Search Images Maps Play YouTube News Gmail Drive More »
Sign in
Screen reader users: click this link for accessible mode. Accessible mode has the same essential features but works better with your reader.

Patents

  1. Advanced Patent Search
Publication numberUS3693347 A
Publication typeGrant
Publication dateSep 26, 1972
Filing dateMay 12, 1971
Priority dateMay 12, 1971
Also published asCA952603A1, DE2222689A1
Publication numberUS 3693347 A, US 3693347A, US-A-3693347, US3693347 A, US3693347A
InventorsWilliam H Day, Paul H Kydd
Original AssigneeGen Electric
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Steam injection in gas turbines having fixed geometry components
US 3693347 A
Abstract
Control means are provided for utilizing maximum tolerable amounts of steam in gas turbines having fixed geometry components under various operating conditions. Optional means include: means for automatically holding a constant cycle pressure ratio under all ambient conditions; temperature sensing control means for automatically adjusting steam injection in both low and high temperature ambients to avoid visible plumes and to avoid acid condensation, respectively; or combined temperature and humidity sensing control means for automatically optimizing steam injection under all conditions of ambient temperature and humidity.
Images(4)
Previous page
Next page
Claims  available in
Description  (OCR text may contain errors)

United States Patent Kydd et al. 51 Sept. 26, 1972 [54] STEAM INJECTION IN GAS TURBINES Primary Examiner-Carlton R. Croyle HAVING FIXED GEOMETRY Assistant Examiner-Warren Olsen COMPONENTS Attorney-Richard R. Brainard, Paul A. Frank, [72] Inventors: Paul a Kydd; William H. Day both Charles T. Watts, Leo l. Malossl, Frank L. Neuhauser,

of Scotia, Oscar B. Waddell and Joseph B. Forman [73] Assignee: General Electric Company 221 Filed: May 12, 1971 [57] ABSTRACT [21] m No; 142,471 Control means are provided for utilizing maximum tolerable amounts of steam in gas turbines having fixed geometry components under various operating kgg g'gg conditions. Optional means include: means for auto- 'L' g matically holding a constant cycle pressure ratio under a 6 all ambient conditions; temperature sensing control means for automatically adjusting steam injection in [56] References Cited both low and high temperature ambients to avoid visible plumes and to avoid acid condensation, respective- UNITED STATES PATENTS ly; or combined temperature and humidity sensing 2,959,005 ll/l960 Zara ..60/39.55 means automatically Plimizing swam 3,353,360 ll/l967 Gorzegno ..150/39.3 J under condilims of ambient temperature 2,678,531 5/1954 Miller ..60/39.05 and hum'dlty- 3,649,469 3/1972 MacBeth ..6()/39.55

FOREIGN PATENTS OR APPLICATIONS 30 Claims, 7 Drawing Figures 614,106 12/1948 Great Britain ..60/39.53

l ,33 ,34 32 I PRESSURE can/Mum a Wl-TiF-r' mawoucsa CIRCUIT saw? STEAM INJECTION IN GAS TURBINES HAVING FIXED GEOMETRY COMPONENTS BACKGROUND OF THE INVENTION DESCRIPTION OF THE PREFERRED EMBODIMENT Although steam injection, per se, of gas turbines has The injection of steam into the combustion chamber been previously employed no consideration appears to of a gas turbine is broadly old as is shown in US. Pat. No. 2,678,53l-Miller and US. Pat. No. 3,353,360- Gorzegno. The operation of gas turbines in the steam injection mode provides greater output, because of the increased mass flow through the turbine and because of the higher specific heat of the turbine working fluid. A higher cycle efficiency also results, because this mass flow is obtained without the expenditure of additional compressor power, and the steam for the steam injection can be generated utilizing heat losses or exhaust heat which otherwise is not effectively utilized.

