US20110247335A1

US20110247335A1 - Waste heat steam generator and method for improved operation of a waste heat steam generator

Info

Publication number: US20110247335A1
Application number: US13/139,751
Authority: US
Inventors: Erich Schmid; Helmut Stierstorfer
Original assignee: Siemens AG
Current assignee: Siemens AG
Priority date: 2008-12-19
Filing date: 2009-11-05
Publication date: 2011-10-13
Also published as: EP2199547A1; EP2368021B1; CN102257248A; PL2368021T3; CN102257248B; WO2010069671A1; RU2516068C2; RU2011129804A; EP2368021A1

Abstract

A heat recovery steam generator is provided. The heat recovery steam generator includes an exhaust gas inlet for receiving an exhaust gas from a gas turbine. A first superheater is positioned in a flow direction of the exhaust gas. A heating surface is disposed between the exhaust gas inlet and the first superheater. A separator is connected downstream of the heating surface on a secondary side of the heating surface.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application is the US National Stage of International Application No. PCT/EP2009/064663, filed Nov. 5, 2009 and claims the benefit thereof. The International Application claims the benefits of European application No. 08172255.5 EP filed Dec. 19, 2008. All of the applications are incorporated by reference herein in their entirety.

FIELD OF INVENTION

The invention relates to a heat recovery steam generator, in particular in a combined-cycle gas and steam turbine plant, and refers to the utilization of heat at maximum exhaust gas temperatures. The invention further relates to a method for operating a heat recovery steam generator.

