EPA-650/2-74-009-C
July 1974
Environmental Protection Technology Series
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EPA-650/2-74-009-C
EVALUATION OF POLLUTION CONTROL
IN FOSSIL FUEL CONVERSION
PROCESSES
GASIFICATION; SECTION 1. LURGI PROCESS
by
H. Shaw and E. M. Magee
Exxon Research and Engineering Co.
P.O. Box 8,
Linden, New Jersey 07036
Contract No. 68-02-0629
Program Element No. 1AB013
ROAPNo. 21ADD-023
EPA Project Officer: William J . Rhodes
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, B.C. 20460
July 1974
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This report has been reviewed by the Environmental Protection Agency
and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of tho Agency,
nor does mention of trade names or commercial products constitute
endorsement or recommendation for use.
10.
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TABLE OF CONTENTS
SUMMARY [[[ 1
INTRODUCTION .................................................. 3
1. PROCESS DESCRIPTION ....................................... 5
1.1 Process Facilities ................................. 5
1.1.1 Plant Site .................................. 5
1.1.2 Coal Storage and Pretreatment ............... 7
1.1.3 Gasification ................................ 10
1.1.4 Tar Separation .............................. 14
1.1.5 Shift Conversion ............................ 14
1.1.6 Gas Purification ............................ 14
1.1.7 Methanation ................................. 15
1.1.8 Compression and Dehydration ................. 16
1.2 Auxiliary Facilities ............................... 16
1.2.1 Oxygen Plant ................................ 16
1.2.2 Sulfur Plant ................................ 17
1.2.3 Incineration ................................ 19
1.2.4 Power and Steam Production .................. 20
1.2.5 Raw Water Treatment ......................... 24
1.2.6 Gas Liquor Treatment and
Effluent Water Treatment .................... 26
1.2.7 Ash Disposal ................................ 27
2. ENVIRONMENTAL CONSIDERATIONS .............................. 29
2.1 Air Emissions ...................................... 29
2.1.1 Oxides of Nitrogen .......................... 29
2.1.2 Sulfur Emissions ............................ 31
2.1.3 Particulates Emissions ...................... 32
2.1.4 Other Pollutants ............................ 33
2.1.5 Trace Elements .............................. 34
2.2 Water Pollution .................................... 38
2.2.1 Ammonia ..................................... 41
2.2.2 Phenols ..................................... 41
2.2.3 Other Aqueous Pollutants .................... 41
2.2.4 Water Quality Plan .......................... 43
2.3 Solids ............................................. 43
2.3.1 Ash ......................................... 43
2.3.2 Chemicals ................................... 44
2.3.3 Trace Elements .............................. 44
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TABLE OF CONTENTS (Cont'd)
3. THERMAL EFFICIENCY 46
4. PROCESS ALTERNATIVES 50
4.1 Engineering Modifications 50
4.2 Process Improvements 51
4. 3 Technology Needs 51
5. GLOSSARY AND CONVERSION FACTORS 53
6. REFERENCES 54
APPENDIX 1 59
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LIST OF TABLES
Table Page
Table of Conversion Units 2
1 Navajo Sub-Bituminous Coal 8
2 Typical Trace Element Analysis
Navajo Sub-Bituminous Coal 9
3 Chemical Reactions in Lurgi Gasifier 13
4 Sulfur Balance 18
5 Fuel Gas Distribution 21
6 Electrical Balance 22
7 Sulfur Balance 23
8 Water Balance 25
9 Range of Trace Elements 35
10 Percent Disappearance of Trace Elements 36
11 Tertiary Waste Treatment Technology 39
12 Overall Thermal Efficiency Using
Fuel Gas Fired Boiler 47
13 Overall Thermal Efficiency Using
Coal Fired Boiler 48
14 Lurgi Dry Ash Gasification Process 61
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LIST OF FIGURES
Figure Page
1 Process Flow Diagram For Lurgi
Dry Ash Gasification Process 6
2 Lurgi Gasifier 11
3 Air Effluents 30
4 Liquid and Solid By-Products and Effluents 40
APPENDIX - Figure 1 - Process Flow Diagram For Lurgi
Dry Ash Gasification Process 60
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SUMMARY
A process analysis of the Lurgi Dry Ash Gasification Process for
high Btu gas was carried out. The process has been reviewed from the stand-
point of its potential for affecting the environment. The waste stream
compositions were calculated for a 250 MM scfd synthetic natural gas plant
using a subbituminous coal. Thus, the quantities of solid, liquid, and
gaseous pollutants were estimated, where possible. The thermal efficiency
for various process alternatives was calculated. A number of process
modifications which would reduce pollution and/or increase thermal ef-
ficiency were suggested. The technology needs to control pollution were
assessed.
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TABLE OF CONVERSION UNITS
To Convert From
Btu
Btu/pound
Cubic feet/day
Feet
Gallons/minute
Inches
Pounds
Pounds/Btu
Pounds/hour
Pounds/square inch
Tons
Tons/day
To
Calories, kg
Calories, kg/kilogram
Cubic meters/day
Meters
Cubic meters/minute
Centimeters
Kilograms
Kilograms/calorie,.kg
Kilograms/hour
Kilograms/square centimeter
Metric tons
Metric tons/day
Multiply By
0.25198
0.55552
0:028317
0.30480
0.0037854
2.5400
0.45359
1.8001
0.45359
0.070307
0.90719
0.90719
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INTRODUCTION
A serious shortage of the more convenient and less costly fossil
fuels is projected (1). Substantial fuel reserves which can be used directly
in a way that does not harm the environment are similarly not available (2).
A large effort is underway to develop technology to convert some of the
large sources of domestic fuels to convenient and clean fuels (3). One of
the most advanced technical efforts is in the area of converting high
sulfur bearing coals to synthetic natural gas (4). There are other programs
which are designed to convert coal to low sulfur fuel oil (5).
The Environmental Protection Agency has anticipated the need to
produce convenient and environmentally acceptable fuels from fossil fuels
which could be environmentally harmful. The contemplated processing plants
for converting the less clean fuels would have the burden of removing
the sulfur and other potential pollutants. Thus, the fuel conversion plant
itself could become a source of pollution to the environment. Therefore,
the time is ripe to assess the potential pollution problems that might be
associated with such plants. If problems are anticipated at this time, then
potential solutions can be developed prior to the construction of a
commercial plant. An awareness of potential pollution problems will
allow the developer to obviate most of the problems through proper
design and construction
The Environmental Protection Agency has awarded Contract No. EPA-68-
02-0629 to evaluate the current status of fossil fuel conversion and/or
treatment processes with respect to pollution control and thermal efficiency.
Specifically, Exxon'Research and Engineering Company is performing a
detailed pollution control assessment of representative processes using
non-proprietary information. As a result of this study the "technology
needs" to minimize pollution will be delineated in order to allow
sufficient time for research, development and design of adequate pollu-
tion control equipment in coal gasification processes-
All significant input streams to the processes must be defined,
as well as all effluents and their compositions. Complete mass and energy
balances are required to determine all gas, liquid, and solid streams.
With this information, facilities for control of pollution can be examined
and modified as required to meet Environmental Protection Agency objectives.
Thermal efficiency is also calculated, since it indicates the amount of
waste heat that must be rejected to ambient air and water and is related
to the total pollution necessary to produce a given quantity of clean fuel.
It is also a way of estimating the amount of raw fuel resources that are
consumed in making the relatively pollution-free fuel. In view of the
projected energy shortage this is an important consideration. Suggestions
are included concerning technology gaps that exist for techniques to
control pollution or conserve energy. Not included in this study are
such areas as cost, economics, operability, etc. Coal mining and general
offsite facilities are also not within the scope of this study.
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Considerable assistance was received in making this study,
and we wish to acknowledge the help and information furnished by EPA
as well as that obtained from many specialists in Exxon Research and
Engineering Company. Comments furnished by El Paso Natural Gas Company
and by American Lurgi Corporation are also appreciated.
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1. PROCESS DESCRIPTION
The present analysis of the Lurgi Dry Ash Gasification process
draws heavily on the Stearns-Roger design for the El Paso Natural Gas
Company (6). The location factors have been generalized in order to be
consistent with the other coal gasification analyses that are being made.
It should be emphasized that this work is not an attempt to analyze the
plant of the El Paso Natural Gas Company since the design of that plant
has been modified from that of the original FPC filing. This section
is divided into two parts. One describes the equipment and processes
associated with the SNG manufacture, and the other describes the auxiliary
facilities that are required to make this plant self-supporting in utilities.
A simplified process flow diagram is given in Figure 1 to help explain the
interrelationships of the various flow streams and how they impact on
potential pollutants. A detailed material balance is given in Appendix 1.
It should be noted that this plant contains two gasification sections.
SNG is produced in oxygen blown gasifiers (Section 1.1.3) and the power
requirements for the plant are met with a low Btu gas that is produced
in air blown gasifiers (Section 1.2.4).
1.1 Process Facilities
The Lurgi process has operations similar to other types of
coal gasification processes, except for the gasification step itself. The
gasification step in each case is peculiar to the process. In general,
coal gasification involves getting coal from the mine, storing it,
reducing its size to that necessary for gasification, and, possibly,
pretreating the coal. The gasifier raw gas is generally processed
through a shift reactor which converts carbon monoxide and steam
to carbon dioxide and hydrogen. The hydrogen is necessary for
a later step in methanation. This shift reaction is only applied
to the raw gas if one desires to up-grade it to a synthetic natural
gas (SNG) stream. For a low heating value gas, a water gas shift
section is not required. In this Lurgi study, the assumption is that
the gas will be up-graded to SNG. Following the shift there is a
clean-up step to remove from the effluent gas all the H^S and most of
the C02- The acid gases are then taken for sulphur production through
a Glaus plant or other sulfur recovery process. The last traces of
sulfur are then removed from the gas purification product stream in
order not to poison the methanation catalyst.
The next step is methanation, where three moles of hydrogen react
with each mole of carbon monoxide to produce a mole of methane and a mole
of steam. Considerable quantities of C02 also react to produce methane.
These are highly exothermic reactions which produce & fair amount of the
steam required in the plant. Following methanation there is a drying
step and the gas is compressed to pipeline pressure.
1.1-1 Plant Site
The plant site for a 2.50 MM scfd SNG plant should be about 1000
acres and should be close to both a coal mine and a source of water.
In general, the ash produced from the coal is returned to the mine for
disposal. The coal requirement for the plant in the present study
is 26,000 tons/day of Navajo sub-bitiminous coal. The coal analysis
is given in Tables 1 and 2.
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Figure 1
PROCESS FLOW DIAGRAM FOR LURGI DRY ASH GASIFICATION PROCESS
Nitrogen Tar and
And Oxygen Boil Off Tar Oil
Air
Air
Air
Coal
Recompressed
Lock Hopper Gas
By
@
Pass Gas O
Shift
1
•
Convers ion
Liquor From Air Blown
Incinerator
Superheater
Gasifier Purification
Compression
Methanation
Dehydration
Water to Treatment Area
Gasifier,A.
Effluent Water Evaporation
Evaporation
Wet Ash
To Mine
Evaporation
Water
Lime
Sludge
Air
Flue
Gas
Ash
Water Phenols
Aqueous
Ammonia
(24.1%)
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Water make-up requirements are on the order of 59 MM Ib/d or
4908 gpm. The plant is designed not to discharge any aqueous effluents-
1.1-2 Coal Storage and Pretreatment
The coal storage part of the plant does not involve coal cleaning,
gangue removal or primary screening. All of these operations are assumed to
have taken place at the mine. The coal from the mine is transported to
the gasification plant by a continuous belt conveyor.
The typical properties of the Navajo Sub-bituminous Coal used
in the design are given in Tables 1 and 2. (Also included in Table 2
are analyses by the Illinois Geological Survey furnished by EFA, of
Navajo County Red Seam Coal.) The higher heating value (HHV) used in the
design is 8872 Btu/lb of coal.
The sub-bituminous coal delivered to the gasification plant is
crushed to 1-3/4" x 0. Six storage areas are used for stock piling. Each
area is 1,750 ft. long x 124 ft. wide and contains roughly 120,000 tons
of coal. Coal from the various storage piles is blended prior to feeding
it to the gasifier in order to achieve proper heating value control (Btu
control). An emergency stock pile and re-claiming facility are available
to provide an additional 650,000 tons of coal. This will provide a 25 day
supply of coal in cases of emergency.
A secondary screening facility is present at the gasification
plant. The 1-3/4" x 0 coal is screened to produce two gasifier feed
sizes (1-3/4" x 5/8" and 3/8" x 3/16"). Two sizes of coal are used as
an economic measure to minimize size reduction and screening operations.
All undersized material is conveyed at a rate of about 260 tons per hour
to a briquetting plant. Briquettes are fabricated and sized to 1-3/4" x
5/8". The briquettes are mixed with the feed going to the gasifier. The
briquetting plant contains mixers, coaters and compactors in order to mix
the coal fines with a tar binder. (Revised designs (6) (October 1973)
have eliminated the need for a briquetting plant.)
The coal preparation operations which are carried out at the
gasification plant should be designed with proper dust control measures
(7). Wet scrubber dust collectors should be installed in the screening
and briquetting plant to eliminate dust and fuel emissions. Sprays should
be used at transfer points for dust suppression. The disposal of the
aqueous effluent from these scrubbers is analyzed in Section 2.2 (Water
Pollution). The coal piles themselves should be designed and located
in such a way as to minimize the dangers of spontaneous combustion (8,9).
Other factors associated with rainfall on the coal pile should also be
considered in order to avoid acid water drainage (10).
