U.S. patent application number 14/143703 was filed with the patent office on 2014-11-13 for gas turbine combined cycle system.
This patent application is currently assigned to Bechtel Power Corporation. The applicant listed for this patent is Bechtel Power Corporation. Invention is credited to Seyfettin C. Gulen.
Application Number | 20140331686 14/143703 |
Document ID | / |
Family ID | 51863807 |
Filed Date | 2014-11-13 |
United States Patent
Application |
20140331686 |
Kind Code |
A1 |
Gulen; Seyfettin C. |
November 13, 2014 |
GAS TURBINE COMBINED CYCLE SYSTEM
Abstract
In a combined cycle gas turbine configuration having at least
two power blocks, stack emissions (particularly nitrous oxides or
NOx but also carbon monoxide CO and unburned hydrocarbons, UHC) are
controlled concurrently with part load power output. In one power
block a combined cycle power plant has a relatively large
heavy-duty industrial gas turbine fired to about 1,700.degree. C.
at the turbine inlet leading to a first heat recovery system. A
second power block with a smaller gas turbine has a second heat
recovery system. A controller adjusts coupling of flue gas and
steam paths from the second power block to the first power block to
meet load demand in compliance with applicable emissions
regulations.
Inventors: |
Gulen; Seyfettin C.;
(Middletown, MD) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Bechtel Power Corporation |
Frederick |
MD |
US |
|
|
Assignee: |
Bechtel Power Corporation
Frederick
MD
|
Family ID: |
51863807 |
Appl. No.: |
14/143703 |
Filed: |
December 30, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61820901 |
May 8, 2013 |
|
|
|
Current U.S.
Class: |
60/783 ;
60/39.182 |
Current CPC
Class: |
Y02E 20/16 20130101;
F01K 23/10 20130101; F01K 23/101 20130101 |
Class at
Publication: |
60/783 ;
60/39.182 |
International
Class: |
F01K 23/10 20060101
F01K023/10 |
Claims
1. A gas turbine combined cycle system comprising: (a) a first
power block with a first gas turbine configured as a prime mover, a
first heat recovery steam generator coupled to an exhaust path of
the first gas turbine, and a steam turbine coupled to a steam
outlet of the steam generator, the steam turbine being configured
as a prime mover, wherein the first power block drives an electric
generator; (b) at least one additional power block with a gas
turbine configured as a prime mover thermally coupled to a second
heat recovery steam generator; (c) wherein a controller is coupled
to provide a flow of at least one of flue gas and steam from the
additional power block to the first power block, said flow
concurrently adjusting a power output of the first power block and
a harmful emission level of the first gas turbine.
2. The system of claim 1, further comprising a flue gas compressor,
mechanically driven from one of an electric motor and a shaft of
the gas turbine of the additional power block.
3. The system of claim 1, wherein at least two of the prime movers
are mechanically coupled to drive a single shaft coupled to the
electric generator.
4. The system of claim 1, comprising a multi-shaft configuration
wherein each of the prime movers is coupled to a respective
electric generator on a shaft.
5. The system of claim 1, wherein the gas turbine prime mover of
the first power block comprises a frame machine of one of an F, G,
H or J class, with a firing temperature as high as 1,700.degree.
C.
6. The system of claim 1, wherein the gas turbine prime mover of
the at least one additional power block comprises an
aero-derivative unit having a high cycle pressure ratio and high
cycle efficiency, and a power output and airflow that is a fraction
of that of the gas turbine prime mover of the first power
block.
7. The system of claim 1, wherein the flue gas compressor comprises
a multi-casing unit with at least two casings, and further
comprising intercooling between sections of the flue gas
compressor.
8. The system of claim 1, wherein flue gas from the heat recovery
steam generator of the at least one additional power block is
coupled to the first gas turbine at one of a gas turbine compressor
inlet and a gas turbine combustor fuel inlet.
9. The system of claim 1, wherein the second heat recovery steam
generator is coupled to the first gas turbine at one or more entry
locations on the turbine casing, so as to contribute cooling of
components subjected to hot combustion gases.
10. The system of claim 1, further comprising an aftercooler heat
exchanger downstream of the flue gas compressor, wherein steam is
heated before entry into a second gas turbine prime mover.
11. The system of claim 1, wherein feed water from the second heat
recovery steam generator is connected to a flue gas compressor
intercooler for direct contact heat exchange between hot compressed
flue gas from an upstream compressor section and said feed
water.
12. The system of claim 10, further comprising precooler and trim
cooler water-to-flue-gas heat exchangers upstream and downstream of
the flue gas compressor aftercooler, wherein said heat exchangers
are configured to adjust flue gas compressor suction and discharge
gas temperatures.
13. A method for adjusting a load of a first gas turbine and
related exhaust emissions thereof, comprising: apportioning flue
gas from a second heat recovery steam generator between a
compressor and combustor fuel inlet of the first gas turbine, steam
flow to the first gas turbine for hot gas path component cooling
and feed water flow to an intercooler of a flue gas compressor,
including adjusting: (a) flue gas flow from the second heat
recovery steam generator to the first gas turbine compressor inlet;
(b) flue gas flow from the second heat recovery steam generator to
the fuel gas compressor and, subsequently, to the first gas turbine
combustor fuel inlet; (c) steam flow and temperature to the first
gas turbine, via an aftercooler; (d) feed water flow from the
second heat recovery steam generator to a fuel gas compressor
intercooler; (e) cooling water flow to a flue gas compressor
precooler; and (f) cooling water flow to a flue gas compressor trim
cooler.
14. The method of claim 13, further comprising coupling a
controller to least the first gas turbine and associated flow paths
for sensing operational parameters and wherein the apportioning
comprises generating control outputs to associated valves.
15. The method of claim 13, wherein said exhaust emissions comprise
NOx, CO and UHC.
16. The method of claim 13, wherein said adjusting is sequential
along steps (a) through (f).
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the benefit of U.S. Provisional
Application No. 61/820,901, filed May 8, 2013.
FIELD
[0002] This disclosure concerns the field of gas turbines and in
particular provides methods and apparatus for managing stack
emissions (e.g., nitrous oxides (NOx), carbon monoxide (CO),
unburned hydrocarbons (UHC) and the like), while concurrently
controlling load power output. The invention is particularly
applicable to combined cycle power plants with heavy-duty
industrial gas turbines, fired, for example, to 1,700.degree. C.
(3,092.degree. F.) at the turbine inlet.
BACKGROUND
[0003] The term "combined cycle" generally refers to an assembly of
two or more engines driven from the same source of heat, converting
heat energy into mechanical energy, usually to drive one or more
electrical generators. In gas turbine (GT) combined cycle plants,
expansion of product gas resulting from combustion of fuel turns a
gas turbine. Hot exhaust gases from the gas turbine are the heat
source for generating steam in a heat recovery steam generator
(HRSG).
[0004] Combining two or more thermodynamic cycles reduces the
energy released as wasted exhaust heat. One combination comprises a
gas turbine (operating by the Brayton cycle) fueled by natural gas
or synthesis gas from coal. The hot exhaust from the gas turbine
powers a steam power plant (operating by the Rankine cycle).
[0005] Advantageously, the combined cycle plant is operated cleanly
and efficiently. An important parameter controlling the efficiency
of a gas turbine combined cycle power plant is the maximum
temperature of the gas turbine Brayton cycle. Strictly speaking,
the highest temperature found in the gas turbine cycle is the flame
temperature in the combustor, which is well above 3,000.degree. F.
But in practical terms, a logical choice for a control parameter is
the combustor exit temperature, after dilution with combustor liner
cooling flow and before the inlet to the turbine section. This
temperature is commonly referred to as Turbine Inlet Temperature
(TIT). Another commonly used engineering proxy for cycle maximum
temperature is the temperature of hot combustion gas at the inlet
of the stage 1 rotor or bucket ("S1B") before the gases start to
produce useful turbine work. This temperature is commonly known as
the "Firing Temperature" and in F class gas turbines it is about
200.degree. F. or more lower than the hot gas temperature at the
combustor exit (at the inlet of stage 1 vane or nozzle, S1N, i.e.,
the "true" TIT). Thus, another term for Firing Temperature is Rotor
Inlet Temperature (RIT), where the referenced rotor is the stage 1
rotor. That temperature is about 100.degree. C. higher than the
fictitious temperature defined in the ISO-2314 gas turbine
acceptance standards adopted by European OEMs.
[0006] Modern gas turbine combined cycle apparatus are exemplified
by advanced F, G, and H class units with TITs greater than
1,500.degree. C. About 60% gas turbine combined cycle (GTCC) net
efficiency has been achieved with these advanced units.
[0007] The design of high efficiency, high temperature gas turbines
presents challenges including (1) cooling of the turbine hot gas
path (HGP) components operating at such high temperatures; and (2)
control of NOx and CO emissions. Cooling is advantageous to achieve
acceptable parts life. Increasingly stringent emission limits are
being imposed by regulatory agencies.
[0008] Techniques for accommodating high temperatures include using
advanced nickel-based superalloys and casting techniques (e.g.,
single crystal) for turbine elements, accompanied by ceramic-based
thermal barrier coatings (TBC), stationary and rotating airfoils of
the first turbine stage (commonly known as nozzles/vanes and
buckets/blades, respectively). Even when using the most advanced
materials and coatings, cooling of HGP components by air extracted
from the compressor discharge is necessary to ensure feasible parts
life. Turbine HGP cooling by compressor extraction air is
detrimental to gas turbine performance in at least two aspects. One
aspect of introducing "cold" air into the hot combustion gas stream
is to reduce the gas temperature between the turbine inlet and the
stage 1 rotor inlet (where the gas starts generating useful shaft
work). Thus, in order to achieve a desired firing temperature, the
gas turbine combustor needs to be fired that much harder, with
direct impact on NOx emissions. Another aspect of air cooling is
that the air used to cool the stage 1 rotor does not produce useful
shaft work. The cooling air limits the desired impact of higher
firing temperatures.
[0009] One possible solution to this two-pronged problem would be
to develop materials that require little or no cooling. It may be
possible at some point to extend ceramics used in TBC to monolithic
ceramic materials useful in stationary and rotating components.
Such developments remain a major challenge. Combining the heat
resistance of ceramics with the strength of metal (ceramic by
itself is brittle), a ceramic matrix composite (CMC) may be a
candidate to solve the cooling problem of turbine HGP components at
very high temperatures. But commercialization seems to be decades
off.
[0010] One existing technology in this regard is closed-loop steam
cooling of turbine HGP components. In particular, General
Electric's H-System.TM. with two stages (stages 1 and 2) fully
steam cooled (i.e., both stationary and rotating components); and
Mitsubishi Heavy Industries' (MHI) G and J class machines with
steam cooling of combustor transition piece (the duct between the
combustor exit and turbine inlet) and turbine blade rings
(shrouds).
[0011] Steam cooling in a closed loop (i) reduces the temperature
dilution between combustor exit (i.e., turbine inlet) and stage 1
rotor inlet and (ii) releases cooling air for work production in
the turbine (in H-System.TM.). Thus, for example, by cooling stage
1 vanes with steam imported from the bottoming cycle, the
difference between TIT and firing temperature can be reduced from
greater than 200.degree. F. to about 60-80.degree. F. This results
in an increase of firing temperature at the same TIT (that is, at
the same level of NOx emissions). Alternatively, it allows the
deployment of parts with current materials and coating
technologies, at higher TIT.
[0012] One drawback of steam cooling technology is a lack of
"flexibility". Specifically, the availability of steam (or the lack
of it) during the early phase of combined cycle startup slows down
the process until enough steam is generated in the HRSG to supply
the gas turbine. An auxiliary boiler might be utilized instead to
provide cooling steam during startup, but at the expense of
additional startup fuel consumption and emissions, and at
additional capital cost.
[0013] Apart from cooling problems, NOx emissions remain an
obstacle in the path of ever-rising TITs. NOx is a generic term for
nitrous oxides NO and NO.sub.2 (nitric oxide and nitrogen dioxide).
They are produced from the reaction of nitrogen and oxygen gases in
the air during combustion, especially at high temperatures. NOx
gases react to form smog and acid rain as well as being central to
the formation of tropospheric ozone. Levels of NOx emission are
strongly related to the flame temperature in the combustor's
primary zone.
[0014] Since the flame temperature is directly related to TIT, a
change in TIT from 1,600.degree. C. to 1,700.degree. C., for
example, may increase NOx emissions in Dry Low NOx (DLN) combustors
by 150% to 250%.
[0015] One possible method to control the NOx emissions is to
reduce the flame temperature in the primary flame zone of the DLN
combustor by introducing a diluent into the fuel-air mixture. The
diluent may act as a heat sink. In earlier generations of
industrial GTs with diffusion combustors, this was done by
injecting water or steam into the combustor. In DLN combustors,
diluent water injection is only used when burning liquid fuel
(e.g., #2 fuel oil). Another possible method of introducing
H.sub.2O as a diluent into the combustor is via fuel gas
moisturization (employed by General Electric's H-System.TM.). A
method used in internal combustion is to recirculate the exhaust
gas and dilute the combustion motive air while increasing its
CO.sub.2 content. This is known as Exhaust Gas Recirculation (EGR).
EGR can be accomplished in two ways: [0016] Introducing the HRSG
stack gas into the inlet of the compressor; or [0017] Compressing
the HRSG stack gas up to the GT casing pressure using a separate
compressor and mixing it with fuel gas prior to introducing it into
the combustor to be burned.
[0018] The EGR method can be used with DLN as well as diffusion
combustors. Studies show that at a temperature of 1,700.degree. C.,
the lowest level of NOx concentration is obtained in the diffusion
type combustor when the recirculation ratio is increased to about
35%.
[0019] Another item of interest in terms of flexibility of large
gas turbines is the ability to run at a part load with maximum
possible efficiency and full emissions compliance. A gas turbine is
said to run at full load at given site ambient conditions when two
conditions are satisfied: the gas turbine inlet guide vanes are at
their normal fully open position; and the gas turbine is fired to
its rated firing temperature based on its normal full load control
curve.
[0020] The term "base load" typically applies to gas turbine full
load at a specific site ambient condition, e.g., ISO conditions of
59.degree. F. (15.degree. C.), 60% relative humidity and 14.696
psia (1 atmosphere). A gas turbine is said to run at "part load"
when its power output is less than it would be if it were running
at full load at a given site ambient conditions.
[0021] For maximum combined cycle efficiency, gas turbine part load
is controlled first by closing the inlet guide vanes (IGVs) and
reducing the airflow at the same firing temperature. This reduces
cycle pressure ratio and increases the exhaust temperature for
maximum contribution from the bottoming cycle (i.e., the steam
turbine). When the exhaust temperature reaches a certain limit
(commonly known as the exhaust isotherm, typically around
1,200.degree. F.), the gas turbine controller starts reducing the
fuel flow, and consequently the firing temperature, while keeping
the exhaust temperature at its maximum value. Once the IGVs reach
their fully closed position (i.e., minimum airflow), further
reduction in output is achieved by reducing the fuel flow, and
exhaust temperature starts going down, with further detrimental
impact on the contribution of the bottoming cycle.
[0022] With multiple gas turbine plants such as 2.times.1 (two GTs
with two HRSGs and one steam turbine, ST) one can turn one GT off
to achieve 50% or lower plant load with improved heat rate
(compared to 1.times.1 plants). In general, GTCC plants with
advanced gas turbines utilizing DLN combustors cannot be turned
down below 30-40% load and still be emissions compliant. One
exception is the sequential combustion gas turbines (also known as
reheat gas turbines) with two combustors, which can turn down the
second (downstream) combustor at low loads with better efficiency
while maintaining emissions at allowable limits.
[0023] One possible method to reduce the GT output while
maintaining the IGVs at their fully open position is to increase
the temperature of the compressor airflow. This leads to reduced
density and mass flow rate and has a similar effect on the GT as if
it were operating on a hot day. It can be shown that at the same
level of part load (i.e., same megawatt output), this method
results in a better CC heat rate while also helping to reduce the
emissions. There are several ways to accomplish this effect, as
described in e.g., U.S. Pat. No. 7,305,831, which is hereby
incorporated by reference in this disclosure.
SUMMARY OF THE INVENTION
[0024] An object of the present disclosure is to optimally limit
NOx emissions over a range of plant loading conditions. Two
different classes of gas turbines are operated in a combined cycle
configuration for concurrent optimized control of NOx emissions and
plant load. One gas turbine advantageously is an F, G, H or J class
heavy-duty industrial machine with very high TIT (up to
1,700.degree. C.) and commensurate airflow to achieve 300 MW or
higher power output (henceforth, HDGT for Heavy Duty Gas Turbine).
The other gas turbine advantageously is a smaller gas turbine.
Ideally, the smaller gas turbine is an aero-derivative GT such as
General Electric's LMS100.TM.. The invention also can be applied to
other gas turbines, preferably wherein a smaller GT has a power
output and airflow about one third of that of the larger HDGT.
[0025] Thus, according to one aspect, the exhaust gas of a smaller
GT generates steam in a small HRSG, and that steam is used in
cooling the hot gas path (HGP) components of the larger GT.
[0026] In one embodiment, part or all of the HRSG stack gas is
divided into two streams. One stream is coupled into the compressor
inlet of the larger GT for load control. Another stream is coupled
into a gas compressor on the same shaft as the smaller GT to be
compressed and fed into the combustor of the larger GT for NOx
control. As used in this disclosure, terms such as "coupled" and
"connected" are intended to denote operational relationships, and
although direct connections are possible, the terms do not exclude
indirect operational connections such as couplings through
intervening elements.
[0027] Hot water generated in the economizer of the small HRSG is
injected into the hot flue gas downstream of the first gas
compressor for intercooling. Steam generated in the small HRSG is
heated to a prescribed temperature in an aftercooler (AC)
downstream of the second gas compressor (e.g., 650.degree. F. or
.about.350.degree. C.). Following the AC, compressed hot flue gas
is cooled in a trim cooler (as needed) and mixed with fuel gas
prior to entry into the fuel skid of the larger GT.
[0028] The term "exhaust gas" is used henceforth in this disclosure
for the exhaust gas of the gas turbine between the exit of the gas
turbine and the exit of the last HRSG heat exchanger section (e.g.,
a low pressure economizer) before the stack (flue). Once beyond the
HRSG, the exiting gas is referred to as flue gas.
[0029] The foregoing and other objects and advantages are provided
in a gas turbine combined cycle system with a first combined cycle
power block with a heavy duty gas turbine operated at high turbine
inlet temperature, up to 1,700.degree. C., together with a smaller
gas turbine combined cycle power block, wherein at least one of the
two material streams, flue gas and steam, from the smaller power
block is introduced into the heavy duty gas turbine of the first
power block to control the gas turbine NOx emissions and power
output (load). Requisite controls are implemented to optimize
operating parameters while meeting emissions-compliant load
requirements.
[0030] The first power block has a first gas turbine configured as
a prime mover, a first heat recovery steam generator coupled to an
exhaust path of the first gas turbine, and a steam turbine coupled
to a steam outlet of the steam generator. The steam turbine also is
configured as a prime mover, and at least these two prime movers
drive an electric generator. The smaller at least one additional
power block has a gas turbine configured as a prime mover thermally
coupled to a second heat recovery steam generator. A controller is
coupled to provide and/or to adjust a flow of at least one of flue
gas and steam from the additional power block to the first power
block. This flow concurrently adjusts a power output level of the
first power block and a level of potentially harmful emissions from
the first gas turbine at specified turbine inlet temperature, which
can be as high as 1,700.degree. C.
[0031] In one embodiment, a flue gas compressor, mechanically
driven from one of an electric motor or a shaft of the gas turbine
of the additional power block, injects part of the flue gas from
the additional power block into the combustor of the gas turbine of
the first power block for reducing the NOx emissions.
[0032] The various prime movers can be coupled to apply torque to
separate electric generators or can be mechanically coupled by
gears and clutches to drive a single shaft coupled to an electric
generator.
[0033] Advantageously, the gas turbine prime mover of the first
power block can include a frame machine of one of an F, G, H or J
class, with a firing temperature up to 1,700.degree. C. By
controlling the combustion oxygen content via exhaust gas
recirculation, the level of emissions is controlled, especially
that of NOx.
[0034] The gas turbine prime mover of the at least one additional
power block can include an aero-derivative unit having a high cycle
pressure ratio and high cycle efficiency. The power output and
airflow of the additional power block are a fraction of that of the
gas turbine prime mover of the first power block. The flue gas
compressor driven from the additional power block can be a
multi-casing unit with at least two casings (sections).
Intercooling can be provided between sections of the flue gas
compressor.
[0035] Flue gas from the heat recovery steam generator of the at
least one additional power block is coupled to the first gas
turbine (i.e., the large heavy duty gas turbine with very high TIT
in the first power block). This coupling can be made at one of a
gas turbine compressor inlet and a gas turbine combustor fuel
inlet. The second heat recovery steam generator is coupled to the
first gas turbine at one or more entry locations on the turbine
casing, so as to contribute steam for cooling of components
subjected to hot combustion gases.
[0036] In one embodiment, an aftercooler heat exchanger is placed
downstream of the flue gas compressor. Steam is heated in the
aftercooler heat exchanger before entry into a second gas turbine
prime mover.
[0037] Feed water from the second heat recovery steam generator can
be coupled to a flue gas compressor intercooler for direct contact
heat exchange between hot compressed flue gas from an upstream
compressor section and the feed water. Precooler and trim cooler
water-to-flue-gas heat exchangers can be provided upstream and
downstream of the flue gas compressor aftercooler. Such heat
exchangers are configured to adjust flue gas compressor suction and
discharge gas temperatures. The adjustments are made by a
programmed controller based on sensed inputs including load
demands, temperatures, pressures, flow rates, ambient conditions
and the like.
[0038] In addition to a system, the invention encompasses a method
for adjusting the load of a first gas turbine, and related exhaust
emissions levels thereof. This method involves apportioning flue
gas from a second heat recovery steam generator between a
compressor and combustor fuel inlet of the first gas turbine, steam
flow to the first gas turbine for hot gas path component cooling
and feed water flow to an intercooler of a flue gas compressor. The
flows that are advantageously controlled and adjusted include the
flue gas flow from the second heat recovery steam generator to the
first gas turbine compressor inlet; the flue gas flow from the
second heat recovery steam generator to the fuel gas compressor
and, subsequently, to the first gas turbine combustor fuel inlet;
the steam flow to the first gas turbine and its temperature,
controlled via an aftercooler; a feed water flow from the second
heat recovery steam generator to a fuel gas compressor intercooler;
cooling water flow to a flue gas compressor precooler; and cooling
water flow to a flue gas compressor trim cooler. These adjustments
can be sequential, concurrent or grouped for establishing and
maintaining predetermined conditions.
[0039] At least the foregoing flows and potentially additional
operational parameters are monitored and controlled by coupling a
controller to at least the first gas turbine and associated flow
paths. The controller is responsive to temperature, pressure, flow
and load sensors, and apportions flows by generating control
outputs to associated valves and switches.
[0040] Among other control objects, the controller is arranged to
provide a high turbine inlet temperature at the first power block,
for power generation efficiency as a function of fuel burned, but
without producing undue levels of undesirable exhaust emissions
such as NOx, CO and UHC.
BRIEF DESCRIPTION OF THE DRAWINGS
[0041] Embodiments of the invention will now be described with
reference to the accompanying drawing.
[0042] FIG. 1 is a schematic view of an embodiment of the present
invention.
DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS
[0043] An exemplary embodiment as shown in FIG. 1 has two power
blocks. Power Block 1 comprises a first gas turbine (GT #1) and a
steam turbine (ST), labeled but not shown as a separate block, on a
single shaft driving a single generator or each driving its own
generator in a multi-shaft configuration. Power Block 2 comprises a
second gas turbine (GT #2) and an intercooled, two-stage flue gas
compressor (FGC) on a single shaft with a single electric
generator.
[0044] The gas turbine prime mover of each power block burns fuel
and is thermally coupled to a heat recovery steam generator HRSG
via the exhaust of the respective prime mover, i.e., GT #1 supplies
hot exhaust gas to HRSG #1 (labeled but not shown as a separate
block) and GT #2 supplies hot exhaust gas to HRSG #2.
[0045] The shaft configuration of Power Block 2 is not critical to
the invention. That is, Power Block 2 can be a single-shaft or
multi-shaft configuration. In a multi-shaft configuration, the FGC
can be driven by an electric motor. Depending on the size of the
system in question, this motor can be as large as 50 MW or even
greater. As such, it is an expensive component of a size beyond the
capability of most manufacturers. In a single shaft configuration
as shown in FIG. 1, the FGC is connected to the GT #2 generator via
a clutch and gear box (if necessary). Thus, Power Block 2 can
operate when Power Block 1 is shut down and the FGC is disengaged.
Power Block 2 is of a smaller load rating the Power Block 1, and
independent operation of Power Block 2 is advantageous, for example
to handle overnight low load operation and similar situations.
[0046] Referring to FIG. 1, Power Block 2 (at the top section of
the FIGURE) has three products: [0047] HRSG stack gas (also known
as flue gas) for part load (megawatt output) and combustor NOx
emissions control of the GT #1 (labeled 1 and 2). [0048] Medium
pressure steam (labeled 3) for cooling of HGP components of the GT
#1. [0049] Low pressure feed water for intercooling of compressed
flue gas (labeled 4).
[0050] A controller preferably receives as inputs data or signal
levels at least representing: Site ambient conditions (temperature
and humidity in particular); operator's load demand (a megawatt
power output target); and for GT #1, pressure ratio (or compressor
discharge pressure), compressor discharge temperature and exhaust
temperature.
[0051] The controller preferably applies a programmed control
algorithm, which can be based on a full thermal model of GT #1
(commonly known as a Model Based Control or MBC as known in the
art) or on pre-calculated curves or on other similar methods, the
controller generates the following outputs:
[0052] (1) Apportioning of the cooled GT #2 exhaust gas flow at the
exit of HRSG #2 between: (a) GT #1 compressor inlet for GT #1
megawatt output control (at part load) via increased inlet
temperature and reduced airflow; (b) GT #1 combustor inlet via
mixing with fuel gas (following compression in the FGC); and (c)
HRSG #1 stack (of the remainder, if any).
[0053] (2) Steam flow and temperature to GT #1 for HGP component
cooling (typically, 650 psia and 650.degree. F., to be determined
by the GT OEM). As shown in FIG. 1, HRSG #2 utilizing the exhaust
of GT #2 can generate about 50 pps (180,000 pph) saturated steam at
675 psia. Ultimately, the cooling steam requirement is determined
by the cooling duty, which is a direct function of the HGP parts to
be cooled (e.g., combustor liner and the transition piece in G and
J class machines, stage 1 nozzles, etc.). It is highly likely that
all available steam will be used on occasion, and advantageously
can be supplemented by additional steam from HRSG #1.
[0054] (3) Feed water flow to the intercooler (a direct contact
heat exchanger similar in principle to the GT inlet evaporative
coolers) of the FGC to maintain a nearly saturated and cooled exit
gas stream (e.g., 95+% relative humidity at around 230.degree. F.).
For a system shown in FIG. 1, this flow can be as high as 15-16 pps
(about 40-50% of GT #1 fuel gas flow).
[0055] (4) Precooler cooling water flow to maintain FGC inlet
temperature at a set value (e.g., 125.degree. F.).
[0056] (5) Trim cooler cooling water flow to maintain mixed
fuel-flue gas temperature at a set value (e.g., 450-500.degree.
F.).
[0057] Note that EGR and steam cooling can be accomplished in a
single 1.times.1 GTCC configuration with an advanced HDGT such as
Mitsubishi Heavy Industries or MHI's J class GT. Steam cooled GTs
such as General Electric's H-System.TM. and MHI's G class units
have been operating in the field for more than a decade.
[0058] Among other advantages, the present invention can afford
some or all of: (1) precise, simultaneous control of NOx emissions
and part load at any given site ambient condition with better GTCC
plant heat rate; (2) a lower GTCC MECL (Minimum Emissions Compliant
Load), especially with diffusion combustors; (3) by supplementing
flue gas from HRSG #2 with water injection (for intercooling),
improvement in NOx control capabilities using the moist gas stream
(about 19% H.sub.2O by volume). For a given NOx target, this
reduces the amount of gas to be compressed and reduces parasitic
power consumption; (4) performance fuel gas heating to
450-500.degree. F. via direct contact heat exchange; (5) overnight
parking of the plant at low load by shutting down GT #1. GT #2 can
run at a relatively high simple cycle efficiency and HRSG #2
provides steam for maintaining the ST seals and condenser vacuum as
well as for HRSG #1 sparging to keep the unit warm for the next
startup; and (6) following an overnight or weekend shutdown, GT #1
can start up in a fast start mode by utilizing steam available from
HRSG #2 for HGP component cooling. Without the aforementioned
features enabled by the present invention, this might only have
been possible by an auxiliary (fired) boiler to generate seal and
sparging steam overnight (or over a period of days) and GT cooling
steam during startup. In addition to extra capital cost, this
entails extra fuel consumption and emissions with no megawatt
generation.
[0059] All patent and other documents cited herein are hereby
incorporated by reference in their entireties. Although the
invention has been described in terms of exemplary embodiments, it
is not limited thereto. Rather, the appended claims should be
construed broadly, to include other variants and embodiments of the
invention, which may be made by those skilled in the art without
departing from the scope and range of equivalents of the
invention.
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