BACKGROUND OF INVENTION

In a steam turbine plant comprising a steam turbine and an internal combustion engine, heat from hot exhaust gases of the internal combustion engine can be utilized to operate the steam turbine plant. If the internal combustion engine is a gas turbine, which together with the steam turbine plant accordingly forms a combined-cycle plant (combined gas and steam turbine plant), compressed air is mixed with a gaseous or liquid fuel, for example natural gas or petroleum, and combusted and the pressurized exhaust gases are expanded in the turbine part of the gas turbine, simultaneously performing work in the process. The expanded hot exhaust gas leaving the gas turbine typically still has a temperature of 550° C. to 650° C. In order to utilize the energy contained in this heat, the exhaust gas is supplied to a waste heat recovery steam generator which is disposed downstream at the waste-gas side of the gas turbine system and in which heating surfaces in the form of tubes or tube bundles are disposed. The heating surfaces are in turn connected into a water-steam circuit of the steam turbine plant that comprises at least one, though mostly a plurality of pressure stages. The pressure stages differ from one another in that different pressure levels prevail in the heating surfaces during steam generation.
The flow medium circuit conventionally comprises a plurality of—for example three—pressure stages, each with its own evaporator section. In this case an evaporator section comprises a feedwater preheater (economizer), an evaporator and a superheater. Because of the limited thermal loading capacity of the tube wall materials conventionally used it is necessary to ensure that during operation of a combined-cycle gas and steam turbine plant an upper temperature limit for the components in the heat recovery steam generator that are impinged upon by hot exhaust gas is not exceeded. This applies in particular to the high-pressure and intermediate superheater, which is disposed at the exhaust gas inlet, i.e. in the hottest area of the heat recovery steam generator.
Particularly during part-load operation the gas turbine exhaust gas temperature rises until it reaches the so-called guide vane corner point. Below this IGV corner point the exhaust gas temperature drops, although this is also associated with increased emissions. The highest exhaust gas temperatures (>600° C. at high ambient temperatures or when operating with gas turbine intake air preheating) therefore occur also during startup of the gas turbine, provided that the steam turbine has not yet been started, or during combined-cycle operation in the low-load range (ca. 50% capacity).
Besides the thermal loading of the high-pressure superheater surfaces, during operation of a gas and steam turbine plant, and particularly during ramp-up of the same, attention also has to be paid to the initiation temperature of the steam turbine at a cold or warm start, which at 350-400° C. is relatively low compared to the high gas turbine exhaust gas temperatures.
Once the start operation has been completed and the steam turbine is at operating temperature, it is, however, necessary to limit the steam temperature not just in an upward direction. With a view to improving the efficiency of the plant, the maximum steam temperature is selected in the region of the operating temperature limit of the martensitic steel used. It therefore follows that it is imperative to regulate the temperature relatively precisely (in the minutes range).
In conventional steam power stations (fired and heat recovery steam generators), in order to control the steam temperature and protect temperature-sensitive components at various points of the steam lines injection coolers are employed which lower the temperature of the steam flowing through the line by injecting cool feedwater into a steam line and hence also reduce the temperature of the components through which said cooled steam flows.
However, the concept comprising intermediate and end injection coolers reaches its technical limit at maximum injection rates of 15 to 20% and moreover reduces the plant efficiency during startup and power operation.
Furthermore, injection coolers in the live-steam/intermediate superheating steam line are not accepted or are only reluctantly tolerated by many operators and steam turbine manufacturers because of the perceived risk that water droplets might pass into the steam turbine. Temperature shock problems may moreover occur because of the large temperature differences between injection water and steam temperature when the end injection cooler is used, i.e. the cooler water flows through the injection nozzle that is heated to steam temperature.
Although there is the possibility of using an additional injection cooler, this necessitates longer mixing sections and leads to even more complex regulation means and to the need to dispose the branch leading to the high-pressure diversion (HPD) station further away from the HRSG.
A possible solution is provided by lowering the load of the gas turbine until there is a reduction in the exhaust gas temperature. However, this leads to increased emissions and therefore may result in a restriction of the number of starts once the emission limits are reached.
An undershooting of the minimum steam volume for the steam turbine start may also occur in large steam turbines having two or three associated gas turbines (2×1, 3×1). However, this considerably limits the desired operational flexibility.
Finally, it would be possible to design the material of the affected superheater/intermediate superheater system regions for an extremely high gas turbine exhaust gas temperature, although then material problems may possibly ensue in new gas turbine developments because for example the use of austenitic materials may become necessary.
U.S. Pat. No. 7,174,715 B2 (Armitage et al., Feb. 13, 2007; “Hot to Cold Steam Transformer for Turbine Systems”) discloses a further possible solution. There, a steam transformer is used to condition the steam temperature in a steam turbine, for example during the turbine cold start. For this purpose steam and water are supplied to the steam transformer. As a result of the contact with water the steam cools down and exits the steam transformer through a mist eliminator (demister).
A generic drawback of this system is however that although the steam temperature can be adjusted, the problem of excessively high exhaust gas temperature at the superheater itself is not solved.