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Table 1
NA.VAJO SUB-BITUMINOUS COAL (6)
Proximate Analysis Weight
DAF Coal 66.2
Ash 17.3
Moisture 16.5
Component Analysis (DAF Coal)
C 76.72
H 5.71
N 1.37
S 0.95
0 15.21
Trace Compounds 0-04
HHV Range 7500 To 10,250 Btu/lb
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— Q -
Table 2
TYPICAL TRACE ELEMENT ANALYSIS
NAVAJQ SUB-BITUMINOUS COAL (6)
Sb
As
Bi
B
Br
Cd
F
Ga
Ge
Pb
Hg
Ni
Se
Zn
Be
Co
Cr
Cu
Mn
Mo
P
Sn
V
TOTAL
Fluorine
-f Boron
Minimum
0.30
0.10
0.00
60.00
0.40
0.20
200.00
0.50
0.06
1.40
0.20
3.00
0.08
1.10
Trace Elements
ppm by weight
IGS Data
(1)
Maximum
267.3
97.3%
.20
.00
1.
3.
0.20
150.00
18.00
0.40
780.00
8.00
0.50
4.00
0.35
30.00
0.21
27.00
1023
0.3
1.3
17.
0.4
<0.2
39.
1.6
2.
4.
0.06
5.
1.2
15.
0.2
7-
5.
22.
6.
2.
125.
<2.
17.
90.7%
(1) Data furnished by EPA from IGS Analyses of Navajo County Red Seam Coal,
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Spontaneous combustion of coal is probably caused by the oxida-
tion of the coal substance itself. The oxidation is influenced by such
factors as moisture and pyrites. Other factors such as coal size,and
in particular,the segregation of fines in the coal pile have a strong
influence on the spontaneous combustion of coal. The rate of oxidation
of most coals increases very slowly with temperature to about 160°F
(11). If conditions of heat dissipation are particularly poor, tempera-
ture rises above this point and more rapid oxidation can occur, thus causing
further increases in temperature until the coal ignition point is achieved.
In order to avoid spontaneous combustion of coal, certain rules
should be followed. The coal should be stored in a pile in such a way as to
avoid the segregation of lumps and fine coal. It is not advisable to
pile the coal too high since this prevents the escape of heat from the
region located in the center of the pile. Storage piles should be kept
away from other external sources of heat. For long term storage it is
advisable to compact the coal pile so as to avoid local regions where
air and coal can interact, and to reduce dusting and wind losses. The
temperature of the coal pile should be taken regularly, and if the
temperature reaches about 160°F some preventive measures should be taken.
In all solids handling and processing, good housekeeping is
essential. Tt should be a matter of policy in the plant to quickly contain
and clean-up spills and leaks. This is generally required by proper
safety procedures as well. In the outdoor coal storage and process areas
any dust that is not contained can be picked up by the wind and spread
promptly over the site. Specific clean-up equipment such as trucks, vacuum
pick-ups, and hoses should be provided. Spraying water on the roads and
hoses to flush dust to the storm sewer system should be done routinely.
Noise control is another environmental consideration which should
be considered in the coal process area. Screening and briquetting are
expected to be noisy operations. Most of the noise will be shielded
from the public because these operations will be contained in a building.
Special precautions will have to be taken to protect the personnel
operating in that building.
1.1.3 Gasification
In the Lurgi Process, gasification takes place in a counter-
current moving bed of coal at 420 psig. A cyclic mode of operation using
a pressurized hopper is used to feed coal (12). The pressurizing medium
is a slip stream of raw gas which is later recompressed and put back into
the raw gas stream going to purification. The gasifier has a water jacket
to protect the vessel and provide steam for gasification. Approximately
107» of the gasification steam requirement is provided in this manner. The
internals of the gasifier are illustrated in Figure 2. They include blades
to mechanically overcome caking, a moving grate on the bottom to remove
the dry ash, and a mechanism to introduce steam and oxygen uniformly over
the cross section of the gasifier.
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Figure 2
LURGI GASIFIER
FEED COAL
DRIVE
GRATE
DRIVE
STEAM*
OXYGEN
SCRUBBING
COOLER
GAS
tf=? WATER JACKET
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In genera], there are three process zones in the gasifier. The
first zone devolatalizies the coal. As the coal drops down it is met with
hot synthesis gas coming up from the bottom causing devolatilization,
thus removing hydrocarbons and methane from the coal. As the coal
drops lower to the second zone, gasification occurs by the reaction
of carbon with steam. Finally as the coal approaches the grate, carbon
is burned to produce the heat required for the gasification process.
The chemical reactions associated with these zones are listed
in Table 3.
The top and middle zone temperatures are generally between
1100 and 1400°F, where the devolatilization and gasification take place.
The gas leaves the bed between 700 and 1100°F depending on the rank of
the coal. The effluent stream for the Navajo sub-bituminous coal will
be approximately 850°F (13). The temperature of the ash is kept below
the ash fusion temperature by introducing sufficient steam to avoid ash
fusion. This is one of the advantages of this type of gasification.
It is estimated that 1.41% of the PAF coal is not consumed and leaves
with the ash. Thus 5.41% of the dry ash is coal,result ing in an ash
sulfur content of 0.05%.
The gas stream leaving the Lurgi gasifier contains coal dust,
oil, naphtha, phenol, ammonia, tar oil, ash, char and other constituents.
This mixture goes through a scrubbing and cooling tower to remove the tar.
The raw gas stream then goes through a waste heat boiler where the raw
gas temperature is cooled to about 370°F. The boiler produces 112 psia
steam for the Rectisol, Phenosolvan, and Stretford plants. The raw
gas composition on a dry basis is as follows: 28.9 ?» C02, 0.32% H£S,
0.40 % C2HA, 19.55 % CO, 38.81 % H2, 11.09 CHz,, 0.31 % C2H6 and 0.32 %
nitrogen plus argon. The raw gas stream after cooling is split into
roughly two equal parts. Half of it goes through shift conversion to
produce additional hydrogen which will be needed for methanation. The
other half goes directly to the gas purification system. Any liquid
that is condensed in the waste heat boiler and gas cooling section
is sent to the gas liquor separation unit-
The coal lock hopper gas is compressed and mixed with the
stream that goes directly to purification. This lock hopper gas stream
is mixed with other vent streams which contain sufficient quantities
of carbon monoxide and methane to warrant its re-introduction into
the raw gas stream.
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Table 3
CHEMICAL REACTIONS IN LURGI GAS IFIER
Devolatilization and Drying
Coal + Heat > CH + HO + Organics
Gas If ication
C + H20 + 56,400 Btu/lb - mole > CO + H2
CO + HO S> CO + H + 17,770 Btu/lb-mole
C + C02 + 74,200 Btu/lb - mole 5- 2 CO
C + 2Hn > CH. + 32 ,300 Btu/lb - mole
^ 4
Partial Combustion
C + 1/2 0 > CO -t- 47,550 Btu/lb- mole
C + 02 > C02 + 169,200 Btu/lb- mole
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1.1-4 Tar Separation
The water that was used to initially quench the gas as it comes
out of the gasifier becomes a gas liquor. The gas liquor cools the crude
gas mixture to a temperature at which it is saturated with water. This
gas liquor is then flashed, and the tar is removed out of the bottom.
The top phase is then sent to water purification. The gas liquor flash
tanks will also receive the aqueous effluent from the cooling area prior
to the shift reactor. In the gas liquor purification system,dissolved
phenol and ammonia are removed for subsequent by-product recovery value.
1.1.5 Shift Conversion
Slightly less than half of the total crude gas is sent to the
shift conversion section. The crude gas will be cooled in a waste heat
boiler generating steam at about 76 psia. This is the gas that goes to
the shift reactor section. The shift reactors are designed to produce
hydrogen by the "water-gas shift" reaction. This exothermic reaction
has the following stoichiometry;
CO + H20 = C02 + H2 + 17,770 Btu per Ib mole
The shift gas feed is quenched and washed in a countercurrent water tower.
The washed gas is heated and passed through a pre-reactor to remove carbon
containing residues. The heated gas will be shifted in a series of re-
actors resulting in 77.27, conversion of carbon monoxide. The equilibrium
temperature at which the 77.2% of the CO would be converted in this system
is 800°F. Shift reactors generally operate between 700 and 1000°F. The
shift section is designed to produce a ratio of over three moles of hydro-
gen to each mole of carbon monoxide in the total gas stream for methanation.
In this design the ratio of H?:CO going to methanation is 3.7.
The hot gas liquor and tar which are condensed during cooling in
the wast heat boiler are sent to the tar separation units. The product
stream from shift conversion is then mixed with the by-pass gas stream
from the gasification unit and is cooled and sent to gas purification.
Since the shift reaction is fairly exothermic, a fair quantity of heat is
recovered prior to the low temperature gas purification step. Heat is
also recovered from the crude gas stream that does not go through the shift
reactors.
1.1.6 Gas Purification
The effluent stream from the shift reactor section is combined
with the other half of the raw gas and the recompressed lock hopper gas,
and is then sent to the purification system. The mixed gas stream is
cooled to low temperature in order to go into the Rectisol system (15).
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The Recitsol process is a low temperature methanol wash process which
removes acid gases such as H2S, COS and C02 down to a level of about 0.1
vppm. (The process guarantee for Recitsol is 0.2 vpptn.) The gas
purification system is also used for drying and reducing the CC>2 level
prior to final pipeline compression. The efficiency of methanol absorp-
tion increases considerably with decreasing temperature. The lowest
temperature used in the process is on the order of -75°F. The first
vessel in the Rectisol unit is a prewash tower which strips out naptha
and cools the raw gas. The absorber then removes FUS and COS down to
about 0.1 vppm. Roughly 88% of the C02 is also absorbed at this time.
The effluent raw gas from the raethanol refrigerated absorption column is
used to cool the incoming acid gas stream. This sulfur free gas stream
is then sent to the rr.ethanation area.
All the acid gas streams are combined into a single stream
and delivered to the sulfur recovery plant. The sulfur plant stream
also includes the carbon dioxide that is removed after methanation.
The acid gases from the cold methanol are recovered in a multi-stage
operation. The acid gas containing stream is regenerated by step-
wise expansion. The last step is a vacuum distillation. The stream
to the sulfur plant contains, in addition to the acid gases, a
fair amount of product hydrocarbons and carbon monoxide which will
ultimately be burned in the incinerator. The Rectisol process is one
of the major power consumers in this gasification scheme. About 23%
of the power output is used in the refrigeration and compression s..ages of
the process. A mechanical compression refrigeration cycle is used which
provides refrigeration at two temperatures: high level refrigeration
at 32°F and -50°F which is used for the acid gas treatment. The 32°F
methanol stream is used mostly for removing water vapor.
1-1.7 Methanation
The feed gas leaving the acid gas purification system is pre-
heated with product gas leaving the methanation reaction section. The
chemical reactions involved in methanation are
CO + 3H2 = CH4 + H20 + 87,700 Btu per Ib-mole
and C02 + 4H? = CH4 + 2H20 + 71,000 Btu per Ib - mole
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- 16 -
Methanation catalysts are known to be extremely sensitive to poisoning
by sulfur (16). The fresh feed is therefore treated with zinc oxide
beds prior to exposure to the catalyst. Zinc oxide is known to be
an effective remover of trace quantities of sulfur. A fraction of the
methanated product is recycled and mixed with the feed to dilute the
concentration of reactants in the feed. This type of operation helps
maintain the methanation reactors close to equilibrium. The heat of
reaction that is generated by the synthesis of methane is removed by
converting boiler feed water to process steam. This steam is used for
gasification and in other parts of the plant.
The Westfield Lurgi Plant (14) found excessive quantities of
nickel carbonyl in its product gas. An active-carbon bed was installed
to remove this material. The origin of the nickel carbonyl has not
been established. Due to process and environmental considerations,
this should be checked.
1.1.8 Compression and Dehydration
The product gas from the methanation reaction section leaves
at approximately 225 psia and 800°F. The stream is cooled and is sent
to a final product condensate separator. The water is recovered and is
sent to the raw water treatment plant. The. gas is cooled to 90°F and
is then recompressed from 225 to 500 psin. This stream is then sent
back to acid gas removal systems for C02 and water removal. The effluent
from the gas purification system is then sent to the second stage of the
compressor where the pressure is boosted to 915 psia to meet pipeline
requirements. Air cooling is used to cool the compressor effluent
gas prior to delivery to the pipeline. The pipeline gas stream contains
2.01% C02,0.757. H2> 95.96% CH4, 0.12% CO, and 1.16% N2 and Ar. The
net flow of gas is 250.7 million scfd. The SNG has a higher heating
value of 972 Btu/scf.
1.2 Auxiliary Facilities
In addition to the basic process facilities described above
a number of auxiliary facilities are required to make the plant run
efficiently and to remove pollutants. These will be described in this
sect ion .
1.2.1 Oxygen Plant
Three oxygen plants are required in this process to produce
6,000 tons per day of 987» pure oxygen. Approximately 444,000 scfm
of air are compressed to 90 psia with three parallel centrifugal
compressors (17). In so doing, the moisture content of the air is
condensed and is available for process use.
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- 17 -
Assuming an average gas temperature of 60°F and 50% relative
humidity, the amount of water removed from the air is 11,190 Ib/hr. Of
this amount of water, approximately 9,600 Ib/hr is available for use in
the plant. Although the oxygen plant consumes 2.94 megawatts of electri-
city, it generates 1.5 megawatts by expansion, of the cold nitrogen
waste product. The oxygen plant is, of course, a net energy consumer.
It uses 25% of the fuel gas produced in the air gasifier to operate
the air compressors. (See section 1.2.4).
The oxygen plant effluent stream contains 429 pptn C02 > 0.2% H->0,
0.9% 02, and 98.9% ^• As this stream evaporates from the cold box it is
taken through a gas turbine expander and generates 1.5 megawatts of
electrical power. The oxygen stream is compressed to 500 psia and sent
Co the gasification unit.
1.2.2 Sulfur Plant
The H2'S effluent stream from the acid gas purification system
(Rectisol) described in Section 1.1.6, and the H2S from the acid gas
treatment plant (hot potassium carbonate) from fuel gas production de-
scribed in Section 1.2.4, are sent to a Stretford sulfur recovery plant.
The Stretford process (18) was chosen by Steams-Roger (6) for sulfur
recovery in this plant because the total percentage of sulfur in the
input stream is only 1%. It is not practical to use a Glaus Plant for
less than 107» H^S; capital and operating costs increase drastic-
ally as throughput volume increases (19). Roughly, 94% of the sulfur
that comes into this unit is removed and high quality elemental sulfur
is produced. The effluent stream contains 741 ppm of sulfur as H9S and
COS. (In a later design of the plant (6) the Stretford unit is shown
removing 99% of the sulfur.) This stream is combined with fuel gas and
is incinerated in the superheater fire box. The overall sulfur balance
for the gasification complex is given in Table 4. This sulfur balance
does not include very minor streams, such as those that reacted with ZnO
in the methanation guard chamber. These are insignificant from the
viewpoint of sulfur recovery but are important from a pollution viewpoint.
The acid gas entering the Stretford unit is treated with a
water solution containing sodium carbonate, sodium vanadate, anthra-
quinone dxsulfonic acid (ADA), citric acid, and traces of chelated
iron at 80°F and a pH of 8-5. The HzS is oxidized by the vanadate to
form elemental sulfur. The vanadium, which is reduced by the sulfur
reaction, is then reoxidized by the ADA to the pentavalant state. This
reaction occurs in the absorber using air as the oxidizing medium. The
liquid containing elemental sulfur passes to an oxidizer where ADA is
reoxidized by air. The elemental sulfur/air froth overflows to a
holding tank. The reoxidized solution is recycled back to the absorber.
The sulfur is recovered from the sulfur froth by filtration, centrifugation
or floatation. A typical Stretford solution purge contains sodium
salts of anthraquinone disulfonate, metavanadate, citrate, thiosulfate
and thiocyanate for which acceptable disposal must be arranged.
-------
- 18 -
Table 4
SULFUR BALANCE
(1)
Source
Coal
13601 Lb/Hr
100%
Distribution
Sulfur Product
Tar and Tar Oil Naphtha
Naphtha
Ash
Incineration
Power Plant
TOTAL
13161 Lb/Hr
232
9
192
791
216
13601
89.47»
1.7
0.1
1.4
5.8
1.6
100
(1) Numbers are rounded off and do not include lesser quantities of
sulfur in minor streams.
-------
- 19 -
Overall chemical equations can be written as 2 L^S + 02 =
2 H20 + 2S« COS goes through the Stretford sulfur production plant
essentially unaltered and comes out in the gas effluent. The product
sulfur solidifies at ambient temperature and is stored in a curbed
storage area. A fair fraction of the Stretford solution must be
disposed of daily. This is due to the formation of the dissolved solids
that finally build up to such a level that they interfere with the
reaction. These solids are primarily sodium thiocyanate and sodium
thiosulfate. The thiocyanate is produced from any hydrogen cyanide
left in the gas after Rectisol purification. The sodium thiosulfate
results from the reaction 2 NaHS + S02 = Na2S203 + H20 in the oxidizer.
The properly designed Stretford unit should have provisions for
removing the hydrogen cyanide in the gas prior to treating the sulfur
gas stream with the absorbing columns (20). If HCN is not removed, then
there are two methods of operation that have proven successful (21). One is
to keep on making up Stretford feed in order to maintain the concentration
of solids at 25%. The other is to allow the concentration of solids
to build up to 40% and then dump the complete charge. The disposal of
this effluent is a problem. It contains a fair amount of thiocyanate
and thiosulfate ions. In view of the large amount of sulfur that
leaves in the Stretford gaseous effluent as designed, it might be
advisable to add a second stage to reduce the sulfur even further.
Stack gas scrubbing may be necessary on the incinerator/superheater.
This is discussed in the following section.
1.2.3 Incineration
The effluent stream from the Stretford sulfur plant is sent
to incineration. The incinerator superheater fire box consumes about
13.7% of the product gas from the air gasification section. This cor-
responds to 44.9 MM scfd. This stream which consists essentially of
96% carbon dioxide will have a total flow of 367 MM scfd on a dry
basis, and a higher heating value of 29 Btu/scf. Approximately 321 M
Ib/hr of air will be required to completely burn the Stretford effluent
stream. The combined effluents from incineration and superheating come
out of a common stack. The flue gas composition will be 62.5% C02,
7.4% H20,295 ppm S02, 76.5 ppm COS, 57.5 ppm NOX, 0.3% 0?, and 29.8%
N2 • The total amount of heat input into the incinerator/superheater
is approximately 872 million Btu/hr. Thus, the equivalent pounds of
S02 per million Btu emitted are 1.82. Some flue gas desulfurization
method may have to be applied to this gas stream to reduce the level
of SOX to one that is more environmentally acceptable. The NOX
level, on the other hand, would meet the standard of 0.2 Ib of N02
per MM Btu set for boilers of greater than 250 MM Btu/hr heat input.
The superheater is used to make 1100 psia steam to operate the pipe-
line SNG compressor and the methanation recycle compressor.
-------
- 20 -
1.2.4 Power and Steam Production
The power requirements for the gasification complex are met
with a boiler-gas turbine combined cycle fired with a low Btu gas produced
in a Lurgi gasifier using air (22). The Navajo coal is gasified at about
285 psig. The method of operating the ten gasifiers (9 on stream and one
on stand-by) is similar to that previously described in Section 1.1.3.
The raw gas produced goes through a tar separation unit and then through
an acid gas treatment section. The raw gas is desulfurized using a hot
potassium carbonate system. The H9S and CC^ from the hot potassium
carbonate system is sent to the Stretford unit and combined with the
Rectisol effluent in order to produce elemental sulfur.
The same type of coal preparation mentioned previously is used
for this gasification. The lock hopper vent gas is compressed and combined
with the raw gas prior to acid gas treatment. In this system,hot compressed
air and steam are mixed and introduced through the bottom grate. The
ash is removed and combined with the ash from the oxygen gasifier in the
ash quench pond. The ash slurry is transported back to the mine for
ultimate disposal. Approximately 327 MM scfd of dry fuel gas is thus
produced. The fuel gas composition is 5% C02 > 220 ppm l^S, .28% C2H4,
18.8% CO, 24.7% H2, 6.4% CH4, 0.4% C2H6 and 44.4% N2 • The 8as has
a higher heating value (HHV) of 230 Btu/scf.
The flue gas is used in a combined cycle operation. Approximately
1/4 of the total gas is sent to gas turbines to operate the oxygen plant
compressors. The rest of the fuel gas stream is heated in a fuel gas fired
heater prior to going through a fuel gas expander. The effluent stream
from the expander is used to fire the fuel gas heater, steam superheater,
incinerator, and the power boiler. The fuel gas distribution is given
in Table 5.
The flue gas composition coming from the power plant stack
(which accounts for roughly 86% of the total fuel gas consumed in the
plant) consists of 11.5% C02, 16.6% H2°' 74 PPm S02' 128 ppm N0x» 1>3%
02, and 70.6% N2> The boiler accounts for 2,700 MM Btu/hr, thus pro-
ducing emission levels of 0.16 Ib of S02 per MM Btu, and 0.2 Ib of NOX
per MM Btu. The flue gas should be kept warm to avoid condensation in
the stack or in the immediate vicinity of the effluent.
The overall electrical power balance is given in Table 6 and
the plant steam balance is given in Table 7.
-------
- 21 -
Table 5
FUEL GAS DISTRIBUTION
Source
Clean Fuel Gas
(contains 1.4 wt
Use
Gas Turbines
Fuel Gas Heater
Steam Superheater
Power Boiler
Tar Oil Naphtha)
Flow Rate
MM SCFD (Dry)
326.8
82.1
19.5
44.9
180.2
Heat Rate
MM BTU/Hr
3129
786.1
186.7
430.0
1725.4
Distribution
100
25.1
6.0
13.7
55.2
-------
- 22 -
Table 6
ELECTRICAL BALANCE
Coal Preparation
Gas Purification
Sulfur Recovery
Cooling Tower
Power Plant
Consumed
MW
6.65
13.20
4.10
5.00
8.07
Fuel Gas Production 4.23
Other
TOTAL
Oxygen Plant
Power Plant
TOTAL
17.25
58.5
Generated
1.5
57.0
58.5
7.
11.4
22.6
7.0
8.6
13.8
7.2
29.4
100
2.6
97.4
100
-------
Table 7
STEAM BALANCE
Source
Use
Power Boiler
Methanacion and Superheater
Gasifier Jacket (02 Blown)
Pipeline and Methanation Compressors
Gasifier Jacket (Air Blown)
Power Generator
Waste Heat Boiler (02 Blown)
Water Gas Shift Deaerator
1500 Psia (955°F)
1489 M Lb/Hr
1100 Psia (930°F)
1354 M Lb/Hr
500 Psia (752°F)
171 M Lb/Hr
1738
54
842
112 Psia (336°F)
741 M Lb/Hr
17.5 Psia (221°F)
2908 M LB/Hr
Electrical Generator
Pipeline Compressor
Pipeline Compressor
Methanation Recycle Compressor
Gasifier (02 Blown)
Gasifier (Air Blown)
02 Plant Turbine
Lock Gas Compressor (02 Blown)
Lock Gas Compressor (Air Blown)
Oxygen Compressor
Air Compressor (Air Blown)
Phenosolvan
Rectisol
Stretford Plant
Refrigeration Compressor
Condenser
Methanation Waste Heat Boiler
Shift Waste Heat Boiler
Waste Heat Boiler (02 Blot n)
Rectisol
Gasifier Jacket (02 Blown)
1105 M Lb/Hr
384
571 M Lb/Hr
784
1762 M Lb/Hr
312
132
118
35
314
132
32 M Lb/Hr
20
21
435
234
1368 M Lb/Hr
527
748
92
173
-------
- 24 -
1.2.5 Raw Water Treatment
Raw water is supplied to a 21 day hold up storage reservoir
from a major source such as a lake or river. The capacity of the reservoir
is 185 million gallons, and it occupies a site of 28 acres by 30 feet deep.
The reservoir serves various functions which include a place to settle
silt and provide water for fire control. The reservoir should be lined
to avoid seepage (23). The rate of evaporation from the reservoir is
145 gpnT. Raw water strainers are placed on the inlet to the pumps
going to the raw water treatment section.
Approximately 4900 gpm of raw water are pumped out of
the reservoir to the treatment section. An additional 600 gpm are
recycled from the methanation reaction and condensate from the
oxygen plant. After the water is strained to remove silt, it is
pumped to a lime treater where it is treated and clarified. The water
in the clarifier is treated with alum and polymers. The effluents from
the clarifier are drained to a clear-well where they are temporarily
stored. The water from the clear-well is pumped through anthracite
pressure filters. Approximately 4500 gpm are sent to demineralization.
Of this amount 3900 gpm go in to become feed water for steam production.
The demineralization section blowdown consisting of 551 gpm is sent
to the ash quench area. Roughly 1/3 of the latter amount of water
is taken back to the mine as part of the ash slurry for ultimate dis-
posal. The process condensate aerator is used to remove hydrocarbons
as well as carbon dioxide which might be dissolved in the water. The
effluent from the condensate aerating vessel is mixed with the demineralizer
effluent. The total demineralizer effluent flow rate is therefore
approximately 4500 gpm. The pressure filter requires roughly 300 gpm
of back wash which is sent back into the reservoir. The reservoir
capacity is sized so that all the silt can be collected over the life
of the project which is roughly 25 years. A good description of the
raw water treatment steps is given in the Betz Handbook (24).
Approximately 2 tons per hour of water treating chemicals
will have to be disposed of from the raw water treatment section. Most
of these chemicals are sent to the evaporation pond and stored there
for the life of the project. Roughly 1000 Ib per hour of water treating
chemical wastes are chemicals associated with che demineralization section.
The demineralization waste stream contains caustic,sulfuric acid and
resins. The internal water cooling system also requires chemical treatment.
The plant is designed to use 130,000 gpm of cooling water.
This system removes 1170 MM Btu/hr. Water is designed to leave the
cooling water system at 75°F and is returned at 93°F. The cooling
water make-up requirement is approximately 2.2% of the circulation or
2810 gpm. Most of this make-up is supplied from the effluent water
treatment area. The cooling water is supplied by three 5-cell cross-
flow cooling towers. The cooling water is treated with chemicals in
order to control corrosion, scale formation, plant growth and pH (25).
The cooling towers are designed for a wet bulb temperature of 67°F,
-------
- 25 -
Table 8
WATER BALANCE
Rea ct ion
Evaporation
Vent
Drift
Ammonia By-Prod uct
Wet Ash
Fuel and Incineration
TOTAL
Consumed
1971 GPM
3543
79
260
106
145
108
6212
Supplied
31.7%
57.0
1.3
4.2
1.7
2.3
1.7
100
Raw River Water Reservoir 4908 GPM 79.0%
Coal 713 11.5
Produced in Methanation 591 9.5
Oxygen Plant Condensate 0 to 19
TOTAL 6212 to 6231 100
-------
- 26 -
allowing an 8°F approach to the designed condition. The cooling tower
blowdown, consisting of only 210 gpm, is sent to the evaporation pond.
Drift loss from the cooling towers is 260 gpm. The chemicals that are
added to the cooling tower include an antifoam package, a biological
control package, a scale and corrosion control package, and sulfuric
acid for pH control- The overall plant water balance is given in Table 8-
1.2.6 Gas Liquor Treatment and
Effluent Water Treatment
The aqueous streams condensed from the coal gasification and
gas processing areas by scrubbing and cooling the crude gas stream are
called the gas liquor. Gas liquor is collected in one central area coming
from gasification, shift, gas purification, and fuel gas synthesis. Before
all of these aqueous streams are collected,a 11 of the tar, the tar oil
naphtha, and naphtha will have been collected and stored for by-product
value. Gas liquor streams will contain all of the ammonia and phenols
that are produced in gasification. In addition to these by-products,
the gas liquor will also contain carbon dioxide, hydrogen sulfide, trace
quantities of hydrogen cvanide, and other trace components.
The incoming gas liquor stream is filtered to remove suspended
matter such as coal dust and ash. Disposition of the filtered solid
material may be a problem as it will be contaminated with traces of
materials from the gas liquor. The liquid is then mixed with an organic
solvent (isopropyl ether) in an extractor in order to dissolve the phenol. The
Phenosolvan process (26) (Lurgi proprietary process) is an integral
part of the gas liquor treatment section. The phenol solvent mixture
is collected and fed to solvent distillation columns where crude phenol
is recovered as the bottom product, and the solvent as the overhead
product. The solvent is then recycled to extractors after removing
some of the contained water. The raffinate is stripped with fuel
gas to remove traces of solvent which are picked up in the extraction
step. The fuel gas is scrubbed with crude phenol product to recover
the solvent. Finally, the phenol solvent mixture is distilled in the
solvent recovery stripper to produce the crude phenol product,and the
solvent is recycled to the extraction step. The solvent free raffinate
is heated and stream stripped to remove carbon dioxide, hydrogen sulfide,
and ammonia.
The effluent stream from the steam stripper is air cooled
and sent to the deacidifier reboiler. The carbon dioxide and hydrogen
sulfide coming off the reboiler are recompressed and treated in the
Rectisol process. The ammonia is collected as a 24.1 wt % aqueous
solution. Some of the vent gas associated with collecting the ammonia
in solution is sent to incineration. The bottoms from the steam heated
ammonia stripper go to the effluent water treatment section after air
cooling.
-------
- 27 -
The effluent water treatment system, biological treatment
(biox), (27) is used to reduce the phenol and ammonia concentrations in
the effluent from the gas liquor so that the water can be reused as
cooling tower make-up. The biox system is also used to treat sanitary
sewage discharge and discharge from the API separator. Approximately
2900 gpm of effluent come from the gas liquor treatment area,and 110 gpm
come from all the other feed streams. These two streams are treated
in series. The first section treats the gas liquor effluent in an
aeration basin followed by a settling basin. The second section treats
the effluent from the first section,as well as the 110 gpm from all other
streams in the same way. Thus, the second treatment area acts as a
polishing section for the effluent water treatment plant.
In the aeration basin, air is introduced near the bottom of the
tank in order to mix the contents of the tank and maintain a surplus of
reserved oxygen. Also, micro-organisms as well as nutrients are introduced
to digest the organic material. The mixed liquor from the aeration basin
overflows into the second basin. The activated sludge settles to the
bottom of the basin and the supernatant liquid is then sent to the
polishing aeration basin. The polishing aeration and settling basins
operate in the same manner. The sludge on the bottom of the settling
basin is collected from both areas. Part of the sludge is returned to
the aeration basin as required to maintain biological activity. The rest
is sent to the ash disposal area for ultimate disposal to the mine. The
purified liquid from the polishing settling basin is filtered and sent
to the cooling tower sump.
The relatively low flow rate stream, 110 gpm, that is estimated
for all streams other than gas liquor effluent includes water from the
API separator, the sanitary sewer system and the storm drain system. Good
design practice would dictate that this stream be fed to the biox
units from a holding pond in order to provide a fairly uniform quality
of water and thus not disturb biological activity. Similarly, in cases
of flow disruptions or upsets in the Phenosolvan process and/or the sour
water stripper for ammonia,the effluent should not be sent to the biox
units in order not to disrupt their biological activity. A stand-by carbon
or charcoal bed might be used to reduce the concentration of phenol
and ammonia to levels that can be tolerated by biox.
1.2.7 Ash Disposal
Dry ash produced from both the oxygen blown gasifier and the
air blown gasifier is quenched with demineralizer blowdown water. The
water is used to reduce the ash temperature and to avoid dust problems
in transporting the ash. Quenched wet ash is sent from the ash hopper through
a drag conveyor to the belt conveyor for ultimate disposal to the mine.
Additional ash slurry that is carried with the steam produced in the quench
goes to a bin lock condensor as well as to a cyclone separator, followed by
a droplet separator, and finally through an ash slurry thickener. The
-------
- 28 -
de-watered ash is then conveyed back to the mine on the belt conveyor
together with the ash from the ash hopper. A total of 466,700 Ib/hr
of wet ash is transferred. Of that amount roughly 73,000 Ib/hr
is water, 20,000 Ib/hr is the equivalent of dry ash free coal, and
374,000 Ib/hr is ash. The sulfur content of this material is
approximately 0.057,. In addition to the ash, some spent chemicals and
sludge from the water effluent treatment plant are also sent to the mine
for burial. The total quantity of additional material will not add more
than 0.5 wt % to the mass going back to the mine.
-------
- 29 -
2. ENVIRONMENTAL CONSIDERATIONS
The potential pollution problems associated with :he Lurgi
dry ash gasification process are analyzed in this section. Where
applicable, technically feasible alternatives are suggested. This
part of the report is subdivided into three sections. These sections
include a detailed analysis of air, liquid, and solid effluents for
the plant as a whole. They also illustrate that most of the known
potential pollution problems can be handled. Due to lack of data
on the potentially harmful effects of trace elements, only a general
discussion is presented. The areas where additional technical information
is needed to assess the pollution potential will be discussed in a
later part of this report.
2.1 Air Emissions
This section deals with the environmental aspects of process
and utility effluents that end up in the air. The sources of NOX and SOX
emissions are described, and quantitative estimates of their levels are made.
Emissions of particulates and trace elements are also estimated but no
quantitative estimates can be deduced with the presently available information.
Other air effluents such as carbon monoxide and hydrocarbons will be discussed
briefly. Figure 3 summarizes the gaseous effluents from the process.
2.1.1 Oxides of Nitrogen
Oxides of nitrogen (NOX) are produced in fuel combustion
processes using air as the oxidizer. At flame temperatures, the combination
of atmospheric oxygen and nitrogen results in the formation of nitric oxide
(NO). The rate of NO formation and decomposition is highly temperature-
dependent. Organic nitrogen compounds present in the fuel provide another
source of NO in combustion processes. Based on experimental evidence,
the role of fuel nitrogen appears to vary from being the dominant source
of NO at low combustion temperatures to being of lesser importance at
high temperatures. Recent experimental evidence (28) indicates that
in pulverized coal combustion, over 90% of the NOX is produced by
chemically combined nitrogen in the fuel.
The sources of the oxides of nitrogen in the Lurgi dry ash gasifica-
tion plant are the superheater/incinerator, the power plant and associated
equipment such as the fuel heater, and gas turbines. Approximately 176 Ib/hr
of NOX are emitted from the superheater/incinerator. This quantity
of NOX meets the regulation promulgated by EPA on December 23, 1971 for
new fossil fuel fired steam generating uni;:s of more than 250 MM Btu/hr
heat input (29). The standard is 0.2 Ib MM Btu of heat input when
gas fired (2 hour average). Similarly the power equipment produces
537 Ib/hr of NOX measured as N02. Substantial reductions in NOX can
be accomplished by combustion modification techniques described by
Bartok et al. for boilers (30) and by Shaw for gas turbines (31). The
NOX effluent from power equipment also meets the 0.2 Ib N02 MM Btu
EPA standard.
-------
Figure 3
AIR EFFLUENTS
(in pounds per hour)
Dust
1.3
i
I
Coal
Preparation
Ammon ia
Storage
5.8 1.3 1.8
i—i
Tar and
Tar oil
lilt
Naphtha
2.8
Organic
By Product
Storage
Product
Gas
1568M
2480 M
i
I
Oxygen
Plant
Incinerator
and
Superheater
C02
H20
02
N2
S02
COS
NO
429 ppm
0.
62 .5%
7.4%
U •*./„
0.9%(Boil off 197 ppm) 0.3%
1C Q"/
98.9%
29 .8%
295 ppm
77 ppm
57 ppm
2574M
I
1300M44,200M
Water Air
CO
o
Power
Plants
Cooling
Water
System
11.5%
16.6%
1.3%
70.6%
74 ppm
- ppm
128 ppm
-------
- 31 -
Estimates were also made of the quantities of oxide of nitrogen
that would be emitted if the power plant of the gasification complex were
to use coal directly rather than gasifying it and using the gaseous fuels.
These calculations were done primarily to estimate the increase in thermal
efficiency if coal were used directly. This is more fully described in
Section 3- If coal were burned for power, the estimated amount of NO*
expected would be on the order of 1,000 Ib/hr. Most of it would be
due to the conversion of the nitrogen contained in the coal (28).
Roughly, this quantity would meet the EPA standard of 0.7 Ib/MM Btu
heat input for coal firing. The only other source of oxides of
nitrogen in the plant would occur in the case of a plant upset where a
large portion of product fuel would be burned in the plant flare system.
2-1.2 Sulfur Emissions
The SOX emissions coming out of the boiler, gas turbines, and
other combustion equipment will be on the order of 0-16 Ib S02/MM Btu.
This amount is well within the tolerance allowed for steam generating
plants. On the other hand, the amount of sulfur oxides being emitted
out of the incinerator/superheater stack will be 1.82 Ib S02/MM Btu.
This amount is in excess of the EPA standards for even a coal burning
plant which has a standard of 1.2 Ib/MM Btu (30). It is not clear at
this time whether emission standards in coal gasification plants should
be based on the heating value of the coal or that of the gas. In the
same vein the allowed emission levels for gas are more restrictive than
those for coal. By combining the heat input into the gasifier and boiler,
and combining the sulfur output from both stacks, the emission level
becomes 0.55 Ib SC^/MM Btu. This number is less than half the national
standard for coal fired utility power plants. As mentioned previously,
an additional stage in the Stretford Plant would reduce the S02 emissions
from the superheater incinerator stack to a level comparable to that
coming out of the boiler stack. The latest design of the plant (6)
claims about 99% sulfur removal in the Stretford process. If this
efficiency is achievable then one stage of Stretford would be adequate.
The oxides of sulfur emissions, if Navajo coal is used to
fire the power plant and superheater, would be over 100 M Ib SC^/d.
This would result in an emission level of 1.42 Ib S02/MM Btu. This
amount is above the national standard of 1.2 Thus, in order to
use coal, a desulfurization technique would have to be used to
clean the flue gas. An alternate approach to reduce S02 emissions
would be to burn a smaller amount of coal in the power plant and
make up the difference in heat requirement with gas coming out of
the purification system. Since the heating value of the gas from
purification is 415 Btu/scf, about 28 MM scfd or about 10% of the
total production would be required in the power plant to give 1.2 Ib
S02/MM Btu. Alternatively, the by-product tar, tar oil naphtha, and
naphtha can be burned to reduce the pollution from coal burning
alone. The overall gasification efficiency would also improve this
way. The economics associated with using the liquid by-products
as fuel as opposed to their sale as chemical raw materials must be
considered.
-------
- 32 -
It is interesting to compare the flue gas composition predicted
for coal combustion in the boiler with that which has been observed for
similar types of coal in the Four Corners Plant of Arizona Public Servic
Co. (32). The predicted flue gas composition are 13.8% C02, 281 ppm CO,
3.4% 02, 73.2% N2, 9.3% H2, 537 ppm N02, and 652 ppm S02- The emission
levels of the Four Corners Plant were approximately the same for the
same amount of oxygen in the flue gas. The Four Corners plant effluent
levels were 741 ppm NOX and 788 ppm S02• There is an approximate
207o variation between the produced emissions and those reported by
Crawford (32). This difference can easily be accounted for by variations
in the coal.
Arrangment should be made to replace the raw product gas in
the lock hoppers with nitrogen or C02 before filling them with coal in
order to prevent the escape of raw product gas containing H2S to the
atmosphere. The raw gas can be incinerated without increasing the
S02 emissions significantly, or can be compressed and returned to the
main gas stream.
2-1-3 Particulates Emissions
The particulate composition from coal combustion generally
consists of about 40% silica, 30% alumina, and 10% iron oxide (33).
The size distribution of these emissions is on the order of 90% less
than 100 microns, and 30% less than 10 microns for pulverized fuel
furnaces (33) . The levels of particulate emissions from all stoker
type boilers, other than spread stokers, are on the order of 5 Ib/MM
Btu (uncontrolled) (33). The actual level of particulate emissions
is subject to wide fluctuation depending on ash content of the coal,
heating value of the coal, and method and rate of burning the coal.
The present Lurgi plant is designed to minimize particulate
emissions. The power plant and incineration/superheater sections fire
a gaseous fuel, and therefore, few particulates are emitted. The only
other potential source of particulate emissions is associated with the
solids handling areas of the plant. The coal grinding and screening
operations should therefore be enclosed. The coal piles should be
protected from the wind. This is generally accomplished by orienting the
piles in order to minimize wind pick up, or by erecting wind barriers.
Coal leading and dumping operations also generate dust. In order to
minimize particulate emissions one must anticipate potential dust
and particulate sources. Wet scrubber dust collectors should be
installed in the screening and briquetting plants to eliminate dust
and fumes. Dust suppression sprays should be used as required at all
coal transfer points. Similarly, dust collection/suppression facilities
should be added to all coal slorage bunkers and ash locks. Major roads
and parking areas should be hard surfaced to suppress dust. Unpaved
areas should be sprayed periodically to reduce dust. All piles should
be oriented properly to keep dust levels down.
-------
- 33 -
2.1.4 Other Pollutants
A number of miscellaneous air pollutants are also expected
to be emitted in very low concentrations. Among these are carbon monoxide,
hydrocarbons, ammonia, and hydrogen fluoride. Carbon monoxide generally
results from inefficiencies in the combustion process. The level of
carbon monoxide is not expected to exceed 0.02 Ib/MM Btu (34). Hydrocarbons
are emitted to the atmosphere due to incomplete combustion and from leaks
in hydrocarbon by-product transfer and storage. The level of hydrocarbons
emitted due to incomplete combustion is not expected to exceed 0.007 Ib/MM
Btu measured as methane (34). -phe emissions of ammonia to the atmos-
phere will be associated with the effluent water treatment process
that is discussed in Section 2.2.1. Hydrogen fluoride is generated from
the trace of fluorine, probably as an inorganic compound, found in the
coal. The hydrogen fluoride is expected to follow ammonia into the
aqueous waste stream. Very Little HF is expected to go into the atmosphere.
Hydrogen fluoride will therefore be discussed along with water pollution.
Large quantities of water vapor will also be emitted from
this plant. Water per se is not a pollutant but can cause some environ-
mental problems during certain parts of the year when the water might
be condusive to fog formation or through its reaction with other emissions
such as S02• In the winter these large quantities of water might
condense and cause icing problems- The power plant flue gas is expected
to produce about 273 M Ib/hr of water. The incinerator emits about
89 M Ib/hr of water. Another 2 MM Ib/hr of water are lost through
evaporation, venting, drift losses, etc. Drift losses will carry
along any trace materials present, while venting and water evaporation
can lead to loss of volatile compounds.
In addition to the hydrocarbon emissions from incomplete
combustion,there are numerous sources associated with transportation
and storage of products. Leakage of hydrocarbons through heat exchange
equipment leads to emissions from cooling towers. Hydrocarbon emissions
are found near the seals of moving equipment such as pumps and compressors.
Valves generally leak a small amount of hydrocarbons. A major source
of hydrocarbon emissions is associated with by-product storage. Estimates
were made of the emissions in this Lurgi design using API suggested
methods (35) due to leakage and storage. The emission rates are:
Crude Phenol 1.3 Ib/hr.
Tar Oil Naphtha 2 .3
Tar 3.5
Naphtha 1.8
Methanol 1.4
Ammonia 1.3
Product Gases 2.8
-------
- 34 -
2.1.5 Trace Elements
Pollution by toxic metals and their potential health effects
are rapidly causing public and governmental concern. Even at trace levels,
certain of these metals have received a great deal of attention in the
popular press.
In accordance with the Clean Air Act Amendments of 1970, the
Environmental Protection Agency has listed mercury and beryllium as
hazardous metallic pollutants. On March 30, 1973, the EPA set national
emission standards for asbestos, beryllium,and mercury, the first three
air pollutants designated hazardous to health. In addition to these
pollutants, other elements about which there may be concern include:
Cd, As, V, Mn, Ni, Sb, Cr, Zn, Cu, Pb, Se, B, F, Li, Ag, Sn and Ba.
In addition to the metals present as elements or inorganic
compounds, trace stack gas constituents may also be in the form of
organometallic compounds. Finally, organic compounds of the heavy,
condensed ring aromatic type that are either present in the fuel or
that may be formed in the course of the process, can also contribute
to the emission of trace pollutants in fuel conversion.
The exact fate of the trace elements present in the coal
during the gasification process may vary with the operating conditions and
also with the ratio of trace elements present in any one stream. Calcium,for
example, may be present in the ash in minor or major amounts, and its
amount relative to the sulfur present has a major effect on the form
in which calcium, sulfur, and oxygen appear in the final ash emitted.
Similar interactions are known or suspected for certain potentially hazardous
elements in the list such as arsenic and selenium. In this case, the
presence of a large or small amount of one potentially toxic element
may substantially affect the amount of another potentially toxic
element emitted to the atmosphere or retained in the ash from the gasifier.
The balance between alkali and alkaline earth elements,and trace elements
whose oxides are acidic,is also expected to be particularly important
in this connection.
The emission levels of trace elements from Navajo coal are
very difficult to anticipate. In general, one would expect that most
of the trace elements would be retained in the ash and thus disposed of
back in the mines. Some of the more volatile trace elements, such as
mercury, selenium, and others could conceivably go overhead and end
up in the water stream. Some of these trace elements can be adsorbed
on particulate matter and be removed with particulates. Alternatively,
these materials could also be retained as adsorbed matter on the
surface of the various processing vessels associated with gas treating.
The range level of trace elements that can be produced in the Lurgi
plant is listed in Table 9 on the following page.
-------
- 35 -
Table 9
RANGE OF TRACE ELEMENTS
in Ib/hr
Trace Elements
Antimony
Arsenic
Bismuth
Boron
Bromine
Cadmium
Fluorine
Galium
Germanium
Lead
Mercury
Nickel
Se lenium
Zinc
Total
Minimum
0.65
0.22
0.00
130
0.86
0.43
432
1.1
0.13
3.0
0.43
6.5
0.17
2.4
578
Maximum
2.6
6.5
0.43
324
0.9
0.86
1690
17
1.1
8.6
0.76
65
0.45
58
2212
As can be seen from Table 9, 91 to 9770 of all the trace elements
can be accounted for by boron and fluorine. No directly relevant study has
been made of the fate of trace elements in a Lurgi gasification plant. One
is therefore forced to rely on the data of other experimental studies
regarding the fate of trace elements. Two recent studies, one using samples
from the Hygas bench scale pilot plant (36) and the other of the TVA Allen
Plant (37) indicate that sampling, as ':ell as chemical and analytical
procedures, are major obstacles for accurate material balances for trace
elements. Table 10 indicates the percent disappearance (removal from
the remaining solids) of some of the trace elements after various steps
in the process. Note that between 85 and 97% of the mercury is not
accounted for in these two plants. In a similar manner, selenium,
arsenic, and lead could not be accounted for. A recent study
on the levels of airborne beryllium due to coal combustion (38)
indicated that a maximum of 16% of the beryllium in the coal could
be accounted for in the fly ash. The level of beryllium one mile
from the Hayden Power Plant where the test was conducted, was a
factor of two to four higher than normal background. It was concluded
from this study that the rise in background beryllium was unquestionably
due to the Hayden Power Plant.
-------
Table 10
Hg
Se
As
Te
Pb
Cd
Sb
V
Hi
Be
Cr
PERCENT DISAPPEARANCE
Preheator
430°C
1 atm
30
41
22
36
25
24
13
-9
8
-9
-13
Hygas Bench Scale
Hydrogasif ier
650°C
74 atm
48
21
25
18
19
23
7
18
8
7
7
(36)
Electrotherma 1
1000°C
74 atm
19
12
18
9
19
14
13
21
8
21
7
Sum
97
74
65
63
63
61
33
30
24
19
1
TVA Allen Plant (37)
Precipitatcnr
Slag Tank £ff.(1) Unaccounted(2)
87
71
97
99
65
97
70
58
67
40
60
95
98
96
96
99
92
98
98
85
58
64
51
-8.5
71
24
39
69
31
I
CJ
(1) Efficiency of trace element collection.
(2) Difference bet-een trace element quantity entering with coal and that
accounted by the precipitator and slag tank.
-------
- 37 -
A series of studies using different sized burners were
reported by Schultz et al. (39). The studies indicated that
the maximum emission of mercury was 50% of that contained in the
coal if the pyrite fraction was removed prior to firing. Lead and
cadmium were accounted for to a larger extent than mercury in the fly
ash. Roughly 30 to 407» of these elements were not accounted for and
were presumed to be emitted with the gaseous effluent. Schultz also
pointed out the need to exercise great experimental care in doing trace
element analysis since the handling procedures could add to the concentra-
tion of trace elements.
Another recent study (40) found mercury levels of 0.1 to 0.7
ppm by weight in the coal supplied to a 5.5 x 10^ Ib/hr steam generator.
This study employed aromatic stripping voltammetry, plasma emission
spectroscopy, and neutron activation methods for Hg analysis. Mercury
balances obtained by analyzing the coal, bottom, hopper, fly ash, flue
r,as , and water leaving the plant were deficient by as much as 5070 but
averaged within 1070 for the study. This study emphasized the need for
reliable sampling techniques, and concluded that 90% of the mercury
in the coal fired is emitted as vapor.
Trace elements can cause operational problems, even if properly
contained from an environmental point of view. Janeson (41) recently
reported that alkali metal compounds from gasification of coal tend to
cause hot corrosion and fouling problems in gas turbines. The study
concluded that chlorine present in the coal promotes alkali release
by forming alkali chlorides. The chlorides react with sulfur compounds
at gas turbine combustion temperatures to form sulfate deposits.
A recent study has given some indication that fine grinding
followed by selective oil agglomeration can significantly reduce the
level of trace metals in feed coal (42). Elements that are organically
bound to the coal tend to remain with the feed coal stream. Thus,
barium, beryllium (43), boron, germanium (44), mercury (45),se lenium,
titanium, and zirconum tend to remain with the agglomerated product.
Clearly, additional studies are essential to delineate the fate of
the trace elements. Parallel studies are needed to define more clearly
what the maximum allowable levels should be in order not to create an
environmental hazard where none exists. In view of the relatively large
number of Lurgi plants in world wide operation, it would be
highly desirable to determine the distribution of trace elements in
the various parts of the process in operating plants.
-------
- 38 -
2.2 Water Pollution
The handling of the process and cooling water stream can
represent one of the major pollution problems in an SNG plant. For
economic and other reasons many gasification plants are seriously
considering recycling all process water to extinction. The SNG plant
water treatment systems will have to be designed specifically for each
plane. No one process will be universally applicable. The variety
of coal sources and gasifier operating conditions will differentiate the
aqueous wastes in the various processes under development.
Water treatment technology has been historically divided into
primary, secondary, and tertiary treatment. Primary treatment is usually
done first and is designed to remove much of the suspended solids and
BOD. The conventional operations in primary treatment, sometimes called
clarification, are coagulation, flocculation and sedimentation. Secondary
or biochemical treatment oxidizes dissolved organic material to reduce
BOD by about 90%. Tertiary treatment involves treatment of pollutants
with lower BOD. The operations involved in tertiary treatment have,
in general,not been used commercially for more than 5 years. The processes
included in tertiary treatment are listed in Table 11 (46).
The Lurgi plant is designed for zero water effluents. Thus,
all the pollution that can be carried by the water will be retained at
the plant site. Overall water balance is given in Table 8. Roughly
80% of the total water make-up comes from the river and only about 5%
of the total water consumed leaves the plant as part of the wet ash and
in the by-product ammonia solution. Essentially all of the organic by-
products are removed through various stages in the process (obviously
some trace amounts remain). Finally, the soluble phenols fraction is
removed in the Phenolsolvan process (26). Inorganic by-products such
as ammonia, hydrogen sulfide, and hydrogen cyanide are treated in
fairly conventional sour water treatment processing schemes. Ammonia
is steam stripped from the liquor and condensed as an aqueous solution
of 24.1 wt. % ammonia. This solution is stored and ultimately sold
for its by-product value. Carbon dioxide and hydrogen sulfide are
collected from a deacidifier column and are sent through the Rectisol
process to the Stretford Plant. The liquid and solid by-products
and effluents for this Lurgi plant are summarized in Figure 4.
It might be desirable to have additional storage capacity
in the effluent water treatment section to provide hold-up in case of
a process upset. There is danger that the levels of phenol or ammonia
would be excessive for the biological activity level present in the
biox units. Thus, the microorganism population might be exterminated
and it could take time to reestablish adequate activity (47). Another
procedure for treating such a stream would be to use a tertiary water
treatment technique, which should be available on a stand-by basis
prior to mixing it into the normal biox feed stream. For best results,
the feed stream composition to the biox units should be kept as constant
as possible.
-------
- 39 -
Table 11
TERTIARY WASTE TREATMENT TECHNOLOGY
Technology
1. Biological - Carbon Adsorption
2. Carbon Adsorption
3. Ozone Oxidation
4. Evaporation
5. Ion Exchange
6. Reverse Osmosis
7. Dialysis
8- Precipitation
Potential Usage
Biological Effluent Polishing
Soluble Organics
Taste and Odor Control and
Destruction of Other Refractories
Organic and Inorganic Separation
Selected Organic and Inorganic
Constituents
Inorganic and Organic Molecules
Separation from Water
Inorganic and Organic Molecules
Separation from Water
Phosphate and Metals Removal
-------
Figure 4
LIQUID AND SOLID BY-PRODUCTS AND EFFLUENTS
(in pounds per hour)
Tar
Separation
Gas
Purification
Gas
Liquor
Treatment
Ash
Disposal
I
o
Tar
89,490
Tar Oil
36,892
Naphtha
18,369
Phenols Ammonia Solution
10,142 69,886
Water = 53,028
Ammonia = 16,858
Wet Ash
466,734
Water = 72,500
MAF Coal = 20,218
Ash = 374,016
Chemicals = 4,000
-------
2.2.I Ammonia
Since no process waler is returned lo lhe river or to any
other water resource, the water treatment methods necessarily relate
to purifying the water to process quality. The ammonia that is treated
is the residue remaining after by-product ammonia has been removed
from the gas liquor treatment section. Trace quantities of ammonia also
come from the API separator and from the sanitary sewer sewage system
into the effluent water treatment section. Approximately 100 ppm ammonia
comes in free and 950 ppm comes in as fixed ammonia. The ammonia is
treated first in an aeration, b asin followed by a settling basin and then
through an aeration/settling polishing unit. The effluent from the
system contains less than 5 ppm ammonia measured as amines and is sent
back to t.ie cooling tower sump- It is interesting that Kostenbader and
Flecksteiner (48) indicate that fixed ammonia may not be readily removed
by biological treatment and that free ammonia may be removed into the air.
The sour water stripper used to recover ammonia has to be
designed to treat certain feed impurities which could cause pollution
problems. The major factor in obtaining proper stripper operation is
the pH of the feed stream. Impurities such as Cl~, oil, phenols, mercaptans,
cyanides, thiocyanates, and polysulfides can affect stripper capacity
and corrode the materials of construction as well as contaminate the
products. Oil can cause reboiler fouling and foaming in the tower. If
the oil is stripped with the H2S it could produce a black sulfur product
which has a poor sale value. Most of the other impurities are potentially
corrosive to the materials of construction.
2.2.2 Phenols
The source of phenol in the water is similar to that of ammonia.
It comes from the gas liquor treatment section. The residual concentration
of phenol in the water depends on the efficiency of the Phenosolvan process.
It is estimated that 500 parts per million phenol enter the effluent water
treatment section (biological degredation) and are processed through
two stages of aeration and settling ponds. The effluent water contains
less than 3 parts per million of phenol and is sent to the cooling tower
sump .
2.2.3 Other Aqueous Pollutants
The other aqueous pollutants that are treated by the biological
treatment section include fatty acids, BOD5, and suspended solids. The
fatty acid concentration which starts out at about 1750 ppm (acidic acid)
is reduced to less than 9 ppm. The BOD concentration which starts out
at 2500 ppm is reduced down to 75 ppm. Suspended solids which are
negligible in the inlet stream increase to about 5 parts per million.
As mentioned previously, the effluent stream from the biological treat-
ment section (effluent water treatment) is sent to the cooling tower
sump.
-------
- 42 -
Pollutants that are not accounted for quantitatively in the
water phase include hydrogen cyanide and hydrogen fluoride. The quantities
of hydrogen cyanide that are expected to be produced in coal gasification
depend on gasification temperature and pressure. At the Lurgi gasification
conditions some HCN is expected to be produced and can pass through the SNG
system (49). HCN comes in contact with water at a number of poincs.
In the production of metallurgical coke, roughly one percent of the coal
nitrogen is converted to HCN. It appears that HCN is produced by the
secondary reaction of ammonia with carbon in the reactor. It has been
shown that HCN formation is a function of ammonia partial pressure, contact
time, and pressure (50). Increased partial pressure of steam suppresses the
production of HCN. Hydrogen cyanide will follow the fate of the hydrogen
sulfide and is removed in the Stretford process. These quantities of HCN
might end up in the water stream. If so, they might have to be treated
separately since they can be very detrimental to the biological activity
of the effluent water treatment section, especially if levels fluctuate.
Hydrogen fluoride, because of its high reactivity, is expected
to react with the calcium oxide, silica, or alumina in ash and ultimately
be disposed of with the ash. Any hydrogen fluoride that ends up in the
water stream will probably be neutralized by basic minerals that are
present there. Small amounts of calcium oxide can be added to neutralize
the hydrogen fluoride.
Some coal dust will invariably end up in the waste water stream.
Dust from the coal pile as well as dust which is washed in water sprays
from the screening operations is carried in the water stream and ultimately
ends up in the evaporation pond. It is very difficult to quantify this
s t re am •
The water stream may contain traces of organic materials that
are carcinogenic and which are not readily removed by biological treatment.
(Only about 907, of the total organic carbon is removed by biological action.)
These materials could enter the environment in the water spray from the
cooling towers-
Other sources of aqueous pollution such as the chemicals used
for regenerating the detnineralizers system, will most likely end up in the
ash quench and removal section and be ultimately carted back to the mine.
The resulting slurry will contain leachable materials- Some solid
materials and solid inorganic compounds will end up in the effluent water
stream from the Stretford process due to leakage. Quantities are small
but disposal may be difficult.
-------
2.2.4 Water Quality Plan
Raw river water is treated conventionally to up-grade its
quality to that of boiler feed water. It is filtered, treated with
lime, and demineralized. This high purity water is used for steam production
as well as for cooling the air and oxygen gasifiers. The biggest source
of water consumption is through evaporation and drift losses. These
account for approximately 2/3 of the total amount of water lost. The
other third is lost by reaction in the gasification steps. Other important
considerations for the water treatment part of the plant include a
lined evaporation pond which is used to handle aqueous wastes which are
not feasible to recycle. In effect, these wastes are si.ored in the pond
for the life time of the project. Oily waste water is treated with an
API oil separator and the effluent is sent to the biox units. The lime
sludge from the raw water treatment system is sent to the evaporation pond
and concentrated there.
In order to conserve water, air cooling is used to dissipate waste
heat arid thus conserve water. Similarly, cooling tower circulation water
will be recycled as much as practicable. The blowdown stream from the
cooling tower is sent to the evaporation pond. This stream contains a
number of chemicals which are needed to prevent corrosion and the build-
up of micro-organisms in the cooling tower. Sludge from the effluent
treatment biox units is sent to the mine with the ash. A separate drainage
system in the area is used so as not to mix the water resulting from
rain and other sources with plant waste streams. Similarly, storm water
is diverted to prevent overloading ?. he biox treatment section.
2.3 Solids
There are three major sources of solid wastes chat must be
considered in the Lurgi plan. These are; ash from the coal, sludge
from the biox effluent water treatment section, and chemicals and
catalysts that are used in the process and in water treating. Dust
from the coal pile has been discussed under air pollutants.
2.3.1 Ash
The total quantities of ash that are expected to be produced
from gasification are 314,000 Ib/hr from che' oxygen gasifier, and
80,200 Ib/hr from the air gasifier. The ash contains che equivalent
of about 5.4 we % DAF coal. Thus, 0.05 wt % sulfur on a dry basis
is contained in the ash. The two sources of ash are mixed with
demineralizer blowdown water resulting in 466,700 Ib/hr of
wet ash which is sent back to the mine for burial. The burial site
for the ash should be such that no trace metals are leached from the
ash into the water system- Good quantitative data is lacking in this
area although one study (52) has shown that large quantities of minor
-------
- 44 -
elements from spent shale are leachable- One substance in the coal ash
that might cause some environmental problems associated with leaching
is boron oxide, I^CK. Boron oxide is generally non-toxic in low
concentrations, and is in fact a necessary plant nutrient (51). The
effect of 8203 at higher concentrations around the vicinity where
the ash is buried is not known and should be investigated.
2.3.2 Chemicals
All chemical effluents will be contained in water process streams
or in the evaporation ponds. The cooling tower water treatment system
will use such chemicals as alum, chlorine, sulfuric acid, sodium hydroxide,
ferric chloride, calcium carbonate, corrosion inhibitors,and polymers.
The raw water treatment chemical wastes consist mostly of lime sludge
which make the water associated with the ash alkaline and thus fix
most of the acid wastes- Other sources of solid wastes include
catalysts from both the shift and melhanation reactors. In general, these
catalyst beds are expected to last from 2 to 3 years. A small fraction
of the catalyst bed is expected to be replaced yearly with fresh catalyst
in order to maintain sufficient catalytic activity. The Stretford solution
provides another source of solid was es. (The reason for replacing the
Stretford solution is the limits on the concentration of solids (21).)
The general method of operation is to maintain a concentration of 25
wt "L solids in the solution, and as the concentration increases a
fraction of the solution is blown down. If the concentration ever
reached 40 wt % then the whole solution is replaced.
2.3.3 Trace Elements
Some of che trace elements present in the coal are highly toxic
(53). For example, lead and arsenic are well known poisons that
have caused accidental deaths in industry. Mercury is the most volatile
of the trace constituents and is known to cause nerve damage and
possibly death. The fate of these trace elements is not known in the
gasification plant. Probably the largest fraction of the trace elements
will end up with the ash. More volatile elements will be quenched in
the tar separation section, thus ending up in the gas liquor system.
The likelihood of any of these trace elements becoming part of the
synthetic natural gas is very small.
A number of recent studies have indicated that large fractions
of trace elements do not end up in the ash (See Section 2.1.5).
Unfortunately good material balances were not achieved in all these
cases. In order to really determine the fate of trace elements
it is essential to do a complete study in which full material balances
can be accomplished. Table 10 lists the results of two such studies.
Note that the percentages listed in the table indicate the amount
of trace constituents that were not accounted for- A negative number
indicates that more of the trace element was recovered than was put
in.
-------
- 45 -
2.4 Noise
Although most of the coal gasification plants are expected to
be in remote areas near coal mines, noise pollution may be a problem.
Noise has been found excessive in a plant producing SNG from low
molecular weight hydrocarbons (54). Noise control plans should
comply with the 1971 Occupational Safety and Health Act (55) and
noise control measures should be designed into the system prior to
construction (56). Once construction is under way it becomes more
difficult to control noise in installed equipment. Gas fired
turbines should be enclosed and air and exhaust systems should be
properly muffled. Sound absorbing insulation should be placed on
piping and equipment as needed while sound absorbing walls and panels
should be used in buildings in which size reduction and screening
operations take place. The incinerator and boiler should include
modern design concepts which reduce combustion noise substantially.
-------
- 46 -
3. THERMAL EFFICIENCY
The overall plant thermal efficiency is an important technical
parameter in any fuel conversion process. It explains the quantities of
environmentally less acceptable fuels that have to be used to produce
environmentally acceptable ones. The heating value of fuel chat is consumed
must necessarily end up in the atmosphere as a waste product. The thermal
efficiency for the Lurgi dry ash gasification process has been calculated
in two manners. The first is for the indicated design (6) in which
electrical power and steam for plant use are produced from the burning of
fuel gas. The second is for a design that assumes that electricity and
steam for plant use are produced from direct coal combustion.
As can be seen from Tables 12 and 13 there is only a slight
gain in efficiency in burning coal as opposed to producing a fuel gas-
This difference might be even less, for some of the fuel gas is used in a
combined cycle operation to drive a gas turbine and part is used in a
fuel gas expander. This benefit is partially balanced by the air
compression necessary for the fuel gas case. Also, no energy debit was
taken for flue gas desulfurization in the coal case- The effects of these
changes on the overall conclusions are minor.
In order to realistically assess the thermal efficiency, all
the by-products were included as part of the effluent stream according
to their heating value. Thermal efficiency for producing SNG is 52.9%
in the fuel gas case. If one adds the heating value of the tar oils,
then the thermal efficiency goes up to 63.1%. If naphtha is
included, the efficiency becomes 64.8%, and when crude phenol is added
the efficiency becomes 65.570. The values for adding ammonia and sulfur
are also included in Table 12 but are not believed to be realistically
useable values. In the case of tin coal fired boiler (Table 13) the
thermal efficiency, including all of the by-products, adds up to 67.3%
and thus the potential advantage of burning the coal directly is only
0-7%. On the other hand, if the objective is to produce SNG then the
potential advantage in thermal efficiency is 2.2%.
It should be mentioned that 5 different methods of generating
steam and power for the Lurgi gasification process were investigated
by Steams-Roger (6) . They concluded that the fuel gas combined cycle
technique described in this report was as economical and efficient as
any of the other four. They felt that this system was less complex
and more reliable than a coal burning unit using flue gas desulfurization.
They studied the following cases: low Btu gas fired turbines with
heat recovery boilers, low Btu gas fired boilers, medium Btu gas fired
turbines with heat recovery boilers, coal tar and tar oil fired boilers
with medium Btu gasifier turbines, and tar and coal fired boilers with
steam turbine drives.
-------
- 47 -
Table 12
JEN
Coal to Oxygen Gasifier
Coal to Air Gasifier
TOTAL
OUT
Substitute Natural Gas
Tar
Tar Oil
Naphtha
Crude Phenol
Ammonia
Sulfur
, EFFICIENCY
Mass Rate
M Lb/Hr.
1722
440
2162
461
89-5
36.9
18.4
10.1
16.9
12.3
USING FUEL GAS FIRED
Heat Rate (HHV)
MM BTU/Hr
15280
3900
19180
10142
1387
572
318
141
164
49
BOILER
Cummulative
Thermal
Efficiency
Percent
--
--
—
52.9
60.1
63.1
64.8
65.5
66.3
66.6
-------
- 48 -
Table 13
IN.
Coal to
Coal to
Total
OUT
SNG
Tar
Tar Oil
Naphtha
Phenol
NH3
S
OVERALL THERMAL EFFICIENCY
Mass Rate
M Lb/Hr.
Oxygen Gasifi.er 1722
Boiler 353
2075
461
67.6
36.9
18.4
8.7
14.5
10.0
USING COAL FIRED BOILER
Heat Rate (HHV)
MM BTU/Hr
15278
3132
18410
10142
1048
572
318
122
141
40
Cummulative
Thermal
Efficiency,
Percent
—
--
--
55.1
60.8
63.9
65.6
66.3
67.0
67.3
-------
It should be pointed out that the thermal efficiency calculated
in Tables 12 and 13 are somewhat overstated since the higher heating
value of the by-products would not be fully recovered. Part of the
heating value would have to be used in achieving water vaporization.
The possibility of using coal and liquid by-products to fire the utility
boilers could present an alternative. Some, but not all of the under-
sized coal could be used, thus minimizing the amount of briquetting
that would be required. The liquid fuel by-products could also be
used in the superheated boiler in order to reduce the sulfur emissions
from that unit.
It should be pointed out that the products spectrum of the
gasification complex can be shifted depending on demand. Thus, if
substitute natural gas is the most desirable product, all the other
hydrocarbon liquids could be recycled through the gasifier to increase
the yield of SNG« Naturally, there would then be a sizeable debit
in overall thermal efficiency, although the efficiency to SNG production
would be increased. If the carbon containing by-products are gasified
then the overall thermal efficiency would be 59.6% (282 MM scfd SNG),
and 61.37. (278 MM scfd SNG) for fuel gas and coal fired power plant
respectively. If the carbon containing by-products are fired as fuel
in the power plant then the thermal efficiency would be 60.0% and
62.070 for fuel gas and coal respectively.
-------
- 50 -
4. PROCESS ALTERNATIVES
The present design of the Lurgi Dry Ash Gasification Process
was examined to assess its pollution potential and to estimate its thermal
efficiency. In this section, discussion will center around the potential
process improvements which will further optimize the pollution control
aspects of the process. This section of the report is subdivided into
three parts. The first part evaluates small modifications involving
simple design changes to improve pollution control. The second part
evaluates certain process improvements which might require some development
work. The last part assesses technology needs which might require
considerable research and development,
4 • 1 Engineering Modifications
The Lurgi design evaluated in this report is based on the
specific design by Steams-Roger for the El Paso Natural Gas Company (6).
The designer makes full use of the present state-of-the-art in minimizing
environmental problems. No major engineering modifications are apparent
which will significantly improve the pollution aspects of this design.
One of the engineering areas which might require some additional considera-
tion is the acid gas treatment section. This design uses a Linde-Lurgi
Rectisol system which is an extremely efficient method of removing acid
gases, but is a very high power consumer. In principle, this type of
acid gas treatment system should be able to separate the carbon dioxide
from the hydrogen sulfide. It is not clear from this design why the
two acid gases are not separated, but are sent jointly to the sulfur
recovery plant. Two other benefits of the Rectisol system are that naphtha
can be separated from the crude gas stream and that methanol also
acts as a dryer before final SNG compression.
Two potential alternatives present themselves in lieu of this
type of acid gas treatment. First, the Rectisol plant could be redesigned
to separate the hydrogen sulfide from the carbon dioxide in order to
increase the concentration of l^S and use a cheaper sulfur recovery process
such as a Claus Plant. The Glaus Plant would of course need some flue
gas treatment facilities. Since Stretford is being used as the sulfur
recovery process one could use an alternative acid gas treatment
process such as the promoted hot potassium carbonate (57). In addition
to a hot potash acid gas treatment section one would also need a dryer
to dry the final pipeline SNG stream.
In this design, the cooling water requirements have been
minimized by using air cooling as much as possible. Also, production
of a low Btu gas using a combined cycle for power generation has
allowed that portion of the design to be used very efficiently. A
relatively small item in the design involves the use of water scrubbing
in areas where coal dust can become a problem. Other techniques for
reducing the quantities of coal dust in the area should be considered
and might indeed be necessary. For example, electrostatic precipitation
or back filtration might be preferable.
-------
- 51 -
A .2 Process Improvements
A number of process alternatives can be discussed which will
improve the overall plant efficiency. These improvements, on the other
hand, might not optimize the economics of the process. For example,
using all the by-products except sulfur and ammonia as fuel for the
power plant and the superheater/incinerator combination with about
135,000 Ib/hr of coal, would increase the SNG production thermal
efficiency to approximately 627, and would meet all the air pollution
standards- Alternatively, coal could be used in the plant boilers but
flue gas desulfurization and dust removal would be required to meet
the environmental standards- Some additional efficiency could be
gained by using the coal fines to fuel the boiler since the briquetting
plant would not be needed. The third possibility would be to use
the coal fines in a slagging type gasifier (58) to produce the low
Btu gas needed to fire the power equipment. Thus, the coal fines are
utilized in producing a fuel gas-
A second processing improvement which would help reduce the
amount of sulfur emitted from the plant would be to use a carbonyl sulfide
hydrolysis step. This could be done either prior to the acid gas
treatment section (as for example, in the by-pass stream around the shift
reactor), or prior to the sulfur plant, since carbonyl sulfide tends
to go through a Stretford unit unreacted-
The possibilities of some slightly higher gasification pressures
should also be considered. Higher pressure gasification would tend to
reduce the oxygen requirements and the ultimate compression debit, thus
improving thermal efficiency. Similarly, if the steam input into the
gasifier could be reduced by going to somewhat higher conversion, the
thermal efficiency would also be improved. Some process improvements
are also possible in the area of methanation. There is research
going on at this time to optimize a fluid bed methanation reactor (59)-
This would allow for better heat transfer between the catalyst and the
water cooling tubes, and would save energy on gas recycle. Thus, the
efficiency and effectiveness of methanation would be improved.
4.3 Technology Needs
One of the principle objectives of the present study is to
anticipate potential pollution problems, thus calling attention to
any technology gap that might exist. Research and development programs
can then be instituted to meet the particular anticipated needs prior
to commercialization. In the present Lurgi design a carbonyl sulfide
hydrolysis section would be desirable since sulfur emissions from
-------
- 52 -
the superheater/incinerator stack could be reduced by over 1/3.
A high temperature raw gas treatment reactor would be very desirable
to minimize particulates and potential sulfur corrosion. In
terms of thermal efficiency, a high temperature acid gas removal would
increase thermal efficiency (60). The need to go from a relatively
hot gas down to temperatures below 0°F would thus be avoided.
Highly selective acid gas separation processes would be
very desirable since they would reduce the volume of gas that has to
go to the sulfur treatment plant and this would reduce the size of
the sulfur treatment plant (61).
A high pressure gasification process that could utilize coal
fines would remove the necessity for briquetting the fines. This
could improve thermal efficiency.
One of the areas of research and development in which information
is most lacking is the one that deals with the fate of trace elements.
It would seem essential to do complete material balances of trace elements
around all the gasification pilot plants that are under development.
Thorough studies of analytical techniques as well as sampling techniques
are required before the fate of the trace elements can be adequately
determined. Similarly, the ash from all the gasification pilot plants
should be studied in order ;.o determine its leachibility under a variecy of
conditions that simulate extremes in mine burial. The ability to dispose of
the ash in the mine will probably be a function of ash stability.
Other areas where information is lacking include composition
of dust and fumes from coal storage, analysis of water run-off from coal
storage, and composition of effluents in vapors from evaporation ponds,
cooling towers and vents.
-------
- 53 -
5. GLOSSARY AND CONVERSION FACTORS
Abbreviat ion
acfm
a tin
biox
BOD
Btu
cal
cfm
d
DAF
°C
°F
°K
°R
ft
gpm
g
HHV
hr
in
Kcal
KW
MW
MM
mol
Ib
ppm
psi
psia
psig
ROM
scfm
sec
SNG
M
W
Def inition
accual cubic feet per minute
atmosphere - unit of pressure
biological oxidation
biochemical oxygen demand
British thermal unit
calorie, ^hermochemical
cubic feet per minute
day
dry ash free (usually coal)
degree Celsius (Centigrade)
degree Fahrenheit
degree Kelvin
degree Rankin
foot
gallons per minute
gram
higher heating valve
hour
inch
kilocalorie
kilowatt
megawatt
million
mole
pound
parts per million
pounds per square inch
pounds per square inch absolute
pounds per square inch gauge
run of mine coal
standard cubic feet per minute (60°F, 14.7 psia)
second
synthetic natural gas
thousand
watt
-------
- 54 -
6. REFERENCES
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10. Anon. "Acid Mine Drainage Prevention Control Treatment", Coal Age
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11. Sevenster, P.G-, "Studies on the Interaction of Oxygen with Coal
in the Temperature Range 0-90°C, Part 1", Fuel, _40, 7 (1961).
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presented at the 4th Synthetic Pipeline Gas Symposium, Chicago,
October 1972.
13. Linton, J.A- and Tisdal, G-C-, "Commercial Production of Synthesis
Gas from Low Grade Coal", Coke and Gas _L9, 402 (1957) .
14. Ricketts, T.S-, "The Operation of the Westfield Lurgi Plant and the
High Pressure Grid System" Inst. of Gas Engrs . J.Oct. (1963).
15. Ranke, G-"The Rectisol Process - for che Selective Removal of C02
and Sulfur Compounds from Industrial Gases", Chemica 1 Economy and
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-------
- 55 -
16. Corey, R.C«, "Bureau of Mines Synthane Process: Research and Development
on Converting Coal to Substitute Natural Gas", presented at Che
Synthetic Fuels from Coal Conference, Stillwater, Okla., May 1972.
17. Latimer, R.E., "Distillation of Air", Chem. Eng. Progress j63, 35
(1967).
18. Ellwood, P. J"Meta-Vanada tes Scrub Manufactured Gas", Chemica 1 Engineering
pages 128-130, July 20, 1964.
19. Beers, W.D-, "Characterization of Claus Plant Emissions", EPA-R2-73-188
(April 1973).
20. Moyes, A.J. and Wilkinson, J.$•, "High-Efficiency Removal of K2S from
Fuel Gases and Process Gas Streams", Process Engineering (London),
September 1973,pp 101-105.
21. Lundberg, J.E."Removal of Hydrogen Sulphide from Coke Oven Gas by
the Stretford Process"presented at the 64th Annual Meeting of
the APCA, Atlantic City, N.J. June 27-July 2, 1971.
22. Agosta, J., Illian, H.F., Lundberg, R.M., and Trandy, O.G., "Status
of Low Btu Gas as a Strategy for Power Station Emission Control'^
65th Annual Meeting of Lhe AIChE, New York City, November 1972.
23. Lee, J."Select ing Membrane Pond Liners",Pollution Engineering
6, No. 1, 33 (1974) .
24. Betz Handbook of Industrial Water Conditioning by Betz, Trevose,
Pa.,Sixth Edition (1962).
25. Hamer, P., Jackson, J., and Thurston, E.F.,"Industria1 Water Treatment
Practice",Butterwor^hs, London 1961.
26. Rhodes, E.G.. "German Low-Temperature Coal Tar Industry", Bureau
of Mines I.e. 7490, February, 1949.
27. McCabe, J. and Eckenfelder, W.W-"Biologica1 Treatment of Sewage
and Industrial Wastes",Volz Reinhold (1958).
-------
- 56 -
28. Pershing, D.W., Brown, J.W., Martin, G-B., and Berkau, E.E., "Influence
of Design Variables on the Production of Thermal and Fuel NOX
from Residual Oil and Coal Combustion", Presented at the 66th
Annual AIChE Meeting, Philadelphia, November 1973, Paper 22C.
29. Anon, "Standards of Performance for New Stationary Success", Federal
Register 36^, No. 159, 15704, August 17, 1971-
30. Bartok, W., Crawford, A.R., Skopp, A., "Control of NOX Emissions from
Stationary Sources", Chem. Eng. Progress 67, 64 (1971).
31- Shaw, H., "The Effects of Water, Pressure, and Equivalence Ratio
on Nitric Oxide Production in Gas Turbines",Journal of Engineering
for Power, Trans. ASME, Series A, Accepted for Publication in 1974.
32. Crawford, A.R., Manny, E.H., and Bartok, W., "NOX Emission Control
for Coal-Fired Utility Boilers", presented at the "Coal Combustion
Seminar", Control Systems Laboratory, EPA, Research Triangle Park,
North Carolina, June 19-20, 1973.
33. Smith, W.S- and Gruber, C.W.,"Atmospheric Emissions from Coal
Combustion - An Inventory Guide", Public Health Service Publica-
tion No. 999-AP-24, April 1966.
34. Haugebrauck, R.P., Von Lehmden, D.J., and Meeker, J.E., "Emissions
of Polynuclear Hydrocarbons and Other Pollutants from Heat-Generation
and Incineration Processes, J. Air Pollution Control Assoc. 14,
267 (1964).
35- Anon, "Petrochemical Evaporation Loss from Storage Tanks", API
Bulletin No. 2523, November 1969.
36. Attari, A. ,"Fate of Trace Constituents of Coal During Gasification",
EPA-650/2-73-004, August 1973.
37. Bolton, W.E., Carter, J-A-, Energy, J.F., Feldman, C-, Fulkerson, W.,
Hulett, L.D., and Lyon, W.L., "Trace Element Mass Balance Around
a Coal Fired Steam Plant", Presented at the 166th ACS National
Meeting, August, 26-31, 1973.
38. Phillips, M.A., "Investigations into Levels of Both Airborne
Beryllium and Beryllium in Coal at the Hayden Power Plant Near
Hayden, Colorado", Environmental Letters 5_, 183 (1973) .
39. Schultz, H.j Hattman, E.A., and Booher, W.B., "The Fate of Some
Trace Elements During Coal Pretreatment and Combustion", Presented
at the 166th ACS National Meeting, August, 26-31, 1973.
40. Billings, C'.E., et al., "Mercury Balance on a Large Pulverized
Coal-Fired Furnace", J. Air Pollution Control Association 23,
773 (1973).
-------
- 57 -
41. Jansson, S-A-, "Reactions of Alkali Metal Compounds During Coal
Gasification for Electric Power Generation", Presented at the
166th ACS National Meeting, August, 26-31, 1973.
42. Capes, C.E., Mcllhinney, A.E., Russell, D-S-, and Sirianni, A.F.,
"Rejection of Trace Metals from Coal During Beneficiation by
Agglomeration", Environ. Sci. and Tech., 8_, 35 (1974).
43. Albernathy, R.F., and Hattman, E.A., U-S- Bureau of Mines Rep.
Invest. 7452, November 1970.
44. Farnand, J.R., and Puddington, I.E., "Oil-Phase Agglomeration of
Germanium-Bearing Vitrain Coal in a Shale Sandstone Deposit",
Can Mining Met. Bull. 6_2, 267 (1969).
45. Ruch, R.R., Gluskoter, H.J., and Kennedy, E.J., "Mercury Content
of Illinois Coals", 111. State Geol. Survey.
46. Myers, L.H., and Mayhue, L.F., "Advanced Industrial Water Treatment
Processes for the Petroleum Refining Organic Chemical Industry",
Presented at the 65th Annual AIChE Meeting, New York, December 1972.
47. Beychok, M.R., "Aqueous Wastes from Petroleum and Petrochemical
Plants", John Wiley and Sons, London (1967).
48. Kostenbader, P.D., and Flecksteiner, J.W., "Biological Oxidation
of Coke Plant Weak Ammonia Liquor", Journal WPCF, 41, No. 2,
1969, p. 199-
49. Moellen, F.W., et al., "Methanation of Coal Gas for SNG", Hydrocarbon
Proc., April, 1974, p. 69-
50. Lowry, H.H., Ed., "Chemistry of Coal Utilization" Supp. Vol., 1019
John Wiley and Sons, New York (1963).
51- Anon, "The Southwest Energy Study" Mining Appendix J., U-S-
Department of the Interior, Washington, D.C- (1972).
52. Colorado State University, "Water Pollution of Spent Oil Shale
Residues", for EPA, PB No. 206, 808, December 1971.
53. Magee, E. M., Hall, H. J., and Varga, G. M-, Jr., "Potential
Pollutants in Fossil Fuels", EPA-R2-73-249, June 1973, PB
No. 225 039.
54. Anderson, D.E., "First Large Scale SNG Plant", Oil and Gas J.,
January 21, 1974, p. 74.
55. Anon, "Occupational Safety and Health Administration", Federal
Register, 36 No. 105, Part II, May 29, 1971.
56. Lowery, R. L., "Noise Control A Common-Sense Approach", Mechanical
Engineering, 95, No. 6, 26 (1973).
-------
- 58 -
57- Field, J.H.., Johnson, G.E., Benson, H-E-, and Tosh, J.S-,
"Removing Hydrogen Sulfide by Hot Potassium Carbonate Absorption"
Report of Investigation 5660, U.S. Department of the Interior,
Washington, B.C., 1960.
58. Magee, E.M., Jahnig, C.E., and Shaw, H«, "Evaluation of Pollution
Control in Fossil Fuel Conversion Processes: Gasification; Section 1:
Koppers-Totzek" EPA-650/2-74-009a, January 1974.
59. Grace, R.J., Brant, U.L., and Kliewer, V.D., "Design of Bi-Gas
Pilot Plant'1, 5th Synthetic Pipeline Gas Symposium, Chicago,
Illinois October, 29-31, 1973.
60. Ruth, L.A., Graff, R.A., and Squires, A.M., "Desulfurization of
Fuels with Calcined Dolomite: IV Reaction of CaC03 with H2S",
Presented at the 71st AIChE National Meeting, Dallas, Texas,
February 22, 1972 (Paper No. 286).
61. Anon, "Evaluation of Coal Gasification Technology", Part II, National
Academy of Engineering, COPAC-7, Washington, D.C. (1973).
-------
- 59 -
APPENDIX I
Material Balance For A Lurgi
Dry Ash SNG Gasification Plant
The mass flow rates and stream compositions are given in Table
14. The flow rates were taken from the El Paso FPC application (6) and
are presented here with minor modification. The material balance points
are numbered according to Figure 1. The Figure is repeated in this
appendix for convenience.
-------
Figure 1
PROCESS FLOW DIAGRAM FOR LURGT DRY ASH GASIFICATION PROCESS
Nitrogen Tar and
And Oxygen Boil Off Tar Oil
Air
Air
Air
Coal
Power
1.5 MW
Incinerator
Recompressed
Lock Hopper Gas
H8> rs
Quench
Water
Superheater^
By Pass Gas
Gasifier Purification
Compression
Coal
Preparation
ttethanation
Dehydration
Water to Treatment Area
Liquor From Air Blown
Gasifier>.
Effluent Water Evaporation
Make-Up
Wa.ter
To Superheaten
Evaporation
and Purifi-
Wet Ash
To Mine
Evaporat ior
Make-Up Water
Wa ter Phenols
Water
Lime
SludRe
(24.1%)
-------
Table 14 (Cont'd")
Stream Number
Stream Identification
CO
C02
H2
CH4
C2H4
C2H6
H2S
COS
S02
NH3
N2 + Ar
02
N02
TOTAL DRY GAS
Water
Coal MAP
Ash
Sulfur
MW
28.01
44.01
2.02
16.04
28.05
30.07
34.08
60-07
64.06
17.03
28.00
32.00
46.00
LURGI DRY ASH GASIFICATION PROCESS
MATERIAL BALANCE, LB/HR
51 52 53 54 55 56
Evaporation Evaporation
From Evaporation From Air To Air From
Raw Water Blow Down From Pond Ash Quench Cooling Tower Cooling Tower
33,901,400 33,901,400
10,298,600 10,298,600
44,200,000 44,200,000
72,560 105,100 363,000 79,100 243,300 1,300,000
Naphtha
Tar Oil Naphtha
Tar
Crude Phenol
i
cr
TOTAL
72,560
105,100
363,000
79,100
44,443,300
45,500,000
-------
Table 14
Stream Number
Stream Identification
CO
C02
H2
CH,
C2H6
H2S
COS
S02
NH3
N2 + Ar
02
N02
TOTAL DRY GAS
Water
Coal MAF
Ash
Sulfur
Naphtha
Tar Oil Naphtha
Tar
Crude Phenol
MW
28.01
44.01
2.02
16.04
28.05
30.07
34.08
60.07
64.06
17.03
28.00
32.00
46.00
LURGI DRY ASH GASIFICATION PROCESS
MATERIAL BALANCE, LB/HR
1 2 3
Coa 1 to 02 Raw
ROM Coal Gasifier Product Gas
535,315
1,243,519
76,665
173,954
10,973
17,937
9,960
220
10,952
2,079,495
356,525 283,975 1,287,646
1,431,694 1,140,354
374,016 297,906
18,369
36,892
27,058
4,365
4
Shift
Feed Gas
257,821
598,910
36,924
83,780
5,285
8,639
4,821
107
5,275
1,001,562
620,154
8,847
17,768
13,032
2,102
5
Crude Gas
to Gas Cooling
300,723
752,660
43,001
100,069
6,954
10,852
6,196
138
6,157
1,226,750
710,772
9,522
19 , 124
14,026
2,263
6
Shift
Product Gas
58,754
911,971
51,287
83,780
5,285
8,639
4,821
107 '
K)
5,275
1,129,919
464,526
8,847
17,768
TOTAL
2,162,235
1,722,235
3,453,825
1,663,465
1,982,547
1,621,060
-------
Table 14 (Cont'd)
LURGI DRY ASH GASIFICATION PROCESS
Stream Number
Stream Identification
CO
C02
H2
CHA
C2H4
C2H6
H2S
COS
S02
NH3
N2 -f Ar
02
N02
TOTAL DRY GAS
Water
Coal MAF
Ash
Sulfur
MW
28.01
44.01
2.02
16.04
28.05
30.07
34.08
60.07
64.06
17.03
28.00
32.00
46.00
7
Gas to
Purification
359,578
1,625,166
94,279
183,836
12,238
19,471
11,017
245
11,431
2,317,261
3,061
MATERIAL
8
Met ha nation
Feed
351,965
200,378
93,384
181,969
5,666
9,096
"* *"
11,183
853,641
BALANCE, LB/HR
9 10 U 12
Ash
Met ha nation From 0£
Product SNG Gasifier Steam
924 924
115,451 24,338
417 417
430,130 432,714
11,183 11,183
558,106 460,576
1,594 1,762,170
16,104
297,906
CO
I
Naphtha
Tar Oil Naphtha
Tar
Crude Phenol
18,369
TOTAL
2,338,691
853,641
559,700
460,576 314,010
1,762,170
-------
Stream Number
Stream Identification
CO
C02
H2
CH4
C2H4
C2H6
H2S
COS
S02
NH3
N2 + Ar
02
N02
TOTAL DRY GAS
Water
Coal MAF
Ash
Sulfur
MW
28 .01
44.01
2.02
16.04
28.05
30.07
34.08
60.07
64.06
17.03
28.00
32.00
46.00
Table 14 (Cont 'd)
LURGI DRY ASH GASIFICATION PROCESS
MATERIAL BALANCE, LB/HR
13 14 15 16
Air Feed Lock
To Oxygen Nitrogen Hopper
Production Oxygen Waste Gas
23,229
108,051
3,260
9,895
1,265
1,555
1,057
25
480
1,559,334 10,227 1,549,107
473,717 458,240 15,832
2,033,051 468,467 1,565,980 148,818
11,190 — 1,590 43,290
17 18
Tar
By-Product Gas Liquor
30,140
1,490,699
Naphtha
Tar Oil Naphtha
Tar
Crude Phenol
36,892
89,490
TOTAL
2,044,241
468,467
1,567,570
192,108
126,382
-------
Stream Number
19
Naphtha
Stream Identification Product
CO
C02
H2
CH4
C2H4
C2H&
H2S
COS
so2
NH3
N2 + Ar
02
N02
TOTAL DRY GAS
Water
Coal MAP
Ash
Sulfur
MW
28.01
44.01
2.02
16.04
28.05
30.07
34.08
60.07
64.06
17.03
28.00
32.00
46.00
Table 14 (Cont'd)
LURGI DRY ASH GASIFICATION PROCESS
MATERIAL BALANCE, LB/HR
20 21 22 23 24
Treated Gas Liquor
Water Phenol Ammonia Vent To Sulfur Plant
To Re-Use Product Solution Incineration Feed
2,056
8,450 1,695,595
164
4,111
5,686
9,445
13,571
306 i
Ol
16,858 860 '
1,176
9,310 1,732,110
1,406,124 53,028 35 1,896
Naphtha
Tar Oil Naphtha
Tar
Crude Phenol
TOTAL
18,369
18,369
1,406,124
10,142
10,142
69,886
9,345
1,734,006
-------
Table 14 (Cont'd)
Stream Number
Scream Identification
CO
C02
H2
CH4
C2H4
C2H6
H2S
COS
S02
NH3
N2 + AT
02
N02
TOTAL DRY GAS
Water
Coal MAF
Ash
Sulfur
MW
28.01
44.01
2.02
16.04
28.05
30.07
34.08
60.07
64.06
17.03
28.00
32.00
46.00
25
Sulfur
Plant
Effluent
2,056
1,695,595
164
4,1H
5,686
9,445
632
306
21,814
1,739,809
8,977
LURGI DRY ASH GASIFICATION PROCESS
MATERIAL BALANCE, LB/HR
26 27 28
By-Product Superheater Coal To
Sulfur Flue Gas Air Gasifier
1,828,643
306
1,258
554,425
6,212
176
2,391,020
88,806 72,550
291,340
76,110
12,161
29 30
Ash From Air To
Air Gasifier Air Gasifier
447,241
135,805
583,046
3,209
4,114
76,110
Naphtha
Tar Oil Naphtha
Tar
Crude Phenol
o^
I
TOTAL
1,748,786
12,161
2,479,826
440,000
80,224
586,255
-------
Table 14 (Conc'd)
LURGI DRY ASH GASIFICATION PROCESS
MATERIAL BALANCE, LB/HR
Stream Number
31
Steam To
Stream identification Air Gasifier
CO
C02
H2
CH4
C2H4
C2H6
H2S
COS
S02
NH3
N2 + Ar
N2
TOTAL DRY GAS
Water
Coal MAF
Ash
Sulfur
MW
28.01
44.01
2.02
16.04
28.05
30.07
34.08
60.07
64.06
17.03
28.00
32.00
46.00
311,960
32
Clean
Fuel Gas
188,076
78,703
17,826
36,730
2,797
4,516
259
6
445,126
774,039
45,027
33 34 35 36
Power Gas Liquor Acid Gas
Plant Wet Ash From From
Flue To Mine Air Gasifier Fuel Gas
398
460,211 187,487
45
91
25
27
2,554
61
432
1,801,185 1,040
39,132
537
2,301,497 191,728
272,668 72,500 1,896
20,218
374,016
37
Air To
Superheater
471,699
144,381
616,080
3,391
Naphtha
Tar Oil Naphtha
Tar
Crude Phenol
10,806
I
cr>
TOTAL
311,960
829,872
2,574,165 466,734
213,165
193,624
619,471
-------
Stream Number
Stream Identification
CO
C02
H2
CHZ,
C2H6
H2S
COS
S02
NH3
N2 + Ar
02
N02
TOTAL DRY GAS
Water
Coal MAF
Ash
Sulfur
MW
28.01
44.01
2.02
16.04
28.05
30.07
34.08
60.07
64.06
17.03
28.00
32.00
46.00
Table 14 (Cont'd)
LURGI DRY ASH GASIFICATION PROCESS
MATERIAL BALANCE, LB/HR
38 39 40 41 42 43 44
Fuel Gas Sulfur Treated Treated
To Plant Water Water Methanation
Superheater Air To Steam Non-Steam Raw Water Lime Sludge Water Product
25,766
10,782
2,442
5,032
383
619
36
60,982 20,597
6,212
106,043 26,809
6,170 148 2,248,000 337,770 2,455,000 90,072 294,235
o\
oo
Naphtha
Tar Oil Naphtha
Tar
Crude Phenol
TOTAL
112,213
26,957 2,248,000 337,770 2,455,000
90,072
294,235
-------
Stream Number
Stream Identification
CO
coz
H2
CH4
C2H^
C2H6
H2S
COS
S02
NH3
N2 + Ar
02
N02
TOTAL DRY GAS
Water
Coal MAP
Ash
Sulfur
28.01
44.01
2.02
16.04
28.05
30.07
34.08
60.07
64.06
17 .03
28.00
32.00
46.00
Table 14 (Cont 'd)
LURGI PRY ASH GASIFICATION PROCESS
MATERIAL BALANCE, LB/HR
45 46 47 48 49 50
Tar Oil Evaporation Drift
Water To Air To Naphtha Evaporation From Loss From
Ash Disposal Boilers Product From Biox Cooling Tower Cooling Tower
1,417,243
440,747
1,857,990
72,500 10,226 87,570 1,170,000 130,000
Naphtha
Tar Oil Naphtha
Tar
Crude Phenol
I
\D
36,892
TOTAL
72,500
1,868,216 36,892
87,570
1,170,000
130,000
-------
- 70 -
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing}
1. REPORT NO.
EPA-650/2-74-009-C
2.
3. RECIPIENT'S ACCESSION-NO.
4-TITLEANDSUBTITLEEvaluation of Pollution Control in
Fossil Fuel Conversion Processes; Gasification;
Section I: Lurgi Process
5. REPORT DATE
July 1974
«. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
H. Shaw and E. M. Magee
8. PERFORMING ORGANIZATION REPORT NO.
GRU.5DJ.74
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Exxon Research and Engineering Company
P. O. Box 8
Linden, New Jersey 07036
10. PROGRAM ELEMENT NO.
1AB013; ROAP 21ADD-023
11. CONTRACT/GRANT NO.
68-02-0629
12. SPONSORING AGENCY
MME AND ADDRESS
EPA, Office of Research and Development
NERC/RTP, Control Systems Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
The report gives results of a review of the Lurgi Dry Ash Gasification Process for
high-Btu gas , from the standpoint of its potential for affecting the environment. The
review included a process analysis of the process. Waste stream compositions were
calculated for a 250 million scfd substitute natural gas plant using a subbituminous
coal. Thus, the quantities of solid, liquid, and gaseous pollutants were estimated.
where possible. Thermal efficiency was calculated for various process alternatives.
A number of process modifications were suggested which would reduce pollution and/
or increase thermal efficiency. The report includes an assessment of technology
needs to control pollution.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b. IDENTIFIERS/OPEN ENDED TERMS
c. COSATI I-icId/Group
Air Pollution
Coal Gasification
Fossil Fuels
Thermal Efficiency
Trace Elements
Air Pollution Control
Stationary Sources
Clean Fuels
Lurgi Process
Fuel Gas
Low-Btu Gas
Research Needs
13B
13H
2 ID
20M
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
70
20. SECURITY CLASS (Tin's pane)
Unclassified
22. PRICE
EPA Form 222O-1 (9-73)
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