-731
128. Farnsworth, J. F., H. F. Leonard and R. Wintrell,
"Application of the K-T Coal Gasification Process for
the Steel Industry", Pittsburgh, PA, Koppers Co., Inc.,
undated. L-531
129. Farnsworth, J. Frank, D. Michael Mitsak and J. F. Kamody,
"Clean Environment with Koppers-Totzek Process", in
Symposium Proceedings: Environmental Aspects of Fuel
Conversion Technology. St. Louis, MO. May 1974.Report
No. EPA-650/2-74-118, EPA Contract No. 68-02-1325, Task
6. Research Triangle Park, NC, Research Triangle Inst. ,
EPA, October 1974. (pp. 115-30) L-527
F-13
-------
130. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report^Report No. FE-1772-11, ERDA
Contract No. E(49-18)~1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
131. Ibid.
132. Sherwin, Martin B., and Marshall E. Frank, Chemicals
from Coal and Shale -an R & D Analysis for National
Science Foundation. Final Report"Report No. PB-243
393, NST Grant No. NSF-EN-43237. New York, NY, Chem
Systems, Inc., July 1975. L-1024
133. Farnsworth, J. Frank, D. Michael Mitsak and J. F. Kamody,
"Clean Environment with Koppers-Totzek Process", in
Symposium Proceedings: Environmgn^l__.Aspects of Fuel
Conversion Technology, St. LouTs", MO, May 197^1 Report
No. EPA-650/2-74-118, EPA Contract No. 68-02-1325, Task
6. Research Triangle Park, NC, Research Triangle Inst.,
EPA, October 1974. (pp. 115-30) L-527
134. Kamody, John F., and J. Frank Farnsworth, "Gas From the
Koppers-Totzek Process for Steam and Power Generation",
Presented at the Industrial Fuel Conference, Purdue
Univ., West Lafayette, IN, October 1974. L-731
135. Farnsworth, J. F., and R. A. Glenn, "Status and Design
Characteristics of the BCR/OCR Bi-Gas Pilot Plant",
Amer. Chem. Soc., Div. Fuel Chem. Prepr. L5(3), 12-31
(1971). L-525 ~~
136. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Repo'rt. Report No. FE-1772-U, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
137. Zahradnik, R. L. , and R. J. Grace, "Chemistry and
Physics of Entrained Coal Gasification", Amer. Chem.
Soc., Div. Fuel Chem., Prepr. 18/1), 203-27 (1973) .
L-3087
138. Air Products and Chemicals, Inc., Engineering Study and
Technical Evaluation of the Bituminous Coal Research.
Inc.. Two-Stage_Super Pressure Gasification .Process.
Report No. ?B"-?3T~77Fr"0"cTl R&D Report 60, OCR Contract
No. 14-32-0001-1204. Washington, DC, OCR, February
1971. L-70
F-14
-------
139. Hegarty, W. P., and B. E. Moody, "Coal Gasification:
Evaluating the Bi-Gas SNG Process", Chem. Eng. Progr.
69(3), 37-42 (1973). L-645
140. Sherwin, Martin B., and Marshall E. Frank, Chemicals
from Coal and Shale - an R & D Analysis for'TTational
science foundation!Final Report. Report No. PB-243
•5^3, NSF Grant No. NSF-EN-43237. New York, NY, Chem
Systems, Inc., July 1975. L-1024
141. Robson, Fred L., et al., Fuel Gas Environmental Impact:
Phase Report. Report No. EPA-600/2-75-078, EPA Contract
No. 68-02-1099. East Hartford, CT, United Technologies
Research Center, November 1975. L-1521
142. American Gas Association, Proceedings of the Seventh
Synthetic Pipeline Gas Symposium. Chicago. IL, 27-29
October 1975.Arlington, VA, 1976.L-8583
143. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
144. Ibid.
145. Katz, Donald L., et al., Evaluation of Coal Conversion
Processes to Provide Clean Fuels.Final Report.Report
No. EPRI 206-0-0, PB-234 202 & PB-234 203. Ann Arbor,
MI, Univ. of Michigan, Col. of Engineering, 1974.