SUMMARY OF THE INVENTION Control means are provided for utilizing the maximum amounts of steam that can be tolerated in the operation of gas turbines having fixed geometry components under various operating conditions. Optional means are provided as follows: means for automatically holding a constant cycle pressure ratio (compressor discharge pressure/ambient pressure) under all ambient conditions; temperature sensing control means for automatically adjusting steam injection in both low and high temperature ambients to avoid visible plumes and to avoid acid condensation, respectively; or combined temperature and humidity sensing control means for automatically optimizing steam injection under all conditions of ambient temperature and humidity.

BRIEF DESCRIPTION OF THE DRAWING The exact nature of this invention as well as objects and advantages thereof will be readily apparent from consideration of the following specification relating to the annexed drawing in which:

FIG. 1 is a schematic representation of one embodiment of means according to this invention for automatically controlling the extent of steam injection employed in a fixed geometry continuous flow gas turbine;

FIG. 2 shows a second embodiment of the control voltage generator shown in FIG. 1 including ambient temperature as a control parameter;

FIG. 3 is another modification of the control voltage generator shown in FIG. 1 including both ambient temperature and ambient humidity as control parameters;

FIGS. 4 and 5 considered together constitute a gas turbine performance map setting forth output and thermal efficiency as a function of ambient temperature at a series of turbine inlet temperatures;

FIG. 6 is a schematic representation of an automatically controlled steam injection system according to this invention wherein in addition to the steam injection means of FIG. 1 steam is also generated from the heat in the coolant stream of a liquid cooled turbine and from the liner of the combustor and FIG. 7 is a schematic representation of a system in which steam is generated at a substantially fixed rate and a control voltage generator according to this invention is used to adjust the admission of steam to the combustor.

have been given to the elimination of problems encountered in the use of steam injection. These problems include the emission of visible exhaust plumes at low ambient temperatures and the occurrence of sulfuric acid condensation in the system under high ambient/low stack temperature conditions. The emission of visible plumes and/or exhausts containing droplets of acid are unacceptable in view of the increasing concern for the quality of the environment. Further, the corrosion caused in the gas turbine exhaust system by sulfuric acid generation must be avoided. Control over the steam injection rate insuring an ecologically acceptable stack exhaust is highly desirable for environmental pollution considerations, of course, however, it has also been found that this control capability can still further improve the operation of gas turbines using steam injection.

Investigations during the development of the instant invention have shown that steam injection reduces the emission of nitric oxide by diluting the combustion air and by reducing the maximum flame temperature. Reduction of flame temperature is important, because the bulk of the nitric oxide is produced at temperatures in excess of about 3,400F.

In the steam injection process high-pressure steam can be used to atomize heavy fuel oil and eliminate the cost and the power consumption of the atomizing air booster compressor. Atomization energy for improved combustion is virtually unlimited with the use of heat recovery steam as the atomizing medium. Additional advantages also accrue in that by using high-pressure steam as the atomizing medium the problem of forma tion of deposits in the turbine and in the heat recovery boiler is reduced. Further, by concentrating the steam flow in the primary zone of the combustor the nitric oxide emission can be even more effectively reduced.

It has also been shown during the aforementioned investigations that even though visible plume-free operation of gas turbines should be possible at ambient temperatures above about F when using very substantial steam flows, the problem of the condensation of sulfuric acid in the stack (whereupon this objectionable corrosive condensate is present in the stack exhaust) still remains. Further, the generation of visible plumes at ambient temperatures below 75F is still a problem. Both of these troublesome conditions can be eliminated by the practice of at least one of the several options presented in the instant invention.

FIG. 1 schematically represents a gas turbine 10 having fixed geometry components; compressor 11, combustor l2 and turbine 13. Gas turbine 10 has been provided with steam injection means and controls therefor in accordance with the instant invention.

The steam injection means comprises a steam separator 14 [which may for example be of the drum variety], conduit 16 carrying a hot water/steam mixture to steam separator 14, conduit 17, which conducts steam from steam separator 14 to the combustor 12, conduit 18 which removes liquid water to the feedwater pump 19, conduit 20 which conducts water to boiler 21, inlet water conduit 22 for water makeup and valved blowldown line 23. A flash tank and pressure reducing valve combination as is shown in the aforementioned Gorzegno patent (incorporated by reference) may be substituted for steam separator 14.