SUMMARY OF INVENTION

The object of the present invention is therefore to disclose a heat recovery steam generator in which even at maximum exhaust gas temperatures a mode of operation that is sparing of materials may be achieved.
The object directed to a heat recovery steam generator is achieved according to the invention by means of a heat recovery steam generator comprising an exhaust gas inlet, characterized in that a heating surface is disposed between the exhaust gas inlet and a superheater arranged in a first position in the flow direction of the exhaust gas.
The invention is accordingly based on the concept of inserting a heating surface upstream of the first superheater situated nearest the exhaust gas inlet, which heating surface, where necessary, removes heat from the hot exhaust gas before the exhaust gas reaches the superheater, with the result that thermal overloading of the superheater and/or overheating of the steam in the superheater may be avoided.
The heating surface is advantageously connected on the secondary side at the outlet side to a steam line leading to a high-pressure part of a steam turbine (live steam line).
It is beneficial in this case if a separator is connected downstream of the heating surface on the secondary side in order to prevent water ingress into the live steam line in the event of a malfunction or when dynamic changes in pressure occur. The separator is advantageously an inertial separator with separating flask. Among inertial force separators, the best separation is achieved by centrifugal force separators. In centrifugal force separators, sometimes also known as cyclone separators, the steam, unlike in a centrifuge, is set in rotation by its own flow velocity and a corresponding structural design of the separator (for example, by flowing tangentially into a cylinder). The centrifugal forces acting on the water droplets accelerate the water droplets radially outward, with the result that they are separated from the steam flow. The steam flow itself is guided inward and ducted away.
In an advantageous embodiment variant, water, preferably hot, slightly supercooled water, for example from an economizer, and in particular from a high-pressure economizer, may be fed to the heating surface on the secondary side.
The heating surface is advantageously a once-through evaporator heating surface. In this case the desired throughflow volume of the water/steam flow may be forced by means of a feed pump for targeted adjustment of the desired cooling effect.
In an alternative embodiment variant, the heating surface is connected on the secondary side at the input side to a high-pressure pre-superheater so that the heating surface may advantageously be used also as a high-pressure superheater by deactivating the feed with high-pressure feedwater and injecting high-pressure steam from the high-pressure pre-superheater.
In principle this is also conceivable with reheated steam, such that in a further advantageous embodiment variant the heating surface is connected on the secondary side at the input side to an intermediate superheater.
The first superheater is advantageously a high-pressure superheater. In an advantageous alternative the first superheater is an intermediate superheater.
It is beneficial if the heat recovery steam generator comprises a high-pressure bypass for bypassing the superheater.
It is furthermore beneficial if the heat recovery steam generator comprises an intermediate superheater bypass for bypassing an intermediate superheater.
Both high-pressure bypass and intermediate superheater bypass may namely be used in an advantageous manner for fine regulation of the steam temperature in that high-pressure steam and reheated steam are conveyed past the high-pressure superheater and the intermediate superheater respectively and mixed with the live steam/reheated steam. Alternatively, said fine regulation could also be handled by an injection cooler.
In an advantageous embodiment variant, an inlet header for the heating surface is a tube-in-tube inlet header.
It is advantageous if a combined-cycle gas and steam turbine plant, comprising a gas turbine and a steam turbine, further comprises a heat recovery steam generator according to the invention.
In the inventive method for operating a heat recovery steam generator comprising a first superheater positioned in the flow direction of the exhaust gas, a hot exhaust gas is cooled before it reaches the first superheater.
In this case it is advantageous if the exhaust gas is cooled by hot high-pressure feedwater. The cooling capacity is beneficially adjustable.
It may however also be advantageous if the exhaust gas is cooled by pre-superheater steam.
It is beneficial if the steam produced during cooling of the exhaust gas is mixed with high-pressure steam.
Upon startup of the heat recovery steam generator the partially filled heating surface operated as a once-through evaporator heating surface (known as the Benson principle) is heated by the gas turbine exhaust gas and the water starts to vaporize (water discharge into cyclone with separating flask). Water is backfed from the high-pressure economizer and the once-through evaporator heating surface is operated initially as a natural-circulation evaporator before being selectively temperature-controlled (depending on the target setpoint value, 360° C. for example) by means of backfeed regulation.
As a result of bypassing the superheater (high-pressure steam bypass), after starting of the high-pressure evaporator the live steam temperature needed to start the steam turbine is set. After the steam turbine start, the steam temperature setpoint value is increased and the backfeed of high-pressure economizer water into the once-through evaporator heating surface is reduced. The high-pressure steam bypass takes over the fine regulation of the steam temperature.
Now, only a minimal feed is still needed to cool the once-through evaporator heating surface, the outlet temperature in this case reaching the nominal setpoint value.
If the gas turbine exhaust gas temperature is correspondingly low (for example cold ambient temperatures, no preheating of gas turbine intake air), the feed may even be deactivated and the heating surface impinged upon by steam from the high-pressure pre-superheater in order to raise the high-pressure superheater temperature (efficiency optimization).
During part-load operation of the heat recovery steam generator a distinction is made between two situations: At high ambient temperatures, the once-through evaporator heating surface is operated at minimum feed and adjusted to maximum rated temperature. At low ambient temperatures, the feed may be deactivated and the heating surface changes its function to that of a high-pressure superheater.
When a switch is made back to feeding with high-pressure economizer water, tube-in-tube inlet headers ensure a functionally appropriate mix of steam and economizer water and hence a gentle cooling of the inlet headers to economizer temperature.
Even when the heat recovery steam generator is being powered down, the operation of the heating surface is dependent on the ambient temperature and/or the gas turbine exhaust gas temperature. If the gas turbine exhaust gas temperature falls below a specific value (for example 550° C.), the feeding of the once-through evaporator heating surface is switched off.
By means of the temperature-controlled once-through evaporator heating surface it is easily possible to solve the problems that are associated with intermediate and end injection coolers, such as the risk of droplets and temperature shock.
The efficiency of the plant is increased because hot high-pressure economizer outlet water may be used both during startup and during part-load operation, thereby maximizing steam production.
The steam temperature (high-pressure/intermediate superheating) may also be flexibly adjusted and controlled in the event of a variation in the gas turbine exhaust gas temperature compared to the specification. Furthermore, the material temperature of the heating surfaces and headers located in hotspots may be limited.
By virtue of the large temperature control range a fine adjustment is possible over the entire range (for high-pressure and intermediate superheater temperatures).
It is furthermore possible to simplify the superheater/intermediate superheater design because an intermediate injection is no longer necessary (intermediate header(s) with injection sections, etc.).
The once-through evaporator heating surface is suitable for use in drum- and Benson-type steam generator designs. It is also advantageous for standardization and is accepted for example also on the US market.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention is described in more detail by way of example with reference to the not-to-scale, schematic drawings, in which:

