Note: Descriptions are shown in the official language in which they were submitted.
1~7966
~ACI~ROUND OF THE INVENTION
l. Field of the Invention
This invention pertains to the partial oxidation
process. More specifically it pertains to the manufacture
of a clean fuel gas for use in a power producing gas turbine. ~ -
2. Description of the Prior Art
In the conventional partial oxidation process, less
than stoichiometric amounts of oxygen are reacted with a
hydrocarbonaceous fuel optionally in the presence of a
temperature moderator to produce a gaseous mixture compris-
ing H2+CO.
In coassigned U.S. Patent 2,975,594 the liquid
hydrocarbon feed to a precombustor contains substantial
amounts of heavy metal compounds. By producing unreacted
carkon in the amount of 0.5 to 10~ of the carbon contained
in the hydrocarbon and at least 50 times the combined weight
of nickel and vanadium a carbon-ash composite is produced
which may be separated. The resulting ash-free gas may be ~-
introduced-into the combustor of a gas turbine. Air may be
compressed by a compressor driven by said turbine, passed
in heat exchanger with the exhaust gas from the turbine, and ~ -
recycled to both combustors. In coassigned U.S. Patent
3,868,817, turbine fuel gas is produced by partial oxidation
in the presence of a temperature moderator selected from
the group consisting of at least a portion of the CO2-rich
stream from the gas purification zone,at least a portion of
the turbine exhaust gas, and mixtures thereof.
-1-
1~79~i6
SUMMARY
Gaseous streams comprising ~2 and CO and at least
one member of the group CO2, H20, CH4, H2S, COS, N2, A, and
particulate carbon are made by the partial oxidation of a
hydrocarbonaceous fuel with a stream of preheated free~oxygen
containing gas i.e.air,oxygen-enriched air, and substantially
pure oxygen, optionally in the presence of a temperature
moderating gas in the reaction zone of a free-flow partial
oxidation gas generator at a temperature in the range of
about 1800 to 3000F and a pressure in the range of about 10
to 200 atmospheres. The effluent gas stream from the gas
generator is cooled, cleaned and if necessary purified to
produce a clean product gas. Prior to being introduced
into the gas generator, the free-oxygen containing gas
is compressed and then heated in a gas fired pressurized
heater by the total combustion or partial oxidation of a
portion of said product gas with air. A second portion of
said product gas is burned with air in the combustor of
a gas turbine comprising said combustor and anexpansion
turbine. The flue gas from the fired pressurized heater,
along with the exhaust gas leaving said combustor may
be introduced into said power-developing expansion turbine as
the working fluid. Alternatively, the flue gas from the
pressurized heater may be mixed with at least a portion
of the remaining product gas, and the mixture of gases
is then introduced into said combustor as the fuel.
Power for operating an electric generator and at least
one compressor for compressing free-oxygen containing
11q~7966
gas or air is obtained from said expansion turbine. An air
or oxygen boost compressor may be driven by a steam turbine.
Superheated steam for use as the working fluid in the steam
turbine may be obtained by passing saturated stream in
indirect heat exchange with the exhaust gas from said
expansion turbine.
One aspect of the subject invention pertains to a
process for the production of an H2 and CO-containing gas
stream along with power comprising: (1) producing a raw
process gas stream comprising H2, and CO and at least one
member of the group CO2, H2O, H2S, COS, CH4, N2, A, and
entrained particulate solids in the reaction zone of a free-
flow gas generator by the partial oxidation of a hydro-
carbonaceous fuel with a heated stream of free-oxygen
containing gas and in the presence of a temperature moderator,
at a temperature in the range of about 1800 to 3000 F and
a pressure in the range of about 10 to 200 atmospheres; (2)
removing entrained solids if any, cooling, cleaning, and
dewatering, said H2 and CO-containing gas stream; (3)
dividing at least a portion of said H2 and CO-containing gas
stream from (2) into a first gas stream which is reacted in
the combustion chamber of a pressurized heater as fuel
producing a stream of flue gas, and into a second gas stream
which is burned as fuel in the combustor of a gas turbine
comprising said combustor and an expansion turbine thereby
producing a stream of exhaust gas, and passing said stream
of exhaust gas through said expansion turbine as the working
fluid; and (4) compressing a stream of free-oxygen containing
~- .
l~L~7~66
gas in gas compression means powered by said expansion
turbine, heating at least a portion of the compressed free-
oxygen containing gas in said pressurized heater, and
introducing the heated compressed free-oxygen containing gas
into the gas generator in step (1).
BRIEF DESCRIPTION OF THB DRAWING
The invention wilI be further understood by reference
to the accompanying drawing which is a schematic representation
of a preferred embodiment of the process.
DE5~RIPTION OF THE INVENTION
This invention pertains to an improved continuous
partial oxidation gasification process for producing synthesis
gas, reducing gas, or fuel gas along with the production of
mechanical power, and optionally electrical energy. The raw
gas stream from the gas generator comprises H2 and CO and at
least one member of the group CO2, H2O, CH4, H2S, COS, N2,
A, and entrained particulate solids, i.e. carbon, and ash. `
The effluent gas is produced in the refractory lined reaction
zone of a separate free-flow unpacked noncatalytic partial
oxidation fuel gas generator. The gas generator is preferably
a vertical steel pressure vessel, such as shown in the
drawing and described in coassigned U.S. Pat. No. 2,992,906
issued to F. E. Guptill, Jr.
A wide range of combustible carbon containing
organic materials may be reacted in the gas generator with a
free-oxygen containing gas optionally in the presence of a
temperature moderating gas to produce said raw gas stream.
-3a-
, ,,
,,., ~,
71~6
The term hydrocarbonaceous as used herein to
describe various suitable feedstocks to the partial
oxidation gas generator is intended to include gaseous,
liquid, and solid hydrocarbons, carbonaceous materials,
and mixtures thereof. In fact, substantially any
combustible carbon containing organic material, fossil fuel,
or slurries thereof, may be included within the definition
of the term "hydrocarbonaceous." For example, there are
(1) pumpable slurries of solid carbonaceous fuels, such
as coal, lignite, particulate carbon, petroleum coke,
concentrated sewer sludge, and mixtures thereof in water
or a liquid hydrocarbon; (2) gas-solid suspension such as
finely ground solid carbonaceous fuels dispersed in
either a temperature moderating gas or in a gasoous
hydrocarbon; and (3) gas- liquid-solid dispersions, such ~-
as atomized liquid hydrocarbon fuel or water and
particulate carbon dispersed in a temperature-moderating
gas. The hydrocarbonaceous fuel may have a sulfur
content in the range of O to 10 weight percent and an ash
content in the range of about O to 50 weight percent.
The term liquid hydrocarbon, as used herein
to describe suitable liquid feedstocks, is intended to
include various materials, such as liquefied petroleum
; gas, petroleum distillates and residues, gasoline,
naphtha, kerosine, crude petroleum, asphalt, gas oil,
residual oil, tar-sand oil and shale oil, coal derived
oil, aromatic hydrocarbon (such as benzene, toluene,
xylene fractions), coal tar, cycle gas oil from fluid-
catalytic-cracking operation, furfural extract of coker
7~366
gas oil, and mixtures thereof. Gaseous hydrocarbon
fuels, as used herein to describe suitable gaseous feed-
stocks, include methane, ~thane, propane, butane,
pentane, natural gas, water-gas, coke-oven gas, refinery
gas, acetylene tail gas, ethylene off-gas, synthesis gas,
and mixtures thereof. Both gaseous and liquid feeds may
be mixed and used simultaneously, and may include
paraffinic, olefinic, naphthenic, and aromatic compounds
in any proportion.
Also included within the definition of the term
hydrocarbonaceous are oxygenated hydrocarbonaceous organic
materials including carbohydrates, cellulosic materials,
aldehydes, organic acids, alcohols, ketones, oxygenated
fuel oil, waste liquids and by products from chemical
processes containing oxygenated hydrocarbonaceous organic
materials and mixtures thereof.
The hydrocarbonaceous feed may be at room
temperature of it may be preferably preheated to a tem-
perature up to as high as about 600F to 1200F, say 800F but
preferably below its cracking temperature. The hydro-
carbonaceous feed may be introduced into the burner in
liquid phase or in a vaporized mixture with a temperature
moderator. Suitable temperature moderators include
steam, water, C02-rich gas, nitrogen in air, by-product
nitrogen from a conventional air separation unit, and
mixtures of the aforesaid temperature moderators.
--5--
97~66
The use of a temperature moderator to moderate
the temperature in the reaction zone depends in general
on the carbon to hydrogen ratio of the feedstock
and the oxygen content of the oxidant stream. A temperature
moderator may not be required with some gaseous hydrocarbon
fuels, however, generally, one s used with liquid hydrocar-
bon fuels and with substantially pure oxygen. The
temperature moderator may be introduced in admixture
with either or both reactant streams. Alternatively, the
temperature moderator may be introduced into the reaction
zone of the gas generator by way of a separate conduit
in the fuel burner. It may be at a temperature in the
range of about ambient to 1200F, say 300 to 600F.
The weight ratio of total amount of H20 to fuel
introduced into the reaction zone of the gas generator
is the range of about 0 to 5.
7~7hen comparatively small amounts of H20 are
charged to the reaction zone, for example through the
burner to cool the burner tip, the H 0 may be mixed with
either the hydrocarbonaceous feedstock, the free-oxygen
containing gas, the temperature moderator, or a
combination thereof. In such case, the weight ratio of
water to hydrocarbonaceous feed may be in the range of
about 0.0 to 1.0 and preferably 0.0 to less than 0.2.
~IL~L~79~
The term free-oxygen containing gas, as used
herein is intended to include air, oxygen-enriched air,
i,e. greater than 21 mole % oxygen, and substantially
pure oxygen, i.e. greater than 95 mole ~ oxygen (the
remainder comprising N2 and rare gases). Free-oxygen
containing gas may be introduced into the gas generator
burner at a temperature in the range of about 400 to
1800F. The free-oxygen containing gas is heated in a
gas fired pressurized heater, to be further described,
prior to being introduced into the burner in the gas
generator. The ratio of free oxygen in the oxidant
introduced into the gas generator to carbon in the
feedstock (O/C, atom/atom) is preferably in the range of
about 0.7 to 1.5.
The feedstreams may be introduced into the
reaction zone of the gas generator by means of fuel
burner, su~h as the annulus-type burner in coassigned
U.S. Pat. No. 2,928,460 issued to duBois Eastman et al.
Any other suitable burner may be employed.
The feedstreams are reacted by partial oxidation
in the reaction zone of the free-flow gas generator at
an autogenous temperature in the range of about 1800F to
3000F, such as 2000 to 2900F, and at a pressure in the
range of about 10 to 200 atmospheres absolute, such as
about 30 to 100 atm. abs. No catalyst is required.
The reaction time in the gas generator is about 1 to 10
seconds.
7~66
The raw effluent gas stream from the generator may have
the following composition in mole %: H2 8.0 to 60.0,
CO 8.0 to 70.0, CO2 1.0 to 50.0, H20 2.0 to 5Q.0,
CH4 ~ to 30.0, H S 0.0 to 1.0, COS 0.0 to 0.7, N2
to 80.0, and A 0.0 to 1.8. Unreacted particulate carbon (on
the basis of carbon in the feed by weight) is usually present
in the effluent gas stream in the amount of about 0.2 to
20 weight percent with liquid feeds, but is usually
negligible with gaseous hydrocarbon feeds. ~olid fuels ;
such as coal may contain up to 50 wt. ~ ash. The specific
composition of the effluent gas is dependent on actual
operating conditions and feedstreams. Synthesis gas
substantially comprises H2+CO; all or most of the H20
and CO2 are removed for reducing gas; and the CH4 content
is controlled for fuel gas, and depends on the desired
heat of combustion.
A continuous stream of hot effluent gas, at
substantially the same temperature and pressure as in the
reaction zone leaves from the axial exit pOrt of the
gas generator and is then cooled, cleaned, dewatered and
optionally purified. Optionally, for hydrocarbonaceous
fuels containing a high ash content such as coal, a
solids separation zone may be inserted between the exit
port of the gas generator and a gas cooler.
The solids separation zone may comprise any suitable
gravity or cyclone separator or other physical cleaning
means for removing at least a portion of any solid matter
that may be entrained in the hot effluent gas stream,
or which may flow from the gas generator i.e. particulate
7966
carbon, ash, metal constituents, scale, slag, bits of
refractory, and mixtures thereof. For example, a catch-pot,
slag chamber,cyclone separator, electrostatic precipitator,
or combinations of such schemes may be used
The solid particles are separated from the effluent gas
stream and recovered with very little, if any temperature
or pressure drop in the process gas stream. Typical slag
chambers that may be employed are shown in the attached
drawing and in the drawing for coassigned U.S. Patent No.
3,528,930.
Preferably, the process gas stream leaving the gas
generator or the solids separation zone is cooled to a
temperature in the range of about 200 to 1200F, such as
400 to 600F by indirect heat exchan~e with water in
said gas cooler. Steam is simultaneously produced in the
gas cooler having a temperature in the range of about
400 to 650F. Optionally, this steam may be superheated
to a temperature in the range of about 750F to 1200F by
indirect heat exchange with turbine exhaust gas in a manner
to be further described.
Alternately, the aforesaid solids separation zone
and gas cooler may be replaced by direct quenching of the
effluent gas stream from the gas generator in water
in a ~uench tank such as shown in coassigned U.S. Pat,
No. 2,896,927. As the process gas stream bubbles through
water maintained at a temperature in the range of about
50 to 450F substantially all of the particulate carbon
and other entrained solids such as ash are scrubbed from
the process gas stream and water is vaporized. A dispersion
iL:iL~7966
of water and s1ids e.g. particulate carbon, ash is
removed from the bottom of the quench tank and separated
by conventional liquid-solids separation processes e.g.
settling, filtration, centrifuge, liquid hydrocarbon
extraction. Clarified water may be returned to the
quench tank.
In the preferred embodiment, after the effluent
gas stream from the gas generator is cooled in a gas
cooler it is introduced into a gas-liquid scrubbing zone
where it is scrubbed with a scrubbing fluid such as
liquid hydrocarbon or water in order to remove any
entrained particulate carbon. A suitable liquid-gas
tray-type column is more fully described in coassigned
U.S. Pat. 3,916,382 - C. P. Marion. Thus, by passing
the process gas stream up a scrubbing column in direct
contact and countercurrent flow with a suitable scrubbing
fluid or with dilute mixtures of particulate carbon and
scrubbing fluid flowing down the column, the particulate
carbon may be removed. A slurry of particulate carbon
and scrubbing fluid is removed from the bottom of the
column and sent to a carbon separation or concentration
zone. This may be done by any conventional means that may
be suitable e.g. filtration, centrifuge, gravity settling,
or by liquid hydrocarbon extraction such as the process
described in coassigned U.S. Pat. No. 2,992,906. Clean
scrubbing fluid or dilute mixtures of scrubbing fluid and
particulate carbon are recycled to the top of the column
for scrubbing more gas.
--10--
7~66
Other suitable conventional gas cooling and
cleaning procedures may be used in combination with or in
place of the aforesaid scrubbing column. For example, the
process gas stream may be introduced below the surface of a
pool of quenching and scrubbing fluid by means of a dip-tube
unit. Or the process gas stream may be passed through
a plurality of scrubbing steps including an orifice-type
scrubber or venturi noz~le scrubber such as shown in
coassigned U.S. Pat. 3,61~,296.
The clean process gas stream may be cooled
below the dew point and dewatered by indirect heat exchange
with at least a portion of the H +CO-containing product
gas and with boiler feed water. The water condensed from
the gas stream may be used elsewhere in the process, for
example in the gas cleaning zone, or in the preparation
of liquid-solid slurry feeds to the gas generator.
In another embodiment of the invention the fuel
to the partial oxidation gas generator may contain sulfur
compounds which appear in the effluent gas stream from
the generator as H2S and COS. In such case it may be
desirable to reduce the concentration of H2S and COS
in the process gas to below the level of chemical attack
on the turbine and gas compressors. To protect the
environment, it may be desirable to reduce the concentration
of CO2, H S and COS in the product gas or in the turbine
exhaust gas which is vented to the atmosphere. The coole~
cleaned, and dewatered process gas stream may be purified
by removing acid-gases i.e. H2S, COS, and CO2 in an acid-gas
7~;6
absorption zone. Advantageously, this will permit
reduction of the si~e and cost of the gas compressors. It
will also upgrade the composition of the product gas stream,
and prevent environmental pollution when the product gas is
used as a fuel gas. Further, it will also prevent sulfur
contamination of any downstream catalyst that the product
gas may come in contact with.
Any suitable conventional process may be used
to remove the gaseous impurities i.e. H2S, COS, CO2 in
the gas purification zone. For example, ref_igeration and
physical or chemical absorption with solvents, such as
methanol, n-methylpyrrolidone, triethanolamine, propylene
carbonate, or alternately with hot potassium carbonate may
be used. In solvent absorption processes, most of the
C2 absorbed in the solvent may be released by simple
flashing. The rest may be removed by stripping. This
may be done most economically with nitrogen. Nitrogen
may be available as a low cost by-product when a conven-
tional air separation unit is used for producing substan-
tially pure oxygen (95 mole percent 2 or more) for use
as the free-oxygen containing gas used in the gas generator.
The regenerated solvent is then recycled to the absorption
column for reuse. When necessary, final cleanup may be
accomplished by passing the process gas through iron oxide,
zinc oxide, or activated carbon to remove residual traces
of H2S or organic sulfide.
~7~66
Similarly, the H S and COS containing solvent may
be regenerated by flashing and stripping with nitroyen,
or alternatively by heating and refluxing at reduced
pressure without using an inert gas. The H2S and COS
are then converted into sulfur by a suitable process. For
example, the Claus process may be used for producing elemental
sulfur from H2S as described in Kirk-Othmer Encyclopedia of
Chemical Technology, Second Edition Volume 19, John
Wiley, 1969, Page 353. Excess SO2 may be removed and
discarded in chemical combination with limestone, or by
means of a suitable commercial extraction process.
A stream of dry, clean, and optionally purified
process gas leaves from the gas cleaning puri~ation
zone at a temperat~lre in the range of about 100 to
800F and at a pressure in the range of about 10 to 180 atm.
abs., such as 5 to 70 atm. abs. Advantageously, the
pressure of this gas stream may be substantially the
same as that in the gas generator less ordinary pressure
drop in the lines and equipment. Exp~nslve gas compressors
are thereby avoided. The composition of this gas stream,
which is also referred to herein as the H2+CO-containing
product gas may be as follows in mole % dry basis: H2 ~5
to 70, CO 20 to 75, CH4 0 to 30, N 0.0 to 70 and A 0.0 to
2Ø
At least a portion i.e. about 50 to 100 volume
percent (vol. %) such as about 70 to 80 vol. % of the
H2+CO containing product gas stream is used internally in
the process as fuel gas. Separate portions of this fuel
~1~7~6
gas are introduced into a pressurized heater and also
into the combustor o'- a gas turbine. The temperature
of the fuel gas may be increased by indirect heat exchange
with cleaned process gas. Any remaining H +CO-containing
product gas stream that is not used internally may be
exported for use as synthesis gas, reducing gas, or fuel
gas. The actual internal-external division of the H2+CO-
containing product gas stream will depend on the purpose
for which the system is designed. For example, if it
is desired to produce mainly power for export starting
with a dirty fuel and without contaminating the
environment, then the cooled and cleaned generator gases
are optionally cooled below the dew point to remove H20
and purified to remove acid gases i.e. CO , H2S, and COS.
All of the H2+CO-containing product gas produced is
- preferably then used internally in the process as fuel
gas. In such case, the clean dewatered and purified
fuel gas that is produced in the process may have a heat
of combustion in British Thermal Units per Standard Cubic
Foot (BTU/SCF) in the range of about 70 to 350, such as
75 to 150, say 90.
As previously mentioned, a portion of the
internally distributed H +CO-containing product gas stream
is introduced into a pressurized heater as the fuel gas.
The pressurized heater may be of any conventional type
comprising a closed combustion chamber, equipped with a
burner for introducing and mixing together compressed
37~6~
stream of fuel gas and air. An outlet is provided for
d~scharging the flue gas under pressure. A pipe coil
is disposed within the combustion chamber. A compressed
stream of free-oxygen gas is passed throu~h said pipe
coil and heated to the proper temperature for introduction
into the gas generator. Within the combustion chamber
of the pressurized heater, the fuel gas is combusted
or reacted with air which enters the heater at a
temperature in the range of about 200 to 700 F.
The pressure of the fuel gas and the air feed to the
pressurized heater are preferabl~ substantially the same as
the pressure in the gas generator less ordinary pressure
drop in the lines and equipment. Either complete com-
bustion or partial oxidation of the fuel gas may take
place in the pressurized heater depending on the atomic
O/C ratio present. The amount of internally distributed H2+CO
containing gas stream that is introduced into the pressur-
ized heater is only a small percentage of the total
amount of gas generated i.e. about 2 to-20 volume %.
However, this amount of fuel gas is sufficient to heat
all of the free-oxygen containing gas being introduced
into the gas generator to a temperature in the range of
about 400 to 1800~F, such as 900 to 17~F, say 800 to
1200F, When a portion of the free-oxyg~n containing gas
is reacted in the pressurized heater it is preferable to
take that portion from the main free-oxygen containing gas
stream before said main stream is passed into the heater.
-15-
~L~7~6~i
In this way, the size of the heater may be decreased. In
another embodiment, the entire main stream of free-oxygen
containing gas may be passed through the heater.
Then a portion of the heated free-oxygen containing gas
leaving the heater may be split off and burned with the
fuel gas in the heater.
At least a portion, and preferably all of the
flue gas leaving the pressurized heater at a temperature
in the range of about 1400 to 3000F such as 1500
to 1700F and a pressure in the range of about 5
to 70 atm. abs. such as about 10 to 20 atm. abs. is
introduced into a gas turbine. The gas turbine comprises
a combustor section, and a turbine section. The flue
gas from the pressurized heater may be introduced into
either section of the gas turbine. In the preferred embodi-
ment, a portion of the H2+CO-containing product gas is
introduced into the pressurized heater and the remainder
of the internally distributed portion is introduced into
the combustor of said gas turbine where it is combusted ~ ~ -
with air. The air enters the combustor at a temperature
in the range of about 200 to 700 F and at substantially
the same pressure as the H2+CO-containing gas feed to the
combustor. Exhaust gas leaves the combustion chamber
of the gas turbine at a temperature in the range of about
1400F to 3000F, such as 1500F to 1700F, and at a
pressure in the range of about 5 to 70 atm. abs.,say about
10 to 20 atm abs. The exhaust gas stream from the
combustion chamber of the gas turbine may be then mixed
-16-
,,
~i7~66
with at least a portion and preferably all of the
flue gas stream from the previously described pressurized
heater to produce a clean gas stream. When this gas
stream is passed through at least one power~developing
expansion turbine as the working fluid, more work may be
obtained. When complete combustion takes place in the
pressurized heater, the mixture of flue gas from the heater
and exhaust gas from the combustor may have the following
typical analysis in mole percent: CO2 4-20, H20 4-20,
N 75-80, and O20-15. Only very small concentrations
of oxides of nitrogen (NO ) may be found in the flue
gas. This is due to the comparatively low temperature
in the combustion chamber, which is primarily the result
of the comparatively low adiabatic flame temperature of the
improved fuel gas. Further, the SO2 content of the
gas stream is nil; and entrained particulates are
negligible.
Preferably, the flue gas stream from the
press~ed`heater is mixed with the exhaust gas from the
combustor of the gas turbine prior to the introduction
of the gas mixture to the turbine blades. Alternately,
the flue gas stream from the pressurized heater and the
exhaust gas stream from the combustor of the gas turbine
may be introduced into the turbine blades as separate
streams.
In another embodiment, at least a portion and
preferably all of the flue gas from the pressurized
heater along with air and that portion of the internally
distributed H2+CO-containing fuel gas stream which is not
~ ~79~6
burned in the pressurized heater are introduced into the
combustor of the gas turbine where combustion takes
place. In such instance it may be advantageous to
previously react the fuel gas in the combustion chamber
of the pressurized heater by partial oxidation so that the
flue gas may contain so~e H2 and CO. The flue gas from
the pressurized heater may enter the combustor preferably
in admixture with the fuel gas. However, alternatively the
flue gas may be introduced in admixture with the air.
Coupled through a variable speed drive to the axis of the
turbine and driven thereby may be at least one electric
generator and at least one -ompressor. Air, prior to
introduction into the gas turbine and into the pressurized
heater, may be compressed by means of one of said com-
pressors to the proper pressure e.g. over 10 to 180 atm.
abs. Optionally, a free-oxygen containing gas, i.e.
oxygen or oxygen-enriched air may be compressed by a
separate compressor powered by said gas turbine to a
pressure slightly above the pressure in the gas generator
and then passed through said pressurized heater. If the
free-oxygen containing gas which is fed to the gas
generator is air, then one of the gas turbine driven
compressors may be eliminated.
Recovery of the sensible heat in the clean
exhaust gas which leaves the expansion turbine at a
temperature in the range of about 800F to 1200F and a
pressure in the range of about 1.0 to 7.0 atmospheres
absolute may take place by heat exchange with saturated
steam what was produced in a waste heat boiler or in a
gas cooler located downstream from the gas generator. The
-18-
7~6 ~
clean exhaust gas may be then discharged into the atmos-
phere without causing pollution. Superheated steam
may be produced thereby having a temperature in the range
of about 750F to 1200F. The superheated steam may be
used as the working fluid in at least one expansion
turbine. The axial shaft of the steam turbine, for
example, may be coupled through a variable drive to the
shaft of a turbocompressor, to an electric generator, or to
both. In one embodiment, the free-02 containing gas is
partially compressed by the compressor powered by the gas
turbine, cooled, further compressed by a steam turbine
driven boost compressor, and then passed through the
pressurized heater where it is heated.
The following benefits have resulted from the
subject in~ention:
(1) A clean purified H2+CO-containing product gas may be
produced from low grade or undesirable fuels. (2) The
product gas has an improved heating value and may be burned
as fuel in a power producing gas turbine without polluting
the atmosphere. (3) Smaller process equipment may be used
throughout for the same residence time i.e. compressors,
gasifier, gas cooler~ assorted heat exchangers, and
purification system. (4) Less combustion problems occur
in the gas turbine combustor, primarily with combustor
cooling methods.
-19-
37~66
DESCRIPTION OF THE DRAWING
A more complete understanding of the invention
may be had by reference to the accompanying schematic
drawing which shows an embodiment of the previously
described process in detail. All of the lines and equipment
are preferably insulated to minimize heat loss.
Referring to the figure in the drawing, free-flow
partial oxidation gas generator 1 lined with refractory
2 as previously described has an upstream axially aligned
flanged inlet port 3, a downstream axially aligned flanged
outlet port 4, and an unpacked reaction zone 5. Annulus
type burner 6, as previously described, with centeripassage
7 in alignment with the axis of gas generator 1 is mounted
in inlet port 3. Center passage 7 has a flanged upstream
inlet 8 and a converging conical shaped downstream nozzle
9 at the tip of the burner. Burner 6 is also provided with
a concentric coaxial annular passage that has an upstream
flanged inlet 10 and a downstream conical shaped discharge
passage 11. Burners of other design may also be used.
A continuous strea~ of free-oxygen containing gas
is heated by being passed through coil 20 in gas-fired
~ pressurized heater 21, and is then passed through line 22 into
- flanged inlet 8 of burner 6. A hydrocarbonaceous fuel
optionally in admixture with a temperature moderator such ; ~
as H20, for example a slurry of coal and water, is introduced ~ -
into burner 6 by way of line 23 and inlet 10.
Spherically shaped, refractory lined or insulated
flanged "T" connector 30 is joined by inlet 31 to outlet
4 of gas generator 1. Axially-aligned outlet 32 is
, .
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7~3~j6
connected to inlet 33 of insulated slag pot 34. Flanged
axial outlet 35 is normally closed by line 39 and valve
40.
The effluent gas stream from gas generator 1
passes through outlet 4. It then enters connector 30
through inlet 31 and leaves through outlet 37 and insulated
line 38. Any particulate solids, such as slag, carbon,
metals, or refractory that separates from the effluent gas
stream in connector 30 accumulates in the bottom of slag
pot 34. The material in slag pot 34 is periodically
removed through line 39, valve 40, line 41 and through a
conventional lock-hopper system not shown.
The effluent stream of generator gas is cooled in
gas cooler 42 by indirect heat exchange with a coolant
such as boiler feed water (BFW) from line 43. The BFW
may be preheated elsewhere in the system. Steam is
produced in gas cooler 42 and may leave for example as
saturated steam through line 44, 45 and 46 for use
elsewhere in the system. Optionally, at least a portion
of the steam may be exported through line 47, valve 48,
and line 49.
The cooled process gas stream in line 55 containing
entrained particulate carbon and possibly other solids is
passed into gas cleaning zone 56 where it is scrubbed with
a scrubbing fluid such as water from line 57. Particulate
carbon and any other remaining solids is removed from the
gas stream and leaves as a carbon-water dispersion in line
58. The ~lean process gas stream in line 59 is dewatered
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~L~r~75~i6
by being cooled below its dew point. Thus, the clean
process gas stream is passed through heat exchanger 60,
line 61 cooler 62, and line 63. Ccnden.ed water is removed
in knock-out pot 64, and leaves through line 65. Optionally,
any acid-gas impurities present may be removed in a conven-
tional gas purification zone 70. In such case the cooled,
cleaned, and ~ewatered process gas stream is passed through
lines 71 and 72. Acid gases such as CO2, H2S, and COS may
be removed and leave by line 73. By-pass line 74, valve
75, and line 76 are provided in the event no purification
of the gas stream is necessary. The process gas stream
in line 76 or the purified gas stream in line 72 comprises
the H2+CO-containing product gas. At least a portion of the
H2+CO-containing product gas in line 78 is used downstream
in the process as fuel gas. The remainder of the product
gas may be exported by way of line 79, valve 80, and line 81.
The H2+CO-containing product gas in line 78 is
burned as a fuel gas in pressurized heater 21 and in a
gas turbine that comprises combustor 82 and expansion turbine
83. The stream of f!~el gas in line 78 is optionally heated
in heat-exchanger 60, passed through line 85, and is then
divided into two streams. One stream of fuel gas is
passed into line 86 which leads into inlet 87 of burner
88 in the combustion chamber 89 of pressurized heater 21.
; The other stream of fuel gas is passed through lines 90,
91 and into combustor 82 of said gas turbine.
.
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7~3t66
Air from line 95, is passed through inlet 96 of
burner 88 in pressurized heater 21. Combustion takes
place in heater 21, and the flue gas passes out through
line 97. In the preferred embodiment with valve 98 closed
and valve 99 open, the flue gas in line 92 is passed
through line 100 and is mixed in line 101 with the exhaust
gas leaving combustor 82 through line 102. The mixture
of gases is then introduced, by way of line 101, into
expansion turbine 83 as the working fluid. In another
embodiment, with valve 98 open and valve 99 closed, the
flue gas in line 97 is directed into combustor 82 of the
gas turbine by being passed through line 103, valve 98, line
104, and into line 91 where it is mixed with the fuel gas
from line 90. The mixture of gases is then introduced,
by way of line 128, into combustor 82. After combustion
the exhaust gas from combustor 82 is passed through lines
102 and 101 into expansion turbine 83 as the working fluid.
Optionally, expansion turbine 83 may be coupled
to electric generator 105 by way of shaft 106. Free-oxygen
containing gas compressor 108, and optionally air compressor
109 are driven by turbine 83, for example by shafts 110 and
111, When the free-oxygen containing gas is air, then
compressor 109 may not be required. When the free-oxygen
containing gas is substantially pure oxygen or oxygen
enriched air, then both compressors 108 and 109 are
included in the system.
~7966
For example, in the preferred embodiment, the
free-oxygen containing gas is air in line 112. Air
compressor 109 and boost compressor 140 may be cut out of
the system by closing valves 113 and 114 and opening valves
115, 116, and 117. All of the air for the system is then
compressed by compressor 108.
A first portion of compressed air is passed into the
gas generator by way of lines 120 to 124, pressurized heater
21, coil 20, line 22, and inlet 8 of burner 6. A second
portion of the air compressed in compressor 108 is passed
into combustor 82 of the gas turbine by way of lines
120, and 125 to 128. A third portion of the air
compressed in compressor 108 is passed into burner 88 in
pressurized heater 21 by way of lines 120, 125, 126, 127,
129, 95, and inlet 96.
In another embodiment, the free-oxygen containing
gas in line 112 is substantially pure oxygen which is
compressed in compressor 108, heated in pressurized heater ~;
21, and introduced into~burner 6 of gas generator 1. Addi- ~ ~
tional air compressor 109 is now included in the system. ~ .
In such case, valve 115 is closed and valve 113 is
opened. Air in line 135 is compressed in compressor 109
and a first-portion is passed through lines 136, 137, 127, and
128 into combustor 82. A second portion of air is directed
into burner 88 of pressurized heater 21 by way of linQs
136, 137, 127, 129, 95, and inlet 96.
In another embodiment, an air or free-oxygen
containing gas boost compressor 140 may be used to
increase the pressure of the compressed air or free-oxygen
containing gas that was originally compressed by compressor
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7~66
108. At least a portion of this compressed gas stream
is finally introduced into gas generator 1 after being
heated in pressurized heater 21~ In such case, with
valve 117 closed and valve 114 open, the free-oxygen
containing gas in line 121 is passed through lines 141,
142, heat exchanger 143, line 144, heat exchanger 145,
and line 146 into boost compressor 140. The compressed
stream of free-oxygen containing gas is then passed
through line 147, heat exchanger 143, lines 148 and 124,
coil 20 of pressurized heater 21, line 22, and inlet 8 of
burner 6. The free-oxygen containing gas passing through
heat exchanger 145 is cooled by indirect heat exchange
with water. For example, boiler feed water (BFW) in
line 149 may be preheated in heat exchanger 145 and leaveS
by line 150. The preheated BFW may be introduced into gas
cooler 42 by way of line 43 and converted into steam, in
the manner previously described.
Optionally, in one embodiment the thermal
efficiency of the process is increased by utilizing the
sensible heat in the exhaust gas from expansion turbine
83 to superheat saturated steam produced in the system.
The superheated steam is then used as the working fluid
- in at least one steam turbine for the production of
mechanical work, electrical power or both. For example,
the clean exhaust gas from turbine 83 is passed through
line 155, superheater 156, line 157, waste heat boiler
158, and line 159 to the stack. With valves 48 and 160
closed and valves 46, 161, and 162 open, saturated steam
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7~66
may be ~assed through lines 163, 164, superheater 156, and
lines 165 to 168 into steam turbine 169 as the working fluid.
Steam turbine 169 is coupled to boost compressor 140, for
example by way of shaft 170. Also superheated steam in line
166 may be optionally passed through lines 171 and 172 into
steam turbine 173 as the working fluid. Steam turbine 173
may be coupled to electric generator 174 by shaft 175. Exhaust
steam from steam turbine 173 is passed through line 177 into
steam condensor 178. Similarly, exhaust steam from steam tur-
bine 169 is passed through line 179 into steam condensor 178.
Condensed water i.e. BFW may be pumped by pump 180 through
lines 185 to 188, cooler 62, and line 189 into waste heat
boiler 158. Saturated steam in line 190 may be passed through
line 164 into superheater 156. Optionally, a portion of the
BFW in line 187 may be passed through line 191, valve 192,
and line 193 into line 149 where it is preheated in heat
exchanger 145, in the manner previously described. Make-up
water may be introduced into the system through line 194,
valve 195, and l-ne 196.
In the event that steam turbines 169, 173, or both
are not in the system, then valves 161, 162, or both may be
closed. Valve 160 may be then opened and superheated steam
may be exported through lines 197 and 198.
In another embodiment, free~oxygen containing gas in
line 124 may be preheated to a temperature in the range of
about 800-1100F by indirect heat exchange with a portion of
the exhaust gas from turbine 83 prior to being passed through
pressurized heater 21.
The process of the invention has been described gene-
rally with reference to materials of particular compositions
for purposes of clarity and illustration only. It will be appar~
ent to those skilled in the art from the foregoing that various
modifications of the process and materials disclosed herein can
be made without departure from the spirit of the invention.
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