During operation in the steam injection mode compressor 11 takes in atmospheric air and forces it under substantial superatmospheric pressure into combustor 12. Fuel is supplied to combustor 12 through fuel inlet 24 and steam is injected into combustor 12 via line 17. Either high-pressure air or the steam (or suitable mixtures thereof) may be employed to atomize the fuel in combustor 12. Combustion of the fuel in combustor 12 produces hot gases, which pass through turbine 13, where expansion of the hot gases occurs with the generation of mechanical energy part of which drives compressor 12 via shaft 26 and part of which is available to drive a load via shaft 27.

Control voltage generator 31 consists of the preset voltage source 32, pressure transducer 33 and comparator circuit 34. These components are electrically connected as shown. When operating, voltage source 32 continuously applies a fixed biasing voltage E to comparator circuit 34 and pressure transducer 33 continuously applies voltage E, to comparator circuit 34, E being a voltage that is proportional to the compressor discharge pressure applied to pressure transducer 33 via conduit 36. Comparator circuit 34 is adjusted so that for a voltage Ep reflecting a compressor discharge pressure equal to the selected operating value of cycle pressure ratio selected as described hereinabove, the bias voltage E is just compensated.

In the event of a change in the compressor discharge pressure, voltage E will not be equal to bias voltage E and the voltage error is the control voltage (E,;) that is thereby generated (and amplified, if required) is supplied to by-pass unit 37 (with motorized actuator 37a), e.g., a damper actuator (as manufactured by the General Electric Company, Instrument Department, Lynn, Mass), so as to change the position of baffle 37b and thereby modify the amount of exhaust gas passing through boiler 21 to reduce and then eliminate the error. Thus, if voltage E, is temporarily greater than bias voltage E a negative control voltage E; is generated resetting bypass actuator 37a to decrease the amount of exhaust gas from turbine 13 passing through line 38, bypass unit 37, line 38a and boiler 21. This change results in a decrease in the amount of steam generated in boiler 21 and separated in steam separator 14 thereby decreasing the steam input to combustor 12. If the reverse situation occurs (E, is less than E a positive control voltage E results and bypass actuator 37a is readjusted so as to increase the exhaust flow through boiler 21 and decrease the amount of exhaust passing through the exhaust conduit 39 and mixer 40 to the stack. The changes in steam flow so accomplished will reduce and eliminate control voltage E changing the pressure ratio across compressor 12 by changing the amount of mass flow occurring at fixed temperature through the fixed geometry turbine. If desired, some of the injected steam is introduced into the head end of the combustor and the balance of the input is introduced therein downstream of the head.

Valve in steam line 17 is controlled in the conventional manner (as by sensing the rotational speed of shaft 27) to compensate for large increases or decreases in gas turbine load. Valve 25 may be a throttling/shut-off type valve or a bypass valve.

There are at least two types of situations in which the automatic elimination of visible exhaust plume and exhaust system corrosion must be accomplished at some turbine inlet temperature lower than the temperature at which steam injection which maintains constant pressure ratio will do so automatically. In such situations the control voltage generator device 31 will not provide sufficiently sophisticated control. Either of the control voltage generators shown in FIGS. 2 and 3 may then be employed to effect control such that the maximum amount of steam is generated (and injected) as required for maximum output and thermal efficiency over the preselected range of ambient temperatures. Examples of the aforementioned types of situations are as follows:

a. when it is desired to operate the machine at a turbine inlet temperature below the maximum turbine inlet temperature thereof (although such operation is within its capability) in order to achieve reduced power output but yet operate in this regime at maximum steam flow and efficiency and b. when the compressor/turbine combination is such that the turbine cannot tolerate as high an inlet temperature as is necessary for the maintenance by steam injection of the maximum pressure ratio over the full preselected range of ambient temperatures.

The device of FIG. 2 supplies a voltage to automatically control steam generation as a function of ambient temperature while the device shown in FIG. 3 supplies a voltage to automatically control steam generation as a function of both the ambient temperature and ambient relative humidity (RH). All components shown in connection with all the control means disclosed herein are commercially available items.

