U.S. patent application number 13/056138 was filed with the patent office on 2011-05-26 for minimal sour gas emission for an integrated gasification combined cycle complex.
This patent application is currently assigned to Hydrogen Energy International Limited. Invention is credited to Maria Balmas, Henry C. Chan, Craig Skinner.
Application Number | 20110120012 13/056138 |
Document ID | / |
Family ID | 41610915 |
Filed Date | 2011-05-26 |
United States Patent
Application |
20110120012 |
Kind Code |
A1 |
Balmas; Maria ; et
al. |
May 26, 2011 |
MINIMAL SOUR GAS EMISSION FOR AN INTEGRATED GASIFICATION COMBINED
CYCLE COMPLEX
Abstract
Disclosed is a process to start-up, operate, and shut down a
gasifier and an integrated gasification combined cycle complex with
minimal sour gas emissions while additionally reducing the release
of contaminants such as carbon monoxide, hydrogen sulfide, and
nitrogen oxides. The process is accomplished by starting up with a
sulfur free feedstock and by scrubbing any ventable sour gases free
of sulfur contaminants prior to release of any such gases to the
atmosphere.
Inventors: |
Balmas; Maria; (Hacienda
Heights, CA) ; Chan; Henry C.; (Fountain Valley,
CA) ; Skinner; Craig; (Newport Beach, CA) |
Assignee: |
Hydrogen Energy International
Limited
Weybridge, Surrey
GB
|
Family ID: |
41610915 |
Appl. No.: |
13/056138 |
Filed: |
July 21, 2009 |
PCT Filed: |
July 21, 2009 |
PCT NO: |
PCT/US09/51206 |
371 Date: |
January 27, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61084774 |
Jul 30, 2008 |
|
|
|
Current U.S.
Class: |
48/197R |
Current CPC
Class: |
F05D 2220/722 20130101;
C10K 1/004 20130101; C10J 3/00 20130101; Y02E 20/18 20130101; C10K
1/101 20130101; C10K 1/143 20130101; C10J 3/726 20130101; C10J
3/728 20130101; C10J 2300/1653 20130101; C10K 1/003 20130101; Y02E
20/16 20130101; C10J 2300/0989 20130101 |
Class at
Publication: |
48/197.R |
International
Class: |
C10J 3/46 20060101
C10J003/46 |
Claims
1. A process for starting up and shutting down an integrated
gasification combined cycle complex wherein the integrated
gasification combined cycle complex comprises a syngas production
zone, shift conversion/low temperature gas cooling zone, acid gas
removal zone, sulfur recovery zone and a combined cycle power block
zone, wherein each zone has at least one blow down conduit
associated with it, wherein the integrated gasification combined
cycle complex is started up with a hydrocarbon-containing feedstock
not containing contaminants such as sulfur-containing compounds and
wherein said startup or shut-down is carried out with sulfur-free
or reduced sulfur flaring which process comprises the steps of: (a)
recovering any sour effluent stream from an applicable zone being
started up or shutdown and; (b) scrubbing such sour gas to reduce
the content of sulfur-containing contaminants during the startup or
shutdown prior to venting or flaring such gases; (c) recovering a
sweet reducing effluent stream from an applicable zone being
started up in the integrated gasification combined cycle complex;
(d) passing the sweet reducing effluent stream from the applicable
zone that is being started up through at least one blow down
conduit downstream of the applicable zone; (e) passing the sweet
reducing stream recovered from the blow down conduit in step (c) to
a flare or vent;
2. The process of claim 1 wherein oxidizing streams are collected
from the group consisting of sumps, tanks, instrument vents,
bridals, and pressure safety valves associated with the various
zones in the integrated gasification combined cycle complex and
such oxidizing streams are passed to the sulfur recovery zone.
3. The process of claim 1 which process further comprises the steps
of: (a) passing a sulfur-free hydrocarbon feedstock to the syngas
production zone to produce a sweet reducing syngas effluent stream;
(b) passing the sweet reducing syngas effluent stream to a blow
down conduit; (c) passing the sweet reducing stream from the blow
down conduit in step (b) to a flare (e) when the feed rate to the
syngas production zone reaches a predetermined rate at
predetermined conditions including a predetermined pressure and
temperature, the syngas zone sweet reducing effluent stream is
diverted from the blow down conduit in step (b) to the shift
conversion zone having a low temperature gas cooling zone
downstream thereof to produce a sweet reducing stream effluent from
the low temperature gas cooling zone; (f) passing the sweet
reducing stream effluent from the low temperature gas cooling zone
to a blow down conduit downstream of the low temperature gas
cooling zone; (g) passing the sweet reducing stream from the blow
down conduit in step (f) to a flare; (h) starting up the acid gas
removal zone with nitrogen or any other inert gas such that when
the acid gas removal zone has reached predetermined operating
conditions including temperature and pressure the sweet reducing
stream effluent from the blow down conduit associated with the low
temperature gas cooling zone in step (f) is diverted to the acid
gas removal zone to produce a sweet reducing effluent stream; (i)
passing the sweet reducing effluent stream from the acid gas
removal zone in step (h) to a blow down conduit down stream of the
acid gas removal zone; (j) passing the sweet reducing stream from
the blow down conduit in step (i) to a flare; (k) starting up the
sulfur recovery zone with a start-up gas such as natural gas such
that when the sulfur recovery zone has reached operating conditions
the sweet reducing effluent stream from the acid gas removal zone
is diverted from the blow down conduit in step (j) to the sulfur
recovery zone to produce a sweet reducing effluent stream; (l)
passing the sulfur recovery zone sweet reducing effluent to a tail
gas treatment unit to produce a tail gas treatment unit sweet
reducing effluent; (m) passing the tail gas treatment unit sweet
reducing effluent to a thermal oxidizer or flare; (n) reducing the
amount of sulfur-free containing feedstock to the syngas production
zone and passing a sulfur-containing hydrocarbon feed stock to the
syngas production zone; (o) diverting the acid gas removal zone
sweet reducing effluent stream from the sulfur recovery zone to a
sour gas scrubber; (p) passing the effluent from the sour gas
scrubber to a flare; (q) when the sulfur concentration of the acid
gas removal effluent stream passing to the sour gas scrubber
reaches a predetermined value, the stream is diverted back to the
sulfur recovery zone while simultaneously reducing start up gas to
the sulfur recovery zone; (r) diverting the tail gas treatment unit
effluent presently flowing to the thermal oxidizer or flare in step
(m) to a point either upstream or down stream of the acid gas
removal zone.
4. The process of claim 1 which process further comprises the steps
of: (a) passing a sulfur-free hydrocarbon feedstock to the syngas
production zone to produce a sweet reducing syngas effluent stream;
(b) passing the sweet reducing syngas effluent stream to the shift
conversion zone having a low temperature gas cooling zone
downstream thereof to produce a sweet reducing stream effluent from
the low temperature gas cooling zone; (c) passing the shift
conversion zone effluent sweet reducing stream from the low
temperature gas cooling zone to a blow down conduit downstream of
the low temperature gas cooling zone; (d) passing the sweet
reducing stream from the blow down conduit in step (c) to a flare;
(e) starting up the acid gas removal zone with nitrogen or any
other inert gas such that when the acid gas removal zone has
reached predetermined operating conditions including appropriate
temperature and pressure, the sweet reducing stream effluent from
the blow down conduit associated with the low temperature gas
cooling zone is diverted to the acid gas removal zone to produce a
sweet reducing effluent stream; (f) passing the sweet reducing
effluent stream from the acid gas removal zone to a blow down
conduit down stream of the acid gas removal zone; (g) passing the
sweet reducing stream from the blow down conduit in step (f) to a
flare; (h) starting up the sulfur recovery zone with a start-up gas
such as natural gas such that when the sulfur recovery zone has
reached operating conditions, the sweet reducing effluent stream
from the acid gas removal zone is diverted from the blowdown
conduit in step (f) to the sulfur recovery zone to produce a sweet
reducing effluent stream; (i) passing the sulfur recovery zone
sweet reducing effluent to a tail gas treatment unit to produce a
tail gas treatment unit sweet reducing effluent; (j) passing the
tail gas treatment unit reducing gas effluent to a thermal oxidizer
or flare; (k) reducing the amount of sulfur-free containing
feedstock to the syngas production zone and passing a
sulfur-containing hydrocarbon feed stock to the syngas production
zone; (l) diverting the acid gas removal zone reducing effluent
stream from the sulfur recovery zone to a sour gas scrubber; (m)
passing the effluent from the sour gas scrubber to a flare (n) when
the sulfur concentration of the acid gas removal effluent stream
passing to the sour gas scrubber reaches a predetermined value, the
stream is diverted back to the sulfur recovery zone while
simultaneously reducing start up gas to the sulfur recovery zone;
and (o) diverting the tail gas from the tail gas treatment unit
effluent presently flowing to the thermal oxidizer or flare in step
(j) to a point either upstream or down stream of the acid gas
recovery zone.
5. The process of claim 1 which process further comprises the steps
of: (a) passing a sulfur-free hydrocarbon feedstock to the syngas
production zone to produce a sweet reducing syngas effluent stream;
(b) passing the sweet reducing syngas effluent stream to a shift
conversion zone having a low temperature gas cooling zone
downstream thereof to produce a sweet reducing effluent stream; (c)
passing the sweet reducing stream effluent from the low temperature
gas cooling zone to the acid gas zone to produce a sweet reducing
gas effluent stream; (d) passing the sweet reducing gas effluent
from the acid gas removal zone to a blow down conduit down stream
of the acid gas removal zone; (e) passing the sweet reducing stream
from the blow down conduit to a flare; (f) starting up the sulfur
recovery zone with a start-up gas such as natural gas such that
when the sulfur recovery zone has reached operating conditions, the
sweet reducing effluent stream from acid gas removal zone is
diverted from the blown down conduit in step (d) to the sulfur
recovery zone to produce a sweet reducing effluent stream; (g)
passing the sulfur recovery zone sweet reducing effluent stream to
a tail gas treatment unit to produce a tailgas treatment unit sweet
reducing effluent; (h) passing the tail gas treatment unit reducing
gas effluent to a flare or thermal oxidizer; (i) reducing the
amount of sulfur-free containing feedstock to the syngas production
zone and passing a sulfur-containing hydrocarbon feed stock to the
syngas production zone; (j) diverting the acid gas removal
regenerator sweet reducing effluent stream from the sulfur recovery
zone to a sour gas scrubber; (k) passing the effluent from the sour
gas scrubber to a flare; (l) when the sulfur concentration of the
acid gas removal effluent stream passing to the sour gas scrubber
reaches a predetermined value, the stream is diverted back to the
sulfur recovery zone while simultaneously reducing start-up gas to
the sulfur recovery zone; and (m) diverting the tail gas from the
tail gas treatment unit effluent presently flowing to the flare or
thermal oxidizer in step (h) to a point either upstream or down
stream of the acid gas removal zone.
6. A process for shutting down the syngas production zone of an
integrated gasification combined cycle complex wherein the
integrated gasification combined cycle complex comprises a syngas
production zone, shift conversion reaction/low temperature gas
cooling zone, acid gas removal zone, sulfur recovery zone and a
combined cycle power block zone, wherein each zone has at least one
blow down conduit associated with it wherein the complex is being
fed a hydrocarbon-containing feedstock which feedstock contains
contaminants such as sulfur, wherein the process comprises the
steps of: (a) switching the feedstock to the syngas production zone
to a sulfur-free hydrocarbon containing feedstock such that a sweet
reducing stream effluent is created once the syngas from the
sulfur-free feedstock displaces the sulfur-containing feedstock;
and (b) diverting and depressurizing the sweet reducing stream
effluent from the syngas production zone to a blow down conduit
associated with the syngas production zone.
7. The process of claim 6 which involves shutting down additional
zones and comprises the steps of (a) diverting and depressurizing a
sweet reducing stream effluent from the low temperature gas cooling
zone to the blow down conduit associated with this zone once the
sulfur-free syngas from the sulfur-free feedstock displaces the
syngas from the sulfur-containing feedstock in syngas production
zone; (b) passing the effluent from the low temperature gas cooling
zone in step (a) to a flare; (c) diverting and depressurizing the
effluent from the acid gas removal zone as follows: (i) passing a
hydrogen rich syngas to a flare; (ii) passing the acid gas to the
sulfur recovery zone; (d) depressurizing the sulfur recovery zone
to a tail gas treating unit ("TGTU") absorber; (e) passing the
effluent from the low pressure tail gas treatment unit absorber to
a thermal oxidizer or flare; (f) switching the fuel to turbines
associated with the power block zone from hydrogen to natural
gas.
8. The process of claim 7 which process further comprises the steps
of: (a) diverting and depressurizing the sweet reducing stream
effluent from the acid gas removal zone as follows: i) passing a
hydrogen rich syngas to a flare; ii) passing the acid gas to the
sulfur recovery zone; (b) depressurizing the sulfur recovery zone
to a tail gas treating unit absorber; (c) passing the effluent from
the low pressure tail gas treatment unit absorber to a thermal
oxidizer or flare; (d) switching the fuel to turbines associated
with the power block zone from hydrogen to natural gas.
9. A process for shutting down the syngas production zone of an
integrated gasification combined cycle complex wherein the
integrated gasification combined cycle complex comprises a syngas
production zone, shift conversion reaction/low temperature gas
cooling zone, acid gas removal zone, sulfur recovery zone and a
combined cycle power block zone, wherein each zone has at least one
blow down conduit associated with it wherein the complex is being
fed a hydrocarbon-containing feedstock which feedstock contains
contaminants such as sulfur, wherein the process comprises the
steps of: (a) diverting and depressurizing a sour reducing stream
effluent from the syngas production zone to a blow down conduit
associated with the syngas production zone; (b) passing the
effluent from the syngas production zone in step (a) to a low
pressure scrubber such as amine or caustic scrubber to remove the
H.sub.2S gas; (c) passing the effluent of the low pressure scrubber
to a flare or thermal oxidizer;
10. The process of claim 9 of shutting down the entire processing
units of the IGCC which process further comprises the steps of: (a)
diverting and depressurizing a sour reducing stream effluent from
the temperature gas cooling zone to the blow down conduit
associated with this zone; (b) passing the effluent from the low
temperature gas cooling zone to a low pressure scrubber such as
amine or caustic scrubber for H.sub.2S removal; (c) passing the
effluent from the low pressure scrubber in step (b) to flare (d)
diverting and depressurizing the effluent from the acid gas removal
zone as follows: (i) passing a hydrogen rich syngas to a flare;
(ii) passing the acid gas to the sulfur recovery zone; (e)
depressurizing the sulfur recovery zone to a tail gas treating unit
absorber; passing the effluent from the low pressure tail gas
treating unit absorber to a thermal oxidizer or flare; (g)
switching the fuel to turbines associated with the power block zone
from hydrogen to natural gas.
11. The process of claim 10 which process further comprises the
steps of: (a) diverting and depressurizing the sour reducing stream
effluent from the acid gas removal zone as follows; (i) passing a
hydrogen rich syngas to the flare; (ii) passing the acid gas to the
sulfur recovery zone; (b) depressurizing the sulfur recovery zone
to a tail gas treating unit absorber; (c) passing the effluent from
the low pressure tail gas treating unit absorber to a thermal
oxidizer or flare; and (d) switching the fuel to the turbines
associated with the power block zone from hydrogen to natural
gas.
12. The process of claims 9, 10 and 11 are also used for unplanned
emergency shutdown.
Description
[0001] This application claims benefit of provisional application
Ser. No. 61/084,774 filed Jul. 30, 2008, which is incorporated
herein by reference in its entirety.
BACKGROUND OF THE INVENTION
[0002] The present invention relates to systems and methods of
starting up, operating and shutting down a gasification reactor and
an integrated gasification combined cycle ("IGCC") complex.
[0003] Gasification was first used to produce "town gas" for light
and heat. Additionally, coal and other hydrocarbons have been
gasified in the past to produce various chemicals and synthetic
fuels. More recently gasification technology has been employed to
generate electricity in an IGCC complex wherein coal or another
hydrocarbon is gasified by partial oxidation using oxygen or air to
syngas. Typically, this syngas is then cleaned of particulates,
sulfur compounds and nitrogen compounds such as NO.sub.x compounds
and then subsequently passed to gas turbine where it is fired.
Additionally the hot exhaust gas from the gas turbine is usually
passed to a heat recovery steam generator where steam is produced
to drive a steam turbine. Electrical power is then produced from
the gas turbine and the steam turbine. These IGCC complexes can
also be designed to produce hydrogen and capture CO.sub.2 thereby
reducing greenhouse gas emissions. Because the emission-forming
components are removed from the syngas prior to combustion an IGCC
complex produces very low levels of air contaminants, such as
NO.sub.x, SO.sub.2, particulate matter and volatile mercury.
[0004] As mentioned above any hydrocarbon can be gasified, i.e.
partially combusted, in contradistinction to combustion, by using
less than the stoichiometric amount of oxygen required to combust
the solid. Generally the oxygen supply is limited to about 20 to 70
percent of the oxygen required for complete combustion. The
reaction of the hydrocarbon-containing feedstock with limited
amounts of oxygen results in the formation of hydrogen, carbon
monoxide and some water and carbon dioxide. Solids such as coal,
biomass, oil refinery bottoms, digester sludge and other
carbon-containing materials can be used as feedstocks to gasifiers.
Recently petroleum coke has been used as the solid hydrocarbon feed
stock for IGCC.
[0005] A typical gasifier operates at very high temperatures such
as temperatures ranging from about 1000.degree. C. to about
1400.degree. C. and in excess of 1,600.degree. C. At such high
temperatures any inert material in the feedstock is melted and
flows to the bottom of the gasification vessel where it forms an
inert slag. There are three basic types of gasifiers that are
either air or oxygen fed gasifiers. Specifically, gasifiers can be
characterized as a moving bed, an entrained flow, or a fluidized
bed. Moving bed gasifiers generally contact the fuel in
countercurrent fashion. Briefly, the carbon-containing fuel is fed
into the top of a reactor where it contacts oxygen, steam and/or
air in counter-current fashion until it has reacted to form syngas.
In the entrained flow gasifier the fuel or hydrocarbon-containing
feedstock contacts the oxidizing gas in co-current fashion until
syngas is produced which exists the top of the reactor while slag
flows to the bottom of the reactor. Finally, in the fluidized-bed
gasifier the hydrocarbon-containing fuel or feedstock is passed
upwards with a steam/oxygen gas where it is suspended until the
gasification reaction takes place.
[0006] The gasifier in an IGCC complex is integrated with an air
separation unit ("ASU"), a gas purification or clean up system such
as an acid gas removal ("AGR") process, and a combined cycle power
plant or "power block" which is the gas turbine unit. The ASU is
used to separate air such that a pure oxygen stream can be sent to
the gasifier.
[0007] In order to convert syngas produced by the gasifier to
hydrogen fuel for both power generation and/or hydrogen sales, the
syngas from the gasification block or gasifier must be shifted to
convert the CO and water in the syngas to CO.sub.2 and hydrogen.
The water gas shift reaction is:
CO+H.sub.2O.fwdarw.CO.sub.2+H.sub.2
CO shift technology is commonly used in conventional hydrogen and
ammonia plants. Where the syngas is derived from gasification, the
CO shift unit is typically located upstream of a sulfur removal
unit and therefore uses "sour" shift catalysts. Shift catalysts can
be cobalt-molybdenum-based catalysts which are readily commercially
available from a number of suppliers. The catalyst life is
typically three years. For a high degree of CO.sub.2 capture
additional stages of shift may be required. The heat from the
highly exothermic shift reaction can be effectively utilized by
generating steam for internal plant consumption.
[0008] As set out above this "shift reaction" is practiced widely
in the refining and petrochemical industries. Examples of
gasification plants utilizing sour shift technology include the
Convent Hydrogen Plant in Louisiana, the Dakota Gasification Plant
in North Dakota, and the petcoke gasification plant in Coffeyville,
Kans. The Coffeyville plant uses gasification technology for
ammonia and CO.sub.2 production.
[0009] Where an IGCC complex is used to capture CO.sub.2, the
CO.sub.2 captured must meet purity standards for compression and
injection if the CO.sub.2 is to be injected into oil fields for
enhanced oil recovery. An extremely high degree of carbon capture
can be achieved by shifting almost all the CO in the raw sour
synthesis gas to carbon dioxide and hydrogen, and then recovering
nearly all of the CO.sub.2 in the resultant syngas within a
downstream AGR unit.
[0010] In an IGCC complex as contemplated herein, shifted syngas
effluent from the shift reactor is passed to an acid gas removal
unit. A suitable acid gas removal unit could be the Rectisol
process licensed by Lurgi AG or Linde AG. The Rectisol Process uses
a physical solvent, unlike amine based acid removal solvents that
rely on a chemical reaction with the acid gases. While any acid gas
removal process can be utilized the Rectisol Process is preferably
utilized due to (1) the high syngas pressure and (2) the proven
ability of the process to (i) achieve very low (<2 ppmv) sulfur
levels in treated fuel gas effluents, (ii) simultaneously produce
an acid gas that is suitable for a Claus sulfur recovery unit
("SRU") and (iii) a CO.sub.2 stream that is suitable for enhanced
oil recovery ("EOR") applications. Ultra-low sulfur content in gas
turbine ("GT") fuel is necessary to allow use of catalysts for CO
and NO.sub.x reduction in the GT exhaust because sulfur compounds
react with ammonia used in the selective catalytic reduction (SCR)
process to form sticky particulates that adhere to catalyst and
heat recovery steam generator ("HRSG") tube surfaces. Rectisol can
also remove nearly all COS from the syngas, thus eliminating the
need for an upstream hydrolysis reactor that would otherwise be
needed to convert COS in the syngas to H.sub.2S. The deep sulfur
removal achieved by the Rectisol unit for H.sub.2-rich syngas
coupled with the use of CO oxidation catalysts and SCR allow the
power block to achieve NO.sub.x, CO and SO.sub.2 emission levels
that are comparable to those for a natural gas-fired combined cycle
power plants, but with much lower CO.sub.2 emissions.
[0011] As mentioned above the Rectisol is a purely physical
absorption process, which is carried out at low temperatures and
benefits from high operating pressure. The absorption medium is
methanol. Mass transfer from the gas into the methanol solvent is
driven by the concentration gradient of the respective component
between the gas and the surface of the solvent, the latter being
dictated by the absorption equilibrium of the solvent with regard
to this component. The compounds absorbed are removed from the
solvent by flashing (desorption) and additional thermal
regeneration, so that the solvent is ready for new absorption. The
relative ease of removing CO.sub.2 from high pressure synthesis gas
as compared to removing it from atmospheric pressure,
nitrogen-diluted flue gas is widely recognized as one of the
principal benefits of gasification when compared to combustion
technologies.
[0012] CO.sub.2 produced by such an IGCC complex, depending on the
process unit integration, is between 97 to 99%+pure with only small
traces of other compounds present. This level of purity is required
for several reasons. First, it is essential for the product to be
very low in water content to minimize or alleviate the formation of
carbonic acid (water+CO.sub.2=carbonic acid) which is very
corrosive to the steel used in the compression equipment, pipeline,
injection/re-injection equipment and the actual wells themselves.
Second, the total sulfur content is limited to 30 ppmv or less to
further minimize corrosion issues and to mitigate any health
concerns to workers or the public in the event of a mechanical
failure or release, Third, nitrogen in the product is limited to
less than about 2 vol % since excessive amounts of nitrogen may
significantly inhibit EOR and permanent sequestration of
CO.sub.2.
[0013] The Rectisol unit can be used to produce high purity
CO.sub.2 at two pressure levels, atmospheric pressure and about
three atmospheres. EOR operations require a CO.sub.2 pressure of
2,000 psig (13.79 MPa), so CO.sub.2 compression above this level is
required. CO.sub.2 enters a dense, supercritical phase at about
1,100 psig (7.58 MPa), therefore it remains in a single phase
throughout a CO.sub.2 pipeline. The Rectisol acid gas removal unit
also produces an acid gas stream containing H.sub.2S.
[0014] The sulfur recovery unit ("SRU") used in the IGCC complex
contemplated herein can be a conventional oxygen-blown Claus
technology to convert the H.sub.2S to liquid elemental sulfur. The
tail gas from the Claus unit can be recycled to the AGR unit to
avoid any venting of sulfurous compounds to the atmosphere or
routed to a conventional Tail Gas Treating Unit (TGTU).
[0015] While the hydrogen produced in the present IGCC complex is
generally used for power production, during off peak demand a
portion of such hydrogen can be directed to petroleum refineries
after suitable purification using, for instance, conventionally
available pressure swing adsorption technology.
[0016] The combustion of the hydrogen fuel to produce power can be
carried out by any conventional gas turbines. These turbines can
each exhaust into a heat recovery and steam generator ("HRSG").
Steam can be generated at three pressure levels and is used to
generate additional electrical energy in a steam turbine.
[0017] A conventional selective catalytic reduction process ("SCR")
can be used for post-combustion treatment of effluent gases to
reduce NO.sub.x content down to acceptable levels.
[0018] In a conventional start-up of a partial oxidation gas
generating process the gas generator is started at atmospheric
pressure after preheating to at least 950.degree. C. Until the
gasifier is pressurized and downstream processes are brought
on-stream the resulting effluent, comprising syngas, is typically
burned in a flare. As is well known to those skilled in the art,
this results in higher than normal emissions of contaminants such
as sulfur. See, for example, U.S. Pat. No. 4,385,906 (Estabrook)
and U.S. Pat. No. 3,816,332 (Marion).
[0019] Accordingly, the start-up of a partial oxidation gas
generator presents special challenges, including dealing with the
contaminant emissions. For example, U.S. Pat. No. 4,378,974 (Petit
et al.) discloses a start-up method for a coal gasification plant,
in particular a refractory lined rotary kiln. The method of Petit
et al. focuses on the problems that arise from coal having a high
chlorine content. Petit et al. discloses a reactor where the lining
is made of materials susceptible to chlorine-induced cracking in
the presence of oxygen. Petit et al. teaches starting the reactor
up in stages while maintaining an oxygen content in the reactor at
a sufficiently low level to prevent chlorine-induced cracking of
the refractory lining.
[0020] Additionally, U.S. Pat. No. 4,385,906 (Estabrook) discloses
a start-up method for a gasification system comprising a gas
generator and a gas purification train. In the method disclosed by
Estabrook the gas purification train is isolated and prepressurized
to 50% of its normal operating pressure. The gas generator is then
started, and its pressure increased before establishing
communication between the generator and the purifier. Purified
gases from the purifier may then be burned in a flare until all
parts of the process reach appropriate temperature and
pressure.
[0021] U.S. Pat. No. 6,033,447 (Moock et al.) discloses a start-up
method for a gasification system with a sulfur-free organic liquid,
such as propanol. The reference claims that air contaminants, such
as sulfur, which are characteristic of start-up, may be eliminated
by starting the gasifier with a sulfur-free, liquid organic fuel.
Once the gasifier is started up using a sulfur-free liquid organic
fuel and reaches the appropriate temperature and pressure
conditions the burner is transitioned to a carbonaceous fossil fuel
slurry. Only sulfur-free gas is flared.
[0022] The present invention deals with the start-up of a gasifier
or an IGCC complex with no sour gas flaring. Flaring is an
uncontrolled combustion of flammable gas at the flare tip. Flare
flames are visible from substantial distances. The combustion is
carried outside the flare tip at the adiabatic flame temperature of
the flammable gas, typically as high as 3,000.degree. F.
(1649.degree. C.).
BRIEF SUMMARY OF THE INVENTION
[0023] The present invention involves a process of collecting all
the potential contaminants or pollutants in blow down conduits
associated with the process units that comprise an IGCC complex,
during start-up, shutdown and normal operation and treating streams
containing these contaminants or pollutants such that the IGCC
complex does not flare any streams containing such contaminants or
otherwise emit the contaminants into the atmosphere. These
potential contaminant or pollutant streams are first treated for
sulfur removal, if necessary. The sulfur-free potentially
contaminant or contaminant-containing streams are then segregated
into either an oxidizing stream or a reducing stream in a flare
header system. These streams are then passed to a flare having
several burner stages such that oxidizing and reducing streams are
not co-mingled. The flare header system can also be equipped with a
Vapor Recovery Unit (VRU) where any usable gas products such as
H.sub.2, CO.sub.2, sulfur compounds can be recovered. A simplified
process block diagram of an IGCC plant with the no sour gas flaring
scheme in accordance with the present invention is given in FIG.
6.
[0024] The sour reducing streams generated during gasifier startups
which contain sulfur are first passed through a low pressure
scrubber containing a solvent that absorbs H.sub.2S such as either
amine based or caustic-based solvent before such streams are
flared. During normal operations, gas products from the sour
reducing streams can be recovered in a tail gas treatment unit
and/or an acid gas removal unit via a vapor recovery unit.
[0025] The sour oxidizing stream typically contains only a trace
amount of flammable gas, and can contain an oxygen content of
greater than about 1.0 vol %. This sour oxidizing stream is passed
to a point downstream of the main reactor furnace burner in the
Sulfur Recovery Unit Tail Gas Treating Unit.
[0026] The sweet reducing stream typically contains flammable gas
with high heating value which can be greater than about 50 BTU/SCF
(1869 kilojoules/scm) and oxygen content of less than about 1.0 vol
%, is then passed to a vapor recovery unit where the stream is
subsequently routed to the feedstream to the Acid Gas Recovery
Unit.
[0027] The sweet oxidizing gas typically contains only a trace
amount of flammable gas, and can contain an oxygen content of
greater than about 1.0 vol %. This sweet oxidizing stream is passed
to a point downstream of the flare burner tip
[0028] The rich acid gas or high H.sub.2S acid gas containing
stream typically contains greater than about 10% H.sub.2S. This
stream, is passed from the AGR to the SRU during startup. In the
case of an unplanned SRU shutdown this stream can be routed to an
emergency caustic scrubber to remove the H.sub.2S prior to
flaring.
[0029] Further objects, features, and advantages of the present
invention will become apparent from consideration of the following
description and the appended claims when taken in connection with
the accompanying drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[0030] FIG. 1 is a schematic diagram of an IGCC complex flow
diagram in accordance with one embodiment of the present invention,
where at least one blowdown conduit is present for the syngas
production zone, the shift conversion and low temperature gas
cooling zones, the acid gas removal zone, and clean hydrogen
expander/heating zone.
[0031] FIG. 2 is another schematic diagram of a blowdown system in
accordance with one embodiment of the present invention. FIG. 2
shows the blowdown gases from the gasification zone, shift zone and
low temperature gas cooling zone, acid gas recovery zone, gas
turbine blow down system and blow down systems for other fugitive
emission sources such as the solid handling system. FIG. 2 shows
the routing of these gases depending on either the H.sub.2S or
oxygen contents.
[0032] FIG. 3 is a schematic diagram of flare system suitable for
use in accordance with the present invention. FIG. 3 also shows the
flare vapor recovery unit integrated within the various streams in
the flare header system.
[0033] FIG. 4 is a schematic diagram of an IGCC complex flow
diagram in accordance with one embodiment of the present invention,
in which at least one blowdown conduit is present for the shift
conversion and low temperature gas cooling zones and the acid gas
removal zone, and in which there is no blowdown conduit for the
syngas production zone.
[0034] FIG. 5 is a schematic diagram of an IGCC complex flow
diagram in accordance with one embodiment of the present invention,
in which at least one blowdown conduit is present for the acid gas
removal zone, and in which there are no blow down conduits for the
syngas production zone and for the shift conversion and low
temperature gas cooling zones.
[0035] FIG. 6 is a schematic diagram of an IGCC complex flow
diagram in accordance with the embodiment of the present invention,
where an LP (low pressure) amine scrubber is used for gasification
startup (sour reducing gas) gases and a LLP (low low pressure)
caustic scrubber is used for SRU (sulfur recovery unit) startup and
for emergency acid gas release.
DETAILED DESCRIPTION OF THE INVENTION
[0036] Broadly, in accordance with the present invention the syngas
production zone or gasifier in an IGCC complex is started up with a
clean, sulfur-free, containing less than about 10 ppmv sulfur
hydrocarbon-containing feedstock such as natural gas or a light
hydrocarbon liquid such as methanol. The sulfur-free syngas
produced in the gasifier, a sweet reducing gas, is then sent to a
flare. When the downstream acid gas removal unit and the sulfur
recovery unit and the tail gas treatment unit are commissioned, the
clean fuel is switched to a high sulfur solid fuel. After the AGR
is fully commissioned, the acid gas (H.sub.2S and other
contaminants) are concentrated and sent to a sulfur recovery unit
e.g. Claus unit to make elemental sulfur. If the acid gas
concentration is less than 25% vol H.sub.2S in the acid gas during
the start-up, such acid gas is routed to a sour gas scrubber such
as an emergency caustic scrubber. Once the SRU is operational, the
small amount of unconverted H.sub.2S in the effluent stream of the
SRU is sent to the Tail Gas Treating Unit ("TGTU"), where the small
amount of sulfur is removed, and the clean tail gas is recycled
back to the AGR or to a CO.sub.2 product stream recovered from the
AGR unit for export.
[0037] The sulfur-free syngas is combusted in the flare
[0038] When the gasifier is shutdown, sour (sulfur-containing gas)
gas is trapped inside the gasifier. This sour gas can be
depressured in a controlled manner though a low low pressure (LLP)
scrubber to remove the sulfur contaminants. The substantially
sulfur-free depressuring gas is then sent to the flare.
[0039] Generally, all emissions containing contaminants during
start-up and shut down and if desired, during operation of the IGCC
complex are collected in four different headers by an eductor or
compressor type collection system also known as the Vapor Recovery
Unit (VRU). The gas is either scrubbed free of sulfur and then sent
to the flare, or can be recycled back to an upstream unit such as
the AGR or SRU for further product (H.sub.2, CO.sub.2, and 8)
recovery
[0040] In one embodiment of the present invention where petroleum
coke is used as the hydrocarbon containing feedstock, the IGCC
complex, nominally designed to procure 500 Mega Watts of power, can
have three coke grinding trains, three operating plus one
additional spare gasifier trains, two shift/low temperature gas
cooling trains, two AGR/SRU trains, one TGTU train, one syngas
expander and optionally a pressure swing absorption unit for
hydrogen export offsite and two combined cycle power block
trains.
[0041] Contaminant or pollutant emissions in accordance with the
invention can be characterized as follows: [0042] 1) Sweet reducing
gas stream--with oxygen content less than about 1 vol % and an
H.sub.2S content of less than about 50 ppmv, these streams
generally emanating from all the units during start-up with a
sulfur-free hydrocarbon feedstock; [0043] 2) Sour reducing gas
stream--same as the stream described in item 1) except that
H.sub.2S content is greater than about 50 ppmv, these streams
generally emanating from the syngas production zone and the shift
conversion/low temperature gas cooling zone units after the feed to
the syngas production zone is switched to the sulfur containing
feed during start up or during shut down after switching to
sulfur-free; [0044] 3) Sour oxidizing gas stream, e.g., having a
possible oxygen content greater than about 1 vol % and an H.sub.2S
content of a greater than about 10 ppmv; these streams generally
emanating from the equipment associated with the SRU that have
contacted air during normal operation such as sourwater tanks,
sulfur pits, etc; [0045] 4) Sweet oxidizing gas stream--same as the
stream described in item 3) except that the H.sub.2S content is
less than about 10 ppmv, which streams generally emanate from the
units that have contacted air during normal operation such as
solids handling or solids preparation units, sumps, tanks,
instrument vents and bridles and safety valves; and [0046] 5) High
H.sub.2S acid gas stream--containing greater than about 10%
H.sub.2S such as the feed to the SRU, or AGR zone.
[0047] In one embodiment of the present invention a feedstock that
does not contain contaminants such as sulfur-containing compounds
i.e., in amounts of about less than about 10 ppmv sulfur, is used
to carry out the start up of the integrated gasification combined
cycle complex. The sulfur-free feedstock which can be a hydrocarbon
feedstock is passed to the syngas production zone which then
produces a sweet reducing syngas effluent stream. As the
gasification or syngas production zone is being started up this
sweet reducing syngas stream is passed to a blow down conduit.
[0048] The sweet reducing syngas effluent stream is then passed via
the blow down conduit to a flare.
[0049] When the feed rate to the syngas production zone reaches a
predetermined rate at predetermined conditions including a
predetermined pressure and temperature, the syngas zone sweet
reducing effluent is diverted from the blow down conduit to the
shift conversion zone which typically has a low temperature gas
cooling zone disposed downstream thereof. The gases passing through
the shift conversion zone and the low temperature gas cooling zone
and exiting the low temperature gas cooling zone and are
characterized as a sweet reducing stream effluent. This sweet
reducing stream effluent is then passed to a blow down conduit to a
flare.
[0050] Prior to, subsequent to, or contemporaneously with the
gasifier start up, the acid gas removal zone is started up with
nitrogen or any other inert gas. When the acid gas removal zone has
reached predetermined operating conditions including temperature
and pressure the sweet reducing gas from the blow down conduit
associated with the low temperature gas cooling zone is diverted to
the acid gas removal zone. The effluent from the acid gas removal
zone is also characterized as a sweet reducing effluent stream.
This sweet reducing stream is then passed through a blow down
conduit to a flare and combusted in the same manner as described
above.
[0051] Prior to, subsequent to, or contemporaneously with the
start-up of the upstream zones the sulfur recovery zone is started
up with a start-up gas such as natural gas such that when the
sulfur recovery zone has reached operating conditions. The sweet
reducing effluent stream from the acid gas removal zone is then
diverted from the blow down conduit to the sulfur recovery zone to
produce another sweet reducing effluent stream. This sulfur
recovery zone sweet reducing effluent stream is then passed to a
tail gas treatment unit to produce a tail gas treatment unit sweet
reducing effluent. The effluent from the tail gas treatment unit is
then passed through a blow down conduit to a flare and combusted in
the same manner as described above.
[0052] Subsequently the amount of sulfur-free containing feedstock
to the syngas production zone is reduced and the amount of
sulfur-containing hydrocarbon feed stock to the syngas production
zone is increased. The acid gas removal zone sweet reducing
effluent stream is diverted from the sulfur recovery zone and
passed to a sour gas scrubber. The effluent from the sour gas
scrubber is then passed to a flare.
[0053] When the sulfur concentration of the acid gas removal
effluent stream passing to the sour gas scrubber reaches a
predetermined value of about 25 volume percent H.sub.2S, this
stream is diverted back to the sulfur recovery zone while
simultaneously reducing start-up gas to the sulfur recovery zone
and increasing the sulfur laden hydrocarbon feedstock to the
desired operating feed rate.
[0054] Finally, the tail gas treatment unit effluent presently
flowing to the flare is diverted to a point either upstream or down
stream of the acid gas removal zone for additional CO.sub.2
recovery.
[0055] Additionally in accordance with the present invention
various sweet oxidizing gases collected from sumps, tanks,
instrument vents, bridles, and pressure safety valves associated
with the various zones in the IGCC complex can be passed to the
flare or a thermal oxidizer or incinerator such as those commonly
found in some conventional tail gas treating units.
[0056] By following the above start up procedure in accordance with
this invention the IGCC complex can be started up with mitigated
releases of all noxious contaminants.
[0057] Another embodiment of the above start up procedure in
accordance with the present invention involves passing the
sulfur-free start up feedstock through the syngas production and
the shift conversion zone including the low temperature gas cooling
zone prior sending it to a blow down conduit for flaring. FIG. 4
depicts a schematic process flow diagram that would permit this
type of start up. In yet another embodiment of the start-up
procedure the sulfur free start up feedstock is passed through the
syngas production zone, the shift conversion zone, low temperature
gas cooling zone and the acid gas removal zone prior to sending it
to a blow down conduit for flaring. FIG. 5 depicts a schematic
process flow diagram that would permit this type of start up.
[0058] Another embodiment of the present invention provides for a
process for shutting down an integrated gasification combined cycle
complex with mitigating the release of noxious contaminants such as
sulfur. More specifically in the shut down procedure the feedstock
to the syngas production zone is switched to a sulfur-free, i.e.
about less than 10 ppmv sulfur, feedstock. Once the syngas stream
using the sulfur laden hydrocarbon feedstock is displaced by the
syngas using the sulfur free feedstock, the effluent from the
syngas production zone now a sweet reducing gas is diverting from
the shift conversion zone and depressurized to a blow down conduit
associated with the syngas production zone. The effluent from the
syngas production zone is then passed to a flare.
[0059] Subsequently, the effluent from the low temperature gas
cooling zone associated with the shift conversion zone is diverted
from the acid gas removal zone and depressurized to a blow down
conduit associated with the shift conversion zone. This effluent
stream is then passed to a flare.
[0060] The effluent from the acid gas reduction zone is then
depressurized. Specifically the hydrogen rich syngas is passed to a
flare. The acid gas is depressurized to the sulfur recovery
zone.
[0061] The gaseous effluent from the sulfur recovery zone is
depressurized to a tail gas treating unit.
[0062] The effluent from the tail gas treating unit is diverted
from its recycle to the acid gas removal zone and is depressurized
to a flare in accordance with the present invention.
[0063] Finally the fuel to the turbines in the power block zone is
switched from hydrogen to natural gas.
[0064] In another embodiment the gasifier and shift zone can both
be depressurized by diverting the sweet reducing effluent stream
from the low temperature cooling zone to the flare, with the
remainder of the IGCC complex being shut down as described
above.
[0065] In another embodiment of the present invention is to provide
for a process for shutting down an integrated gasification combined
cycle complex while mitigating the release of noxious contaminants
such as sulfur in a manner that does not use a sulfur-free
feedstock as described above. The effluent from the syngas
production zone now a sour reducing gas is diverted from the shift
conversion zone and depressurized to a blow down conduit associated
with the syngas production zone. The effluent from the syngas
production zone is then slowly discharged to a low pressure sour
gas scrubber (such as an amine scrubber) for sulfur removal by
throttling one or more pressure control valves. The effluent from
the sour gas scrubber is passed to a flare for combustion as
described above.
[0066] Subsequently, the effluent from the low temperature gas
cooling zone associated with the shift conversion zone is diverted
from the acid gas removal zone and depressurized to a blow down
conduit associated with the shift conversion zone. This sour
reducing effluent stream is then slowly discharged to a low
pressure scrubber by throttling one or more pressure control
valves. The effluent from the low pressure scrubber is passed to a
flare in accordance with the present invention.
[0067] The effluent from the acid gas reduction zone is then
depressurized. Specifically the hydrogen-rich syngas is passed to a
flare to be combusted and treated in accordance with the present
invention. The acid gas effluent is depressurized to the sulfur
recovery zone.
[0068] The gaseous effluent from the sulfur recovery zone is
depressurized to a tail gas treating unit.
[0069] The effluent from the tail gas treating unit is diverted
from its recycle to the acid gas removal zone and is depressurized
to a flare in accordance with the present invention.
[0070] Finally the fuel to the turbines in the power block zone is
switched from hydrogen to natural gas.
[0071] In another embodiment the gasifier and shift zone can both
be depressurized by diverting the sour reducing effluent stream
from the low temperature cooling zone to a low pressure scrubber
and then to a flare, with the remainder of the IGCC complex being
shut down as described above.
[0072] In yet another embodiment the gasifier, shift and acid gas
removal zones can be depressurized by commencing the acid removal
zone shut down as described above and not depressurizing the
gasifier and shift individually prior to the depressurization of
the acid gas removal zone as described above.
[0073] For the purposes of this invention the tail gas treating
unit comprises of the following components and operates as
described below.
[0074] In this invention, the tail gas treatment unit can contain
either one standard amine absorber for both normal operations and
gasifier shutdown operations or two amine absorbers one dedicated
for gasifier shutdown and the other for normal operating
conditions. The TGTU unit also contains several exchangers, pumps,
filters and a stripping column. The TGTU amine absorber is used to
remove the H.sub.2S in the TGTU feed. The H.sub.2S is absorbed in
the amine and the rich amine (H.sub.2S laden amine solvent) is
regenerated to an essentially sulfur free amine by stripping the
rich amine with steam in the stripping column or regenerator. This
regenerated amine is reused in the TGTU process and the H.sub.2S
from the stripping process is recycled back to the sulfur recovery
unit for further sulfur removal. The TGTU also contains a thermal
oxidizer or incinerator for the combustion of tail gas effluent,
SRU startup gases, fugitive emissions, and gases from the sulfur
pits, sulfur storage tanks and sulfur loading docks.
[0075] For the purposes of this invention, the flare header system
can contain the following components and operates as described
below.
[0076] The flare header system as shown in FIG. 3 is divided in to
several streams depending on the H.sub.2S and/or oxygen content.
These streams are separated into: sour reducing gas, sour oxidizing
gas, sweet reducing gas, sour reducing gas and high acid or
H.sub.2S gas streams. A vapor recovery unit of the eductor or
compressor type is used to recover any usable or saleable gases
from the header system. Included in the flare system is an
emergency caustic scrubber for the removal of H.sub.2S from high
acid gas streams in the event of an emergency shut down or during
the startup of the sulfur recovery unit. Separate flare knock out
drums are required to remove any water from the gases before they
are combusted in the flare.
[0077] The start-up hydrocarbon-containing feedstock or fuel that
is free of sulfur can be natural gas or light hydrocarbon liquid
such as methanol. The start-up fuel rate can be less than or, for
instance, about 10% to more than 50% of the normal operating
condition ("NOC") of one gasifier throughput. As the gasifier
pressure is increased, the rest of the gasification system is
commissioned.
[0078] For instance, when the methanol and oxygen mixture is first
ignited in the gasifier, the pressure will rapidly increase to
50-150 psig (345-1034 kPa) within minutes after the lightoff with a
pressure control valve opened and adjusted to produce such a
backpressure. The blow down syngas is routed to the sweet reducing
gas header to the flare. A water knockout drum at the inlet of the
flare is necessary to remove any condensed moisture from the wet
syngas mixture at start-up. The gasifier pressure is gradually
increased by throttling the pressure control valve to the blowdown
stream. The water in the syngas includes the equilibrium water at
the gasifier operating pressure and any water physically entrained
by the syngas flow. As mentioned in one embodiment, the blow down
gas is sent to the flare. In order to keep the gasification system
gas velocity roughly constant during start-up, an example of the
ramp up schedule of the gasifier start-up can be as follows: [0079]
Hold pressure at about 150 psig (1034 KPa) for about 1 hour to
check leak and tighten flanges if the gasifier has completed a
turnaround maintenance; [0080] Increase the gasifier throughput and
adjust the pressure of the gasifier accordingly, e.g., about 40%
NOC at about 400 psig (2758 KPa), 50% NOC at about 500 psig etc. It
can take about 30 minutes to reach about 70% NOC and about 700 psig
(4826 KPa) pressure; [0081] When the gasifier throughput reaches
about 70% NOC at about 700 psig (4826 KPa), the pressure can be
increased until the gasifier pressure reaches the NOC operating
pressure (e.g. about 1000 psig (6895 KPa); [0082] Alternatively,
for the first gasifier/shift/low temperature gas cooling Acid Gas
Removal train start-up, if the AGR can be operated at a reduced
pressure and a reduced throughput, the gasifier pressure and
throughput can be ramped up to only about 40% NOC throughput at
about 400 psig (2758 KPa) for the AGR start-up to save start-up
fuel and oxygen. This 40% minimum turndown is based on the
constraints provided by a typical AGR column design; [0083] As the
gasifier pressure is increased, the rest of the gasification black
water flash system is commissioned (the term "black water"
designates the water stream from the gas/water scrubber used to
remove particulates from the gasifier which is subsequently flashed
to remove any dissolved gases); and [0084] Ramping the gasifier
pressure at 50-100% NOC to 100 (689.5 KPa)-1300 psig (8963 KPa).
and lining out the unit, it should take a short time to reach the
state NOC at full gasifier operating pressure before introducing
gas to the shift section.
[0085] The syngas from the gasification zone is introduced to the
shift section and the low temperature gas cooling ("LTGC") section.
The syngas from the gasification zone syngas scrubber overhead is
diverted from the flare and introduced to the shift zone and the
LTGC zone by first opening the small equalizing valve at the inlet
of the shift zone gradually to equalize the upstream and downstream
pressure. After the pressure is equalized, then a control valve can
be gradually opened to introduce more syngas to the shift zone and
downstream. Simultaneously, the pressure control valve controlling
the venting of the sweet syngas to the blowdown conduit passing to
the flare can be gradually closed as more syngas is introduced to
downstream section.
[0086] The introduction of syngas to the acid gas removal is
performed similar to the introduction of syngas to the shift/LTGC
zones. The scrubbed and shifted syngas passing through the AGR zone
should be routed to the flare at a blow down conduit located at the
outlet of the H.sub.2 rich syngas in the AGR. Any CO.sub.2 stream
from the AGR unit can be vented to the atmosphere using a CO.sub.2
vent stack. The AGR sweet acid gas is then sent to the Sulfur
Recovery Unit ("SRU"). The SRU can be started up with supplementary
firing using natural gas because the sweet acid gas contains
practically no H.sub.2S. The SRU refractory heat up is estimated to
take at least about 16 to about 24 hours to complete. The SRU
should reach steady-state operation such that it is ready to
receive sour acid gas. The effluent from the TGTU low pressure
amine scrubber contains mainly CO.sub.2 and is vented to a location
downstream of the flare combustor burner during this start-up
period.
[0087] The switching of the sulfur-free startup fuel to coke slurry
feed can be performed after the AGR/SRU have reached steady-state
operation. The composition of the vented syngas at the AGR will
change slightly after the fuel switching. However, the switching of
the sweet to sour acid gas to the SRU can be done over about a 30
minute to about one hour period. The sour acid reducing gas coming
from the AGR is first routed to a low low pressure ("LLP") scrubber
and then to a flare and then switched gradually to the SRU burner.
Such switching of flow to the SRU burner is carried out while
simultaneously reducing the start-up natural gas supply to the
SRU.
[0088] After switching the fuel from clean sulfur-free natural gas
or hydrocarbon liquid to coke slurry feed, the AGR acid gas
H.sub.2S concentration will steadily increase. The SRU operation is
then adjusted to normal operating conditions by feeding H.sub.2S
acid gas from the AGR and NH.sub.3 from a sour water stripper to
the SRU. The SRU tailgas is sent to the TGTU amine scrubber. The
TGTU amine scrubber overhead is first sent to the thermal oxidizer
or flare. When the H.sub.2S content in the scrubbed TGTU overhead
gas is verified to be acceptable, i.e., less than ppmv 10 ppmv, the
tail gas compressor can then be started up in order to route the
tail gas to the product CO.sub.2 stream or alternatively, if the
H.sub.2S content is too high, it can be routed to a point upstream
of the AGR. The CO.sub.2 stream from the AGR is routed to the
CO.sub.2 pipeline for sales or EOR.
[0089] The clean H.sub.2 rich syngas can also be routed downstream
using the expander bypass line to vent at the gas turbine inlet
after the gasifier lightoff. The pressure control valve on an
expander bypass can be used to automatically control the expander
upstream pressure and the pressure control valve on the blowdown
conduit to the flare can be used to automatically control the
expander downstream pressure to the gas turbine.
[0090] For a planned shutdown, the shutdown actions can generally
be carried out by reversing the steps of the start-up procedure.
The gasifier throughput is reduced, e.g., from about 100% to about
70% at its normal operating pressure, and the fuel can be switched
from coke slurry to a sulfur-free feedstock such as methanol. The
gas turbine can be backed down commensurately. After switching the
fuel to the gasifier, the syngas scrubber overhead control valve
can be gradually closed, with the pressure control valve opened
gradually to vent to the sweet reducing gas blowdown header passing
to the flare. As the syngas is vented, the gasifier throughput is
reduced simultaneously to minimize venting. When the syngas
scrubber overhead control valves are completely closed, the clean
syngas is 100% routed to the flare. The pressure and the throughput
of the gasifier operating on the clean fuel can be gradually
reduced until an arbitrary low throughput is achieved and a reduced
gasifier pressure (for example, 50% NOC at 500 psig (3447 KPa)
gasifier pressure) is established. The gasifier shutdown sequence
is then initiated to shutdown the gasifier in a controlled
manner.
[0091] When the gasifier shutdown sequence is initiated to shutdown
the gasifier in a controlled manner, the syngas system is bottled
up at operating pressure. The gasifier will be depressured
gradually through the gasifier blowdown conduit to the flare. The
flow rate of the syngas to the flare due to depressurizing can be
calculated by the reduction of inventory accordingly. After the
syngas depressuring, the system can be nitrogen purged. The
shutdown nitrogen purge is also sent to the flare as well via the
gasifier blowdown conduit.
[0092] The pollution control equipment includes all equipment and
flow schemes shown in FIGS. 2 and 3. For example, the relief or
blow down gases are segregated into various relief headers
according to whether the gases contain H.sub.2S and oxygen, as
described previously. A recovery system is included to recover any
usable gases such as H.sub.2, CO.sub.2 or sulfur for sales. A
ground or elevated flare is used for emergency safety relief,
shutdown and start-up operations. The sour gas scrubbers are used
for H.sub.2S removal in the startup/shutdown cases and in emergency
acid gas release. The following is a non-exclusive example list of
the pollution control equipment that may be used in an IGCC complex
to carry out an embodiment of the present invention: [0093] Thermal
Oxidizer or Incinerator, Aux Boiler, Duct firing with HRSG (of
these units will generally have an SCR downstream) [0094] Emergency
Sour Gas Scrubber (amine or caustic) [0095] LLP Sour Gas Scrubber
(TGTU MDEA absorber) [0096] Flare Vapor Recovery System (sour gas
recycle compressor) [0097] TGTU Tail Gas Compressor [0098] Flare
Knockout Drum [0099] Oxidizing Sour Gas Fugitive Emission Collector
(eductor) System [0100] Reducing Sour Gas Fugitive Emission
Collector (eductor or compressor) System [0101] Oxidizing Sweet Gas
Fugitive Emission Collector (eductor or aspirator) System [0102]
Reducing Sweet Gas Fugitive Emission Collector (eductor or
compressor) System [0103] Gas Turbine/HRSG Pollution Control
Systems
[0104] When pollution-control equipment is all operating properly,
the sour gas coming from in the SRU tailgas is scrubbed and the
clean TGTU tail gas is recycled back to upstream of the CO.sub.2
compressors.
[0105] While the present invention has been described in terms of
preferred embodiments, it will be understood, of course, that the
invention is not limited thereto since modifications may be made by
these skilled in the art, particularly in light of the foregoing
teachings.
* * * * *