L-727
146. Sherwin, Martin B., and Marshall E. Frank, Chemicals
from Coal and Shale -an R & D Analysis for National
Science Foundation"! Final Report. Report No. PB-243
393, NSF Grant No. NSF-EN-43237. New York, NY, Chem
Systems, Inc., July 1975. L-1024
147. Air Products and Chemicals, Inc., Engineering Study and
Technical Evaluation of the Bituminous Coal Research","
Inc., Two-Stage Super Pressure Gasification Process.
Report No. PB-235 778, OCR R&D Report 60, OCR Contract
No. 14-32-0001-1204. Washington, DC, OCR, February 1971.
L-70
148. Robson, Fred L., et al., Fuel Gas Environmental Impact:
Phase Report. Report No. EPA-600/2-75-078, EPA Contract
No. 68-02-1099. East Hartford, CT, United Technologies
Research Center, November 1975. L-1521
F-15
-------
149. Conn, A. L., "Low-Btu Gas for Power Plants", Chem. Eng,
Progr. .69(12), 56-61 (1973). L-1243
150. Hall, E..H., et al., Fuels Technology. A State-of-the-
Art Review. Report No. PB-242 535, EPA-&5072-l/5-034,
EPA Contract No. 68-02-1323, Task 14. Columbus, OH,
Battelle Columbus Labs., April 1975.
151. Dravo Corp., Handbook of Gasifiers and Gas Treatment:
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
152. Hall, E. H. , et al., Fuels Technology A State-of-the-
Art Review. Report No. PB-242 535, EPA-650/2-75-034-,
EPA Contract No. 68-02-1323, Task 14. Columbus, OH,
Battelle Columbus Labs., April 1975.
153. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
154. Hahn, 0. J., Present Status of Low-Btu Gasification
Technology. Lexington, K*£, thst". for Mining and
Minerals Research, Univ. of Kentucky, January 1976.
L-9184
155. Fleming, Donald K., "An Evaluation of Factors that
Affect the Genesis and Disposition of Constituents in
Coal Gasification", Presented at a Symposium/Workshop
on Sampling Strategy and Characterization of Potential
Emissions from Synfuel Production, Austin, TX, June
1976. L-4508
156. Hoy, H. R., and D. M. Wilkins, "Total Gasification of
Coal", Brit. Coal Util. Res. Assoc. Mon. Bull. 22
57-110 T1958) . ""
157. Ferretti, E. J. , K. C. Baczewski and A. C. Mengon,
"Coal Gasification for Industrial Fuel", Energy Commun.
1(5), 433-94 (1975). L-7082
158. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report tio. FE-l772-li, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
F-16
-------
159. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report. Report No. FE-1TO-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
160. Hahn, 0. J., Present Status of Low-Btu Gasification
Technology. Lexington, KY, Inst. for Mining and
Minerals Research, Univ. of Kentucky, January 1976.
L-9184
161. Katz, Donald L., et al., Evaluation of Coal Conversion
Processes to Provide Clean Fuels.Final Report.Report
No. EPRI 2(^6-0-0, PB-234 202 & PB-234 203. Ann Arbor,
MI, Univ. of Michigan, Col. of Engineering, 1974.
L-727
162. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
163. Ibid.
164. Ferrell, J. , and G. Poe, Impact of Clean Fuels
Combustion on Primary Particulate Emissions from
Stationary Sources.Report No. PB-253 452, EPA
Contract No. 68-02-1318. Mountain View, CA, Acurex
Corp., Aerotherm Div., March 1976. L-7829
165. Inex Resources, Inc., "Inex Resources, Inc.", Company
Brochure, Lakewood, CO, no date given. L-9344
166. Scholz, Walter H., "Rectisol: A Low-Temperature
Scrubbing Process for Gas Purification", Advati. Cryog.
Eng. 15 406-14 (1974). L-1004
167. Personal Communication with W. J. Rhodes. L-7888
168. Ibid.
169. - Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report. Report No. FEl-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
170. Raney, Donald R., "Remove Carbon Dioxide with Selexol",
Hydrocarbon Process. 5J>(4) , 73-75 (1976). L-1439
F-17
-------
171. Riesenfeld, F. C., and A. L. Kohl, Gas Purification.
Second edition. Houston, TX, Gulf Publishing Co., 1974.
L-1359
172. Ibid.
173. Franckowiak, S., and E. Nitschke, "Estasolvan. New Gas
Treating Process", Hydrocarbon Process. 49(5), 145-48
(1970). L-1504 " ' ~
174. Ibid.
175. Riesenfeld, F. C., and A. L. Kohl, Gas Purification.
Second edition. Houston, TX, Gulf Publishing Co., 1974.
L-1359
176. Dingman, J. C., and T. F. Moore, "Compare DGA and MEA
Sweetening Methods", Hydrocarbon Process. 47(7),
138-40 (1968). L-135r —
177. Riesenfeld, F. C., and A. L. Kohl, Gas Purification.
Second edition. Houston, TX, Gulf Publishing Co., 1974.
L-1359
178. Heisler, Leopold, and Helmut Weiss, "Experience with an
Austrian Gas Plant", Hydrocarbon Process. 54(5), 157-61
1975. L-2128 —
179. Ibid.
180. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1/72-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
181. "NG/SNG Handbook", Hydrocarbon Process. 50(4), 93-122
(1971). L-5978
182. Ibid.
183. Ibid.
184. Dingman, J. C., and T. F. Moore, "Compare DGA and MEA
Sweetening Methods", Hydrocarbon Process. 47(7), 138-40
(1968). L-1354 ~
185. Ibid.
F-18
-------
186.
187.
188.
189.
190.
191.
192.
193.
194.
195.
196.
197.
198.
Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report.Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
Ibid.
Robson, Fred L., et al., Fuel Gas Environmental
Impact: Phase Report. Report No. EPA-600/2-75-078,
EPA Contract No. 68-02-1099. East Hartford, CT,
United Technologies Research Center, November 1975.
L-1521
Goar, B. G., "Sulfinol Process Has Several Key Advan-
tages", Oil Gas J. (57 117-20 (30 June 1969). L-1916
Bratzler, K., and A. Doerges, "Amisol Process Purifies
Gases", Hydrocarbon Process. 53(4), 78-80 (1974).
L-1353 ~~
Ibid.
Pearson, M. J. , "Developments in Glaus Catalysts",
Hydrocarbon Process. 52(2), 81-85 (1973). L-2106
Berlie, Elmer M., Richard K. Kerr and Robin P. Rankine,
"The Role of the Glaus Sulphur Recovery Process in
Minimizing Air Pollution", Presented at the 67th Annual
Air Pollution Control Association Meeting, Denver, CO,
9-13 June 1974. Pittsburgh, PA, Air Pollution Control
Assoc., 1974. (Paper No. 74-135) L-1373
Ibid.
Riesenfeld, F. C., and A. L. Kohl, Gas Purification.
Second edition. Houston, TX, Gulf Publishing Co., 1974.
L-1359
Ibid.
Berlie, Elmer M., Richard K. Kerr and Robin P. Rankine,
"The Role of the Glaus Sulphur Recovery Process in
Minimizing Air Pollution", Presented at the 67th Annual
Air Pollution Control Association Meeting, Denver, CO,
9-13 June 1974. Pittsburgh, PA, Air Pollution Control
Assoc., 1974. (Paper No. 74-135) L-1373
Gamson, B. W., and R. H. Elkins, "Sulfur from Hydrogen
Sulfide", Chem. Eng. Progr. 49(4), 203-15 (1953).
L-1871 —
F-19
-------
199. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report. Report No. FE-1772-11, ERDA
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div. , February 1976.
L-8590
200. Goar, Gene, "Impure Feeds Cause Glaus Plant Problems",
Hydrocarbon Process. 53(7), 129-32 (1974). L-606
201. Pearson, M. J. , "Developments in Glaus Catalysts",
Hydrocarbon Process. 52(2), 81-85 (1973). L-2106
202. Ibid.
203. Goar, Gene, "Impure Feeds Cause Glaus Plant Problems",
Hydrocarbon Process. 53(7), 129-32 (1974). L-606
204. Riesenfeld, F. C. , and A. L. Kohl; Gas Purification.
Second edition. Houston, TX, Gulf Publishing Co. ,
1974. L-1359
205. Homberg, Otto A., and Alan H. Singleton, "Performance
and Problems of Glaus Plant Operation on Coke Oven
Acid Gases", Reprinted from J. Ait Pollut. Contr.
Asspc. 25(4), 375-78 (1975)^ L-7848
206. Personal Communication with Catalytic, Inc. L-9355
207. Ibid.
208. Riesenfeld, F. C. , and A. L. Kohlj Gas Purification.
Second edition. Houston, TX, Gulf Publishing Co.,
1974. L-1359 ;
209. Personal Communication with Catalytic, Inc. L-9355
210. Ibid. I
i
211. El Paso Natural Gas Co., Application of El Paso Natural
Gas Co. for a Certificate of Public Convenience and
Necessity^ Docket No. CP73-131. El Paso, TX, 1973.
'
212. Personal Communication with Catalytic, Inc. L-9355
213. Ibid. !
214. Ibid.
215. Ibid.
F-20
-------
216. Personal Communication with Catalytic, Inc. L-9355
217. Beavon, David K., "Add-On Process Slashes Glaus Tail
Gas Pollution", Chem. Eng. 78(28), 71-73 (1971). L-183
218. Beavon, David K., "Beavon Sulfur Removal Process", in
Proceedings of the International Conference on Control
of Gaseous Sulphur Compound Emissions. Univ. o£ Salford,
England. 10-12 April 1973, Vol. 1. L-1647
219. "New Beavon Process Takes Sulfur-Bearing Compounds
from Tail Gas", Oil Gas J. 70(6), 66-67 (1972). L-2053
220. Personal Communication with Catalytic, Inc. L-9355
221. Beavon, David K., and Raoul P. Vaell, "The Beavon
Sulfur Removal Process for Purifying Glaus Plant Tail
Gas", in American Petroleum Institute Proceedings,
Division of Refining, 19IT.New York, NY, 197z7
Ip. 267)L-194
222. Pearson, M. J., "Developments in Glaus Catalysts",
Hydrocarbon Process. 5_2(2) , 81-85 (1973). L-2106
223. Ibid.
224. Beavon, David K., and Raoul P. Vaell, "The Beavon
Sulfur Removal Process for Purifying Glaus Plant Tail
Gas", in American Petroleum Institute Proceedings,
Division oT Refining, 1972.New York, NY, 1972. ,
(p. 267)L-194
225. Beavon, David K., "Add-On Process Slashes Glaus Tail
Gas Pollution", Chem. Eng. 78(28), 71-73 (1971).
L-183
226. Beavon, David K., and Raoul P. Vaell, "The Beavon
Sulfur Removal Process for Purifying Glaus Plant Tail
Gas", in American Petroleum Institute Proceedings,
Division of Refining. 1972.New York, NY, 1972.
(p. 267) L-194
227. Dravo Corp., Handbook of Gasifiers and Gas Treatment
Systems. Final Report. Report No. FE-1772-11, ERDA *
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590 , .
'. I -, " ' !•"" *
y- .:.
228. Naber, J. E.,"J. A. Wesselingh-and-W. Groenendaal, "New
Shell Process Treats Glaus Off-Gas", Chem. Eng. Progr.
69(12), 29-34 (1973). a~
F-21
-------
229. Dravo Corp., Handbook of Gaslfiers and Gas Treatment
Systems. Final Report.—Report No. FE-1772-11, tfkM
Contract No. E(49-18)-1772, Task Assignment No. 4.
Pittsburgh, PA, Chemical Plants Div., February 1976.
L-8590
230. Ibid.
231. Pearson, M. J., "Developments in Glaus Catalysts",
Hydrocarbon Process. 52(2), 81-85 (1973). L-2106
232. Ibid.
233. Naber, J. E., J. A. Wesselingh and W. Groenendaal,
"New Shell Process Treats Glaus Off-Gas", Chem. Eng.
Progr. 69(12), 29-34 (1973). L-8532
234. Ibid.
235. Ibid.
236. Danielson, John A., ed., comp., Air Pollution
Eng ine ering Manua1. Second edition"! Research Triangle
Park, NC, EPA, Office of Air and Water Programs, May
1973. L-1642
237. Ibid.
238. Rolke, R. W., et al., Afterburner Systems Study.
Report No. EPA-R2-72-062, PB-212 560, EPA Contract No.
EHS-D-71-3. Emeryville, CA, Shell Development Co.,
August 1972.
239. Ibid.
240. Ibid.
241. Ibid.
242. Ibid.
243. Ibid.
244. Ibid.
245. Danielson, John A., ed., comp., Air Pollution
Engineering Manual. Second edition.Research Triangle
Park, NC, EPA, Office of Air and Water Programs, May
1973. L-1642
F-22
-------
246. Danielson, John A. , ed. , cotnp., Air Pollution
Engineering Manual. Second edition"; Research Triangle
Park, NC, EPA, Office of Air and Water Programs, May
1973. L-1642
247. American Petroleum Institute, API Manual on Disposal
of Refinery Wastes, Liquid Wastes Volume.Washington,
DC, 1969. L-46 ^
248. ibid.
249. Franzen, A., V. Skogan and J. Grutsch, "Pollution
Abatement: Tertiary Treatment of Process Water",
Chan. Eng. Progr. 68(8), 65-72 (1972). L-44
250. Dahlstrom, D., L. Lash and J. Boyd., "Biological and
Chemical Treatment of Industrial Wastes", Chem. Eng.
Progr. 66(11), 41-48 (1970). L-39
251. Bush, Kenneth E., "Refinery Wastewater Treatment and
Reuse", Chem. Eng. 83(8), 113-18 (1976). L-1315
252. Thomson, S. J., "Data Improves Separator Design",
Hydrocarbon Process. 52(10), 81-83 (1973). L-1687
253. "Meeting the Wastewater Treatment Challenge", Reprinted
from. Plant and Industrial Engineer's Digest 3_(1) (1975) .
L-7844"
254. Shaw, E. C., and W. L. Caughman, Jr., "Parallel Plate
Interceptor", NLGI Spokesman 33(11), 395-99 (1970).
L-4388
255. Prather, B. V., and E. P. Young, "Energy for Wastewater
Treatment", Hydrocarbon Process. 55(5), 88-91 (1976).
L-2166 ~~
256. Ibid.
257. Bush, Kenneth E., "Refinery Wastewater Treatment and
Reuse", Chem. Eng. 83(8), 113-18 (1976). L-1315
258. "Meeting the Wastewater Treatment Challenge", Reprinted
from Plant and Industrial Engineer's Digest 3(1) (1975),
L-7844":
259. Thomson, S. J., "Data Improves Separator Design",
Hydrocarbon Process. 52(10), 81-83 (1973). L-1687
F-23
-------
260. McCrodden, B. A., "Treatment of Refinery Wastewater
Using Filtration and Carbon Adsorption", Eng. Bull.,
Purdue Univ.. Eng. Ext. Ser. 145(11), 230-44 (1974;.
L-532S
261. Beychok, Milton R., "Coal Gasification and the Pheno-
solvan Process", Amer. Chem. Soc., Div. Fuel Chem.^
Prepr. 19(5), 85-93 (1974).
262. Personal Communication with W. J. Rhodes. L-7888
263. Beychok, Milton R. , "Coal Gasification and the Pheno-
solvan Process", Amer. Chem. Soc.. Div. Fuel Chem.,
Prepr. 19.(5) , 85-93 (1974). L-19b~~
264. Wurm, H. J., "Treatment of Phenolic Wastes", Eng. Bull.,
Purdue Univ., Eng. Ext. Ser. 132(tl), 1054-73 (1969).
L-3078
265. Ibid.
266. American Lurgi Corp., "Dephenolization of Effluents by
the Phenosolvan Process", Company:Brochure, New Jersey,
no date given, L-9333
267. Van Stone, G. R., "Treatment of Coke Plant Waste
Effluent", Iron Steel Eng. 49/4), 63-66 (1972). L-1431
268. Cheremisinoff, Paul N., "Carbon Adsorption of Air and
Water Pollutants", Pollut. Engr. 8(7), 24-32 (1976).
L-7804
i
269. American Petroleum Institute, API I Manual on Disposal
of Refinery Wastes, Liquid WastesjVolume. Washington,
DC, 1969. L-46T~
270. Cheremisinoff, Paul N., "Carbon Adsorption of Air and
Water Pollutants". Pollut. Engr. 8(7), 24-32 (1976).
L-7804 ~ ' .;
271. Henshaw, Tom B., "Adsorption/Filtration Plant Cuts
Phenols from Effluent", Chem. Engj 78(12), 47-51 (1971).
L-4502 I "~~
272. Fox, Robert D., "Pollution Control at the Source",
Chem. Eng. 80(18), 72-82 (1973). jL-4500
~~ i
273. Erskine, D. B., and W. G. Schulig4r, "Activated Carbon
Processes for Liquids", Chem. ErigJ Progr. 67(11) .
41-44 (1971). L-2391 ~
F-24
-------
274. Henshaw, Tom B., "Adsorption/Filtration Plant Cuts
Phenols from Effluent", Chem. Eng. 78(12), 47-51 (1971)
L-4502
275. Ibid.
276. Cheremisinoff, Paul N., "Carbon Adsorption of Air and
Water Pollutants", Ppllut. Engr; 8(7), 24-32 (1976).
L-7804
277. ibid.
278. Van Stone, G. R., "Treatment of Coke Plant Waste
Effluent", Iron Steel Eng. 49(4), 63-66 (1972). L-1431
279. Hager, Donald G., "Industrial Wastewater Treatment by
Granular Activated Carbon", Ind. Water Eng. 11(1),
14-28 (1974). L-2083 ~"
280. Van Stone, G. R., "Treatment of Coke Plant Waste
Effluent", Iron Steel Eng. 49(4), 63-66 (1972), L-1431
281. DeJohn, Paschal B., and Alan D. Adams, "Activated
Carbon Improves Wastewater Treatment", Hydrocarbon
Process. 54(10) , 104-11 (1975) L-1442
282. Kostenbader, Paul D., and John W. Flecksteiner, "Bio-
logical Oxidation of Coke Plant Weak Ammonia Liquor",
J. Water Pollut. Contr. Fed. 41(2, Part 1), 199+ (1969)
L-75T
283. Bush, Kenneth E., "Refinery Wastewater Treatment and
Reuse", Chem. Eng. 83(8), 113-18 (1976). L-1315
284. American Petroleum Institute, API Manual on Disposal
of Refinery Wastes, Liquid Wastes Volume.Washington,
DC, 1969. L-4-6
285. Mohler, E. F., Jr., and L. T. Clere, "Bio-Oxidation
Process Saves HaO", Hydrocarbon Process. 52(10),
84-88 (1973). L-168F~~~
286. Barker, John E., et al., Biological Removal of Carbon
and Nitrogen Compounds from Coke Plant" Wastea. Report
flo. EPA-R2-73-167, EPA Project No. 12010-EDY. New
York, NY, American Iron and Steel Inst., April 1973.
L-180
287. Mohler, E. F., Jr., and L. T. Clere, "Bio-Oxidation
Process Saves HzO", Hydrocarbon Process. 52(10),
84-88 (1973). L-168F~~
F-25
-------
288. American Petroleum Institute, API Manual on Disposal
of Refinery Wastes. Liquid Wastes Volume. Washington ,
1969. L-46 - "-^ -
289. Matsch, L. C., and W. C. Dedeke, "Waste Water Treatment:
Using Pure Oxygen for Secondary Treatment", Chem. Eng.
Progr. 69(8), 75-76 (1973). L-8619
290. Kostenbader, Paul D. , and John W. Flecksteiner, "Bio-
logical Oxidation of Coke Plant Weak Ammonia Liquor",
J, Water Pollut. Contr. Fed. 41(2, Part 1), 199+ (1969).
L-751
291. American Petroleum Institute, API Manual on Disposal
of Refinery Wastes. Liquid Wastes Volume. Washington,
DC7 1969. L-46
292. Ibid.
293. Ibid.
294. Ibid.
295. Maguire, William F. , "Reuse Sour Water Stripper
Bottoms", Hydrocarbon Process. 54(9), 151-52 (1975).
L-2129 ~
296. Beychok, Milton R. , "Wastewater Treatment, State-of-
the-Art", Hydrocarbon Process. 50(12), 109-12 (1971).
L-1683 "~
297. Hart, James A. , "Waste Water Recycled for Use in
Refinery Cooling Towers", Oil Gas J. 71(24), 92-96
(1973). L-3353 ~~
298. Ibid.
299. Bheda, Manilal, and D. B. Wilson, "A Foam Process for
Treatment of Sour Water" , Chem. Eng. Progr.. Symp. Ser.
6,5(97), 274-77 (1969). L-2T7
300. Annesen, R. , and G. Gould, "Sour-Water Processing Turns
Problem Into Payout", Chem. Eng. 78(7), 67-69 (1971).
L-42
301. Ibid.
302. Ibid.
303. Ibid.
F-26
-------
304. Annesen, R. , and G. Gould, "Sour-Water Processing Turns
Problem Into Payout", Chem. Eng. 78(7), 67-69 (1971).
L-42
305. Ibid.
306. Stickney, W. W., and T. M. Fosberg, "Putting Evaporators
to Work: Treating Chemical Wastes by Evaporation",
Chem. Eng. Pfeogr. £2(4), 41-46 (1976). L-6051
307. "Get Zero Discharge with Brine Concentration", Hydro-
carbon Process. 52(10), 77-80 (1973). L-2010
••.
308. Ibid. X
«?
\
309. Stickney, W. W., and T.\M. Fosberg, "Putting Evaporators
to Work: Treating Chemical Wastes by Evaporation",
Chem. Eng. Progr. £2(4), 41-46 (1976). L-6051
310. Perry, John H., ed. , Chemical Engineer's Handbook
Fourth edition. New York, NY, McGraw-Hill Book Co.,
1963. L-9306 \ 4f
311. Stickney, W. W., and T. M. Fosberg,'"Putting Evaporators
to Work: Treating Chemical Wastes by
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TECHNICAL REPORT DATA I
(Please read Instructions on the reverse before completing) \
1. REPORT NO. ""
EPA-600/7-77-125b
4. TITLE AND SUBTITLE Environmen
("IT* T .r»W /TV/To A \ii rn T34-ii f^nrttf'
•'•'-'* AJUW/ JYiecilUIii — Dlu Li US 11]
II. Appendices A-F
2.
ital Assessment Data Base
ication Technology: Volume
7. AUTHOR(S) - -. •
E.G. Cavanaugh , W. E . Corbett , and G. C . Page
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Radian Corporation
8500 Shoal Creek Boulevard
Austin, Texas 78758
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
November 1977
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
EHE623A
11. CbNTHACf /GRANT NO.
68-02-2147, Exhibit A
13. TYPE OF REPORT AND PERIOD COVERED
Task Final; 8/76-6/77
14. SPONSORING AGENCY CODE
EPA/600/13
10. SUPPLEMENTARY NOTES IERL-RTP project officer for this report is William J. Rhodes ,
Mail Drop 61, 919/541-2851.
i6. ABSTRACT Tne report represents the current data base for the environmental assess-
ment of low- and medium -Btu gasification technology. Purpose of the report is to
determine: processes that can be used to produce low/medium-Btu gas from coal,
uses of the product gas , multimedia discharge streams generated by the processes ,
and the technology required to control the discharge streams. Attention is on the
processes that appear to have the greatest likelihood of near -term commercialization.
This type of screening provides the preliminary basis for establishing priorities for
subsequent phases of the low/medium-Btu gasification environmental assessment pro-
gram. Processes required to produce low/medium-Btu gas from coal are divided into
discrete operations: coal pretreatment, gasification, and gas purification. Each oper-
ation is divided into discrete modules, each having a defined function and identifiable
raw materials, products, and discharge streams. This volume includes appendices
that contain detailed process, environmental, and control technology data for the
processes considered to have the greatest potential for near-term commercialization.
Volume I includes a discussion of the status, significant trends, major process oper-
ations , multimedia discharge stream control strategies , and recommendations for
future program activities.
17.
a. DESCRIPTORS
Air Pollution
Assessments
Coal
Gasification
Treatment
Gas Purification I
18, em;rniBUTIGN STATfc.Mf.NT
Unlimited
EPA Form'2220-1 (9-73)
KEY WORDS AND DOCUMENT ANALYSIS
b.lDENTIFIERS/OPEN ENDED TERMS
Air Pollution Control
Stationary Sources
Environmental Assess-
ment
Pretreatment
19. SECURITY CLASS (TtiiiRcport)
Unclassified
20. SECURITY CLASS (this page)
Unclassified
c. COSATI Field/Group
13B
14B
21D
13H,07A
21. NO. OF PAGES
365
22. PRICE
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