The device 41 shown in FIG. 2 is interchangeable with control voltage generator 31 shown in FIG. 1. Pressure transducer 42 is hydraulically connected via line 36 to the compressor discharge. Voltage E having a value proportional to the compressor discharge pressure is supplied to comparator circuit 43 as described hereinabove. Temperature sensor 44 (e.g., a thermocouple or temperature transmitter such as GE/M AC type 550 manufactured by the General Electric Company, Instrument Department, Lynn, Mass.) is located at or near the compressor inlet emitting a voltage E reflecting the ambient temperature conditions. Temperature sensor 44 is electrically connected to function generator 46 (e.g., GE/MAC type 566 function generator manufactured by the General Electric Company, Instrument Department, Lynn, Mass.) as shown so as to apply voltage E thereto. In function generator 46 (set for a I00 percent relative humidity condition), a bias voltage E is generated as a function of voltage E and, as a result, reflects the effect of any ambient temperature in the preselected range at I00 percent RH. Voltages E and Ep are applied to comparator circuit 43 in the manner described hereinabove for comparator circuit 34. The value of the voltage error (control voltage E if any, determines the setting of motorized bypass unit 37 in the same manner as described hereinabove.

Thus, should the ambient temperature decrease below the point at which a constant pressure ratio can be maintained by steam injection without visible plume, there will be automatic compensation of the rate of steam injection, because the electrical control signal B; will automatically relate to the selected compressor discharge pressure compensated for low ambients. Thus, control voltage E (via bypass actuator 370) will adjust the rate of steam injection to com-' bustor 12 as required to avoid visible plumes in the exhaust. Similarly, should the ambient temperature increase above the point at which a constant pressure ratio can be maintained by steam injection without forming acid condensate in the exhaust, control voltage E; will automatically properly adjust the rate of steam injection to combustor 12 to eliminate the acid condition. This mode of operation will allow satisfactory performance at all ambient relative humidities, but must sacrifice the opportunity to add more steam at ambient humidities lower than I00 percent RH.

The control voltage generator 51 includes pressure transducer 52, the electrical output (voltage Ep) of which passes to comparator circuit 53 as described hereinabove and the electrical signal E, is compared therein to biasing signal E which latter voltage factors into the automatic control function the parameters of ambient temperature and ambient humidity. Both a temperature sensor and a humidity sensor (e.g., of the surface ion exchange type as manufactured by the Amlab Company of Essex, Conn., used in a bridge circuit with thermistor compensation for temperature effects) are located at or near the compressor inlet and these sensors respectively emit electrical signals E and E The humidity sensor 54 is adjusted so that at 100 percent RH the output voltage E is zero and at zero relative humidity E is one unit. Temperature sensor 55 is electrically connected to each of function generators 56 and 57. Function generator 56 emits voltage E as some function of E (and therefore as a function of the ambient temperature) at 100 percent RH. Function generator 56 is electrically connected to summing junction 58,which in turn is electrically connected to comparator circuit 53.

The electrical signal E impressed on function generator 57 generates the voltage designated as AE This electrical signal (voltage AE reflects any requisite correction voltage for the actual ambient temperature at a relative humidity of zero or, in effect is indicative of the rate of steam injection that should be employed under these conditions. Voltage A5,, is then further modified (as described hereinbelow) in interpolation circuit 59 (e.g., voltage multiplier, type 5648 manufactured by General Electric Company, instrument Department, Lynn, Mass.) to reflect the actual ambient humidity sensed by humidity sensor 54. Voltage E emitted by humidity sensor 54 reflects the actual ambient humidity and is indicative of the fraction of voltage AE that can form part of the bias voltage to be applied to comparator circuit 53.