FIG. 1 shows a combined-cycle gas and steam turbine plant having a known heat recovery steam generator,

FIG. 2 shows a combined-cycle gas and steam turbine plant having a further known heat recovery steam generator,

FIG. 3 shows a heat recovery steam generator according to the invention,

FIG. 4 shows an alternative arrangement of the heat recovery steam generator according to the invention and

FIG. 5 shows a tube-in-tube inlet header.

DETAILED DESCRIPTION OF INVENTION

FIG. 1 shows schematically and by way of example a steam turbine plant which is embodied as a combined-cycle gas and steam turbine plant 1 and which comprises a gas turbine 2 as internal combustion engine as well as a steam turbine 3. By means of a shaft 4 a rotor of the gas turbine 2, a rotor of a generator 5 and a rotor of the gas turbine 3 are coupled to one another, wherein the rotor of the steam turbine 3 and the rotor of the generator 5 can be rotationally separated from one another and coupled to one another by way of a coupling 6. The rotors of the generator 5 and the gas turbine 2 are rigidly connected to one another via the shaft 4. An exhaust gas outlet of the gas turbine 2 is connected by way of an exhaust gas line 7 to a heat recovery steam generator 8 which is provided for generating the process steam of the steam turbine 3 from waste heat of the gas turbine 2.
During operation of the combined-cycle gas and steam turbine plant 1, a compressor 9 is driven by the rotating rotor of the gas turbine 2 via the shaft 4, taking in combustion air from the environment and supplying it to a combustion chamber 10. There, the combustion air is mixed with fuel brought from a fuel supply 11 and combusted and the hot, pressurized exhaust gases are supplied to the gas turbine 2, where they are expanded, simultaneously performing work in the process. The hot exhaust gases, still at approx. 550 to 650° C., are then fed through the exhaust gas line 7 to the heat recovery steam generator 8 and flow through this from the exhaust gas inlet 12 to the exhaust gas outlet 13 and pass through a chimney 14 into the environment. On their way through the heat recovery steam generator 8 they supply their heat to a high-pressure superheater 15, then to a high-pressure pre-superheater 16, an intermediate superheater 17, a high-pressure evaporator 18, a high-pressure pre-heater 19, then to an intermediate-pressure superheater 20, an intermediate-pressure evaporator 21, an intermediate-pressure pre-heater 22, then to a low-pressure superheater 23, a low-pressure evaporator 24, and finally to a condensate pre-heater 25.
Steam superheated in the high-pressure superheater 15 is supplied through a steam discharge line 26 to a high-pressure stage 27 of the steam turbine 3, where it expands while simultaneously performing work. By means of the work—in an analogous manner to the work performed in the gas turbine 2—the shaft 4 and hence the generator 5 are set in motion in order to generate electrical energy. The hot steam that has partially expanded in the high-pressure stage 27 is then supplied to the intermediate superheater 17, where it is reheated, and supplied through a discharge line 28 to an intermediate-pressure stage 29 of the steam turbine 3, where it expands, simultaneous performing mechanical work in the process. The steam that has partially expanded there is supplied through an internal feed line to a low-pressure stage 30 of the steam turbine 3, where it expands further while simultaneous releasing mechanical energy.
The expanded steam is condensed in the condenser 31 of the steam turbine 3, and the condensate thus produced is supplied by means of a condensate pump 32 after heating in the condensate preheater 25 directly to a low-pressure stage 33 of the heat recovery steam generator 8 or is supplied—and provided with a corresponding pressure—by means of a feedwater pump 34 to an intermediate-pressure stage 35 or a high-pressure stage 36 of the heat recovery steam generator 8, where the condensate is evaporated. After steam generation and superheating, the steam is fed through the corresponding discharge lines of the heat recovery steam generator 8 back to the steam turbine 3 for expansion and performance of mechanical work.
FIG. 1 further shows an intermediate injection cooler 37 which is connected between high-pressure pre-superheater 16 and high-pressure superheater 15, as well as an end injection cooler 38 which is connected in the flow direction of the steam downstream of the high-pressure superheater 15 for the purpose of regulating the steam temperature.
FIG. 2 schematically shows a combined-cycle gas and steam turbine plant 1 which differs from the system shown in FIG. 1 in that it comprises steam bypasses, namely the high-pressure steam bypass 39, which bypasses the high-pressure superheater 15, and the intermediate superheater steam bypass 40, which bypasses the intermediate superheater. Through control of the valves 41,42 that are associated with these bypasses 39,40 it is possible likewise to adjust the steam temperature in the high-pressure part 36 and in the intermediate superheater part 43.
FIG. 3 schematically shows the heat recovery steam generator 8 according to the invention having an additional heating surface 44 between the exhaust gas inlet 12 of the heat recovery steam generator 8 and the high-pressure superheater 15. The heating surface 44 is supplied with feedwater from the high-pressure economizer 19. A cyclone separator 45 with separating flask is provided at the steam outlet of said heating surface 44 in order to prevent water ingress into the live steam line 26 to which the outlet of the separator 45 is connected in the event of a malfunction or when dynamic pressure changes occur.
FIG. 4 shows an alternative application of the invention in which the heating surface 44 is used as a high-pressure superheater in that the feed from the high-pressure economizer outlet is deactivated and high-pressure steam from the high-pressure pre-superheater 16 is injected. This is in principle also conceivable with reheated steam.
For fine regulation of the steam temperature the high-pressure steam and reheated steam are conveyed past high-pressure superheater 15 and intermediate superheater 17 (superheated and reheated steam bypass respectively) and mixed with the live steam/reheated steam. Alternatively or additionally this fine regulation can also be handled by an injection cooler 51.
In FIGS. 3 and 4, although only a single tube of the heating surface 44 is actually depicted, in reality a plurality of such identically embodied tubes are arranged side by side in the heat recovery steam generator 8 perpendicular to the drawing plane and are connected both to an inlet header and to an outlet header. These tube bundles may be of a single or multilayer construction, depending on the required heat transfer capacity.
FIG. 5 shows an inlet header 47 that is specially embodied in order, when the feeding 50 of the heating surface 44 is switched from steam 49 from the high-pressure pre-superheater 16 back to high-pressure economizer water 48, to guarantee a gentle cooling of the inlet header 47 to economizer temperature by means of a functionally appropriate mix of steam and economizer water. For this purpose the inlet header 47 is constructed in accordance with the tube-in—tube system with concentric heat exchanger elements (cf. DE 37 41 882 C1, GEA Luftkühlergesellschaft Happel GmbH & Co; DOLEZAL RICHARD; Feb. 2, 1989). Feedwater is pumped upward in the central tube 52, is diverted and flows back down between central tube 52 and a second tube 53 surrounding the central tube 52, is diverted once more and flows back up between the second tube 53 and a third tube 54 surrounding the second tube 53 and is supplied to the heating surface 44. Via the surfaces of the second tube 53 and the central tube 52 an exchange of heat with the inflowing feedwater takes place, such that from the inlet into the header 47 to the outlet the feedwater is continuously heated and initially evaporated. This relatively cold steam progressively cools the tubes 53 and 54 until the feedwater that follows then lowers the tube wall temperature to feedwater temperature.

Claims

1.-18. (canceled)

19. A heat recovery steam generator, comprising:

an exhaust gas inlet for receiving an exhaust gas from a gas turbine;

a first superheater positioned in a flow direction of the exhaust gas;

a heating surface disposed between the exhaust gas inlet and the first superheater; and

a separator connected downstream of the heating surface on a secondary side of the heating surface.

20. The heat recovery steam generator as claimed in claim 19, wherein the heating surface is connected on the secondary side at an outlet side to a steam line leading to a high-pressure stage of a steam turbine.

21. The heat recovery steam generator as claimed in claim 19, wherein the separator is an inertial separator.

22. The heat recovery steam generator as claimed in claim 19, wherein water is fed to the secondary side of the heating surface.

23. The heat recovery steam generator as claimed in claim 19, wherein water from an economizer is fed to the secondary side of the heating surface.

24. The heat recovery steam generator as claimed in claim 23, wherein the economizer is a high-pressure economizer.

25. The heat recovery steam generator as claimed in claim 19, wherein the heating surface is a once-through evaporator heating surface.

26. The heat recovery steam generator as claimed in claim 19, wherein the heating surface is connected on the secondary side at an inlet side to a high-pressure pre-superheater.

27. The heat recovery steam generator as claimed in claim 19, wherein the heating surface is connected on the secondary side at an inlet side to an intermediate superheater.

28. The heat recovery steam generator as claimed in claim 19, wherein the first superheater is a high-pressure superheater.

29. The heat recovery steam generator as claimed in claim 26, further comprising a high-pressure steam bypass for bypassing the high-pressure superheater.

30. The heat recovery steam generator as claimed in claim 28, further comprising a high-pressure steam bypass for bypassing the high-pressure superheater.

31. The heat recovery steam generator as claimed in claim 27, further comprising an intermediate superheater steam bypass for bypassing an intermediate superheater.

32. The heat recovery steam generator as claimed in claim 19, further comprising an inlet header for the heating surface, wherein the inlet header is a tube-in-tube inlet header.

33. A combined-cycle gas and steam turbine plant; comprising

a gas turbine; a steam turbine; and

a heat recovery steam generator, comprising:

an exhaust gas inlet for receiving an exhaust gas from the gas turbine;

a first superheater positioned in a flow direction of the exhaust gas;

34. A method for operating a heat recovery steam generator, comprising:

positioning a first superheater in the flow direction of the exhaust gas;

cooling a hot exhaust gas is before it reaches the first superheater; and

separating water that has not evaporated during cooling of the exhaust gas in a cyclone separator with separating flask.

35. The method as claimed in claim 34, wherein the exhaust gas is cooled by hot high-pressure feedwater.

36. The method as claimed in claim 34, wherein the exhaust gas is cooled by pre-superheater steam.

37. The method as claimed in claim 34, further comprising mixing steam produced during cooling of the exhaust gas with high-pressure steam.