Note: Descriptions are shown in the official language in which they were submitted.
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SPECIFICATION
= METHOD FOR OPERATING A GAS TURBINE AND A GAS-TURBINE FOR
IMPLEMENTING THE METHOD
TECHNICAL FIELD
The present invention refers to the field of power plant technology. It
relates to a
method for operating a (stationary) gas turbine, as well as to a gas turbine
for
implementing the method.
PRIOR ART =
A gas turbine with reheating (reheat gas turbine) is known (see, for example,
US
patent application US-A-5,577,378 or "State of the art gas turbines ¨ a brief
update," ABB Review 02/1997, Fig.15, turbine type GT26), which combines
flexible operation with very low flue gas emission readings.
The principle of the known gas turbine with reheating is shown in Fig. 1. The
gas
turbine 11, which is a portion of a combined cycle power plant 10, comprises
two
connected compressors, arranged behind one another on a common shaft 15,
namely a low pressure compressor 13 and a high pressure compressor 14, as well
as two combustors, namely a high pressure combustor 18 and a reheat combustor
19, and the pertinent turbines, namely a high pressure turbine 16 and a low
pressure turbine 17. The shaft 15 drives a generator 12.
The manner in which the unit works is as follows: air is drawn in via an air
inlet 20
from the low pressure compressor 13, and is compressed initially to a level of
intermediate pressure (ca. 20 bar). The high pressure compressor 14 then
further
compresses the air to a level of high pressure (ca.32 bar). Cooling air is
diverted at
both the level of intermediate pressure and at the level of high pressure and
cooled down in pertinent OTC coolers (OTC = Once Through Cooler) 23 and 24
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and conducted further to the combustors 18 and 19 and turbines 16, 17 via
cooling
lines 25 and 26 for cooling purposes. The remaining air from the high pressure
compressor 14 is led to the high pressure combustor 18 and heated there by the
combustion of a fuel, which is introduced via the fuel feedline 21. The
resultant flue
gas is then expanded in the subsequent high pressure turbine 16 to an
intermediate level of pressure, as it performs work. After expansion, the flue
gas is
heated again in the reheat combustor 19 by means of the combustion of a fuel
introduced via fuel feedline 22 before it is expanded in the subsequent low
pressure turbine 17, performing additional work in the process.
The cooling air, which flows through the cooling lines 25, 26, is blown in at
suitable
points of combustors 18, 19 and turbines 16,17, in order to limit the material
temperatures to a reasonable extent. The flue gas that comes from the low
pressure turbine 17 is sent through a heat recovery steam generator (HRSG) 27,
in order to produce steam, which flows through a steam turbine 29 within a
water-
steam circuit, performing additional work there. After flowing through the
heat
recovery steam generator 27, the flue gas is finally released to the outside
through
a flue gas line 28. The OTC coolers 23, 24 are part of the water-steam
circuit;
super-heated steam is produced at their outlets.
As a result of the two combustions in combustors 18, 19, which are dependent
upon one another and follow one another sequentially, a great flexibility in
operation is achieved; the combustion temperatures can be adjusted so that the
maximum degree of effectiveness is achieved within the existing limits. The
sequential combustion system's low flue gas values are the result of the
inherently
low emission values that can be achieved in conjunction with reheating.
On the other hand, combined cycle power plants with single-stage combustion in
the gas turbines are known (see, for example, US patent application US-A-
4,785,622 or US-B2-6,513,317), in which a coal gasifier is integrated, in
order to
provide the requisite fuel for the gas turbine in the form of syngas, which is
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recovered from coal. Such combined cycle power plants are referred to as IGCC
plants
(IGCC ¨ Integrated Gasification Combined Cycle).
SUMMARY OF THE INVENTION
Some embodiments of the present disclosure proceed from the recognition that
by using gas
According to an aspect of the present invention, there is provided a method
for operating a
gas turbine, the method comprising: drawing in and compressing air with the
gas turbine;
conducting compressed air to a combustion chamber; combusting a syngas that is
According to another aspect of the present invention, there is provided a
reheating gas
turbine comprising: compressors for compressing intaken air; a first combustor
and a second
combustor; a first turbine and a second turbine; wherein the first combustor
is in fluid
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gases coming from the first turbine, and is in fluid communication with said
second
turbine so that the resultant hot gases can be expanded in the second turbine;
an air
separation unit having an intake side connected to the compressors, and having
an outlet
side including a nitrogen line for giving off nitrogen that occurs in the
separation and an
oxygen line for giving off oxygen that occurs in the separation; a syngas
production unit
including an outlet in fluid communication with the combustors; wherein the
oxygen
line from the air separation unit outlet side is in fluid communication with
the syngas
production unit; and wherein the nitrogen line from the air separation unit
outlet side
is in fluid communication with the first and second combustors.
Some embodiments of the present disclosure are directed to a method for the
operation
of a gas turbine that works together with a gasification unit for fossil
fuels, especially coal,
which is distinguished by an improved degree of efficiency, which can also be
realized to
particularly good effect using available components, as well to create a gas
turbine for
implementing the method.
In an aspect, in a gas turbine unit that works with syngas, a gas turbine with
reheating
that comprises two combustors and two turbines is used, such that in the first
combustor,
syngas is burned wising compressed air and the resultant hot gases a're
expanded in the
first turbine, and such that in the second combustor, syngas is burned
employing the flue
gases coming from the first turbine and the resultant hot gases are expanded
in the
second turbine.
In an embodiment of the method, at least a portion of the nitrogen that occurs
in
conjunction with the separation of the air is used to dilute the syngas burned
in the
second combustor, such that, in particular, 80-100% of the nitrogen that
occurs in the
separation of the air is used to dilute the syngas that is burned in the
second combustor.
In some embodiments, the nitrogen that occurs in conjunction with the
separation of the
air is preferably blown directly in the second combustor, i.e. without further
compression.
In some embodiments, the remainder of the nitrogen that occurs in conjunction
with the
separation of the air is preferably used to dilute the syngas burned in the
first combustor,
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such that, in particular, the nitrogen provided for the first combustor is
first compressed to
a higher pressure prior to being blown into the combustor.
According to another embodiment of the invention, a portion of the syngas
produced in
the gasification unit is blown into the second combustor without further
compression.
In a further embodiment, a portion of the syngas produced in the gasification
unit is first
compressed to a higher pressure in a compressor and then blown into the first
combustor.
In some embodiments, preferably, the syngas and the nitrogen that is provided
for
dilution are blown into the combustors in concentric arrangement, such that
the nitrogen
jet surrounds the syngas jet after the manner of a mantle and the spraying
occurs
perpendicular to the direction of the compressed air that flows into the
combustors or the
outgoing air from the first turbine, respectively.
In an embodiment of the gas turbine, a compressor for the purpose of
compressing the
nitrogen is provided in the nitrogen line between the outlet of the air
separation unit and
the first combustor.
According to another embodiment, a compressor for the purpose of compressing
the
syngas is provided in the syngas feed line, between the outlet of the unit
that produces
the syngas and the first combustor.
In an embodiment of the process, preferably, fuel nozzles are preferred in the
first and/or
second combustor, through which internally, in concentric arrangement, the
syngas, and
externally, in the form of a surrounding mantle, the nitrogen, flows into the
combustor,
oblique to the direction of flow of the compressed air or outgoing air from
the first turbine.
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BRIEF EXPLANATION OF THE FIGURES
In what follows, the invention is to be explained in greater detail by virtue
of the
embodiment examples in conjunction with the drawings.
5
Fig. 1 shows the simplified schematic of a combined cycle power
plant
with a gas turbine with reheating or sequential combustion
according to the prior art;
Fig. 2 shows the simplified schematic of an IGCC unit with a gas turbine
with reheating or sequential coml?ustion, as it lends itself to the
realization of an embodiment of the invention.
Fig. 3 shows a diagram of the NOx emissions as a function of the
fuel's
nitrogen dilution (ND) for a gas turbine with (curve C) and without
reheating (curve A);
Fig. 4 shows a diagram of the admissible flame temperature range as
a
function of fuel reactivity (FR) for a gas turbine without (curve F)
and with (curve D) reheating or sequential combustion;
Fig. 5 shows a markedly simplified schematic of the interaction of
a gas
turbine with reheating with an air separation and syngas =
production unit, with [due] reference to the requisite level of
pressure;
Fig. 6 shows a diagrammatic representation of the separation of the
mass flows
of syngas and diluted nitrogen to both combustors of the gas turbine with
reheating; and
Fig. 7 shows a simplified representation of the preferred
configuration for
spraying in the syngas and the nitrogen within the context of an
embodiment of the invention.
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DESCRIPTION OF EMBODIMENTS
In Fig. 2, in a markedly simplified schematic, an IGCC unit with a gas turbine
with
re-heating, or sequential combustion, respectively, is shown, as it can be
embodied in exemplary fashion within the context of the invention. The
combined
cycle power plant 30 comprises a gas turbine 11 with a low pressure compressor
=
13, a downstream high pressure compressor 14, a high pressure combustor 18
with a downstream high pressure combustor 18 with a downstream high pressure
turbine 16 and a re-heating combustor 19 with a downstream low pressure
turbine
17. The compressors 13, 14 and the turbines 16, 17 sit on a commonly shared
shaft 15, by which a generator 12 is driven. The combustors 18, 19 are
supplied
with syngas (H2, CO) as fuel via a syngas feed line 31, which is produced by
gasifying coal (coal feeding 33) in a coal gasifier 34 (other fossil fuels can
be
gasified as well). A cooling device 35 for the syngas, a filtering device 36,
and a
CO2 separator 37 with ,a CO2 outlet 38 to release the CO2 that is given off to
the
coal gasifier 34.
Oxygen (02), which is recovered in an air separation unit 32, and is added via
an
oxygen line 32a, is used to gasify coal in the coal gasifier 34. The air
separation
unit 32 receives compressed air from the outlet of the low pressure compressor
13. The nitrogen (N2), which also occurs in the separation, is led via a
nitrogen line
= 32b to various parts of the high pressure combustor 18 and the low
pressure
combustor 19 (see also the diagram in Fig. 6).
For cooling the components of the combustors 18, 19 and turbines 16, 17, which
are exposed to the hot gas, compressed cooling air is drawn off at the outlets
of
both compressors 13 and 14, cooled off in a topped OTC cooler 23 or 24,
respectively, and then led via corresponding cooling lines 25 and 26 to those
points that are to be cooled.
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At the outlet of the low pressure turbine 17, a heat recovery steam generator
27 is
provided, which, together with a connected steam turbine 29, is part of a
water-
steam cycle. The flue gas that escapes from the heat recovery steam generator
27
is released to the outside by way of a flue gas line 28.
The main technical challenges associated with the combustion of syngas in the
combustor of a gas turbine are:
- minimizing gas pressure requirements above the gas pressures that
are
present in the gasification and separation of the air,
- the achievement of low emission levels,
- sufficient distance from the limits of flashbacks and pulsations,
and
- maintaining operational flexibility in the event of changes in the
quality of
the coal gas as well as the possibility of support with other fuels (natural
gas or oil).
In the case of IGCC units, from conception onward, these challenges can be
overcome particularly well by means of a gas turbine with reheating for the
following reasons:
1. The inherent advantage associated with reheating with respect to
NOx can also be transferred to syngas if the combustion
temperatures in both combustors are selected so as to be optimal.
As Fig. 3 shows, taking the NOx curve A as a point of departure for
single stage combustion, by reducing the combustion temperature in
the first combustor in the case of two-stage combustion (curve B) as
a function of the dilution of the syngas SD with nitrogen, a
considerable reduction El of the NOx emission can be achieved,
which is then added to the higher emission in the second stage (E2)
to an overall emission in the case of two-stage combustion (curve C),
which, compared to the single-stage combustion, is still reduced by
the considerable difference E3.
2. The stability of the combustion and the flexibility in the operation of
the gas turbine with re-heating are greater than in the case of a
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comparable gas turbine with single-Stage combustion. The
operational limits, according to Fig. 4, are typically set by the
extinguishing of the flames (limit L2) and the flashback and/or
emission levels (limit L1) as a function of fuel reactivity FR for a
prescribed flame temperature (TF), which leads to a permitted range
of fuel qualities and fuel reactivities. In the gas turbine with single-
stage combustion (curve F in Fig. 4), the limits are quickly reached
on both sides. In the gas turbine with reheating (curve D in Fig. 4),
this operational limit is definitely increased because two combustion
systems render operation in the case of two independent flame
temperatures possible, e.g. with a lower temperature in the first
stage and a higher temperature in the second stage, with slight
disadvantages with respect to NOx.
3. The requirements for the gas pressure can be minimized if the
greatest proportion of the diluting nitrogen (N2) is injected into the
second combustion system (combustor 19), which typically works
with pressures between15 and 20 bar. The optimal selection of
gasification unit, air separation unit, and gas turbine depends upon
the selection of the various technologies. A configuration that is
distinguished by minimized gas compression and thus, minimized
loss of power, is represented schematically in Figs. 5 and 6. It
employs the inherent advantages of sequential combustion.
According to Fig. 5, the nitrogen in the case of the separation of the
air 39 in the air separation unit 32 is led via nitrogen line 32b directly,
on the one hand (without additional compression by means of a
compressor V1) to the second combuster of the gas turbine 11,
whereas the nitrogen that is led to the first combustor is compressed
in the compressor V2. Accordingly, the syngas, which is produced
from coal 40 in the coal gasifier 34 and purified in the filtering device
36, is led via the syngas line 31, on the one hand directly (without
additional compression by means of a compressor V3) to the second
combustor, whereas the nitrogen that was led to the first combustor
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is compressed in the compressor V4. Saving the two compressors
V1 and V3 is symbolized by the crossed-out figures in Fig. 5.
An optimized operation of the unit results, according to Fig. 6, if the
mass flows ml and m2, which are led to the first combustor 18 and
to the second combustor 19, have, in each case, according to the
table from Fig. 6, 40-60% of the syngas and 0-20% of the nitrogen
(mass flow ml) or 60-40% of the syngas and 100-80% of the
nitrogen (mass flow m2). This has the additional advantage of
improved stability of combustion and mixing quality in the mixer of
the second stage of combustion.
A typical nozzle configuration for spraying in the syngas (H2, CO)
and nitrogen (N2) is shown in simplified form in Fig. 7: both gases are
blown in concentrically by means of a fuel nozzle 42, such that the
syngas flows in through a central nozzle 44, whereas the nitrogen is
blown in through an annular nozzle 43 that surrounds the central
nozzle 44 concentrically. In the process, the fuel nozzle 42 is
oriented perpendicular to the direction of the compressed air that
flows into the combustor(s) or of the outgoing air from the first
turbine. As a result of the mantle-like sheathing of the syngas jet with
nitrogen, the syngas is shielded and cooled, and so the spontaneous
ignition by the hot, compressed air or the outgoing air, respectively,
is clearly delayed.
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LIST OF REFERENCE NUMERALS
10,30,40 combined cycle power plant
11 gas turbine
12 generator
13 low pressure compressor
14 high pressure compressor
shaft (gas turbine)
16 high pressure turbine
17 low pressure turbine
18 high pressure combustor
19 reheat combustor
air inlet
21,22 fuel feedline
23,24 OTC cooler
25,26 cooling line
27 heat recovery steam generator
28 flue gas line
29 steam turbine (steam cycle)
31 syngas feed line
32 air separation unit
32a oxygen line
32b nitrogen line
33 coal feeding
34 coal gasifier
35 cooling device
36 filtering device
37 CO2 separator
38 CO2 outlet
39 air
40 coal [also listed above as "combined cycle power plant"]
41 compressed air
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42 = fuel nozzle
43 annular nozzle
44 central nozzle
A,B,C,D,F curve
E1,E2,E3 emission difference (N0x)
FR fuel reactivity
L1,L2 limit
ml ,m2 mass flow
SD syngas dilution
TF1 flame temperature (1st combustor)
V1,..,V4 compressor