As shown, both voltage E and voltage AE are introduced to interpolation circuit 59. The interpolation circuit 59 electrically multiplies voltage AE by voltage E and the product thereof (voltage AE reflects the incremental rate of steam injection that can be tolerated at the ambient temperature and ambient relative humidity over the rate of steam injection permissible for the ambient temperature/100 percent RH condition. Interpolation circuit 59 is electrically connected to summing junction 58 to which the electrical signals E (representing rate of steam injection for the ambient temperature at percent RH) and M5 (representing the increment of added rate of steam injection for ambient humidity) are introduced. ln summing junction 58, E and A5 are added to produce the net biasing voltage E impressed upon comparator circuit 53. Any resulting error signal E; from comparator circuit 53 controls the setting of actuator 37a in the same manner described hereinabove thereby providing automatically optimized operation at all ambient temperatures (in the preselected range) and all ambient relative humidities.

Although the control devices illustrated herein are electrical in nature, this invention is intended to encompass hydraulic, pneumatic and mechanical analogs of these electrical devices. In each instance, it is required to produce a signal quantitatively related to the pressure ratio and interrelate a bias signal therewith. The bias signal may have a constant value or may be variable either as a function of ambient temperature or as a function of both ambient temperature and ambient humidity.

Any one of the three optional control voltage generators described hereinabove may be utilized for controlling the steam injection into any given gas turbine. The choice of which one is to be used will be determined by the characteristics of the gas turbine in question, the range of ambient temperature and rela' tive humidity over which the machine must operate and whether the power output and efficiency are to be optimized with regard to relative humidity.

The characteristics of the gas turbine which are important are the compressor map (pressure ratio versus air flow at various speeds), which defines the stall or pulsation limit as a function of speed, and the first stage turbine nozzle area. The turbine nozzle area must be large enough that the compressor does not stall at maximum turbine inlet temperature and minimum ambient air temperature under which conditions the air flow and pressure ratio of the compressor are high due to the high inlet air density. Consequently at higher ambient temperatures additional mass flow can be accepted by the turbine without stalling the compressor.

The first step in selecting a control voltage generator from the options disclosed herein for a given gas turbine is to choose a turbine inlet temperature and steam flow which provides the desired balance between power output and efiiciency at the design point. High turbine inlet temperatures provide maximum output (HQ 4). Lower turbine inlet temperatures and higher steam flow produce a higher thermal efficiency (FIG. 5) down to the point at which the exhaust temperature is too low to generate the required amount of steam or at which the decline in available energy due to reduced turbine inlet temperature is no longer offset by the increase in available energy from the permissible in crease in steam addition. The above-noted combination of turbine inlet temperature and steam flow will be chosen to increase the pressure ratio to the maximum that the compressor can deliver with an adequate stall margin.

The next step in selecting the control system is to investigate the performance of the gas turbine over the intended range of ambient temperature. The objective is to maintain optimum performance over as wide a range of ambient conditions as are to be encountered. This is most easily accomplished by holding turbine inlet temperature constant via the conventional exhaust temperature measurement and fuel control system and holding pressure ratio constant at its maximum value by controlling the rate of steam injection. It may be that for the given gas turbine components and turbine inlet temperature constant pressure ratio operation can be achieved over the entire range of expected ambient temperature. In this case control voltage generator 31 will suffice.

If at low ambient temperatures and 100 percent RH it is found either that the exhaust moisture content is such that a visible plume forms, or that at high ambient temperatures and 100 percent RH,acid condensation occurs due to excessive steam flow and correspondingly low stack temperature, it will be necessary to restrict the steam flow into the combustor at low temperatures, at high temperatures or both. This restriction of steam flow, which will reduce the pressure ratio and the performance of the gas turbine at extreme ambient conditions can be accomplished with control voltage generator 41.

If it is desired to take advantage of the fact that low ambient relative humidity will reduce the tendency to generate an exhaust plume or stack condensation, one can extend the region of maximum steam flow and performance under low relative humidity conditions by using control voltage generator 51.

In all cases it is desired to achieve the maximum steam flow permitted by the boundaries imposed by exhaust plume formation, compressor stall, and acid condensation, at the chosen turbine inlet temperature. Higher turbine inlet temperatures widen the range of ambient temperature over which operation at constant maximum pressure ratio is possible. The operating boundaries for a representative gas turbine at different turbine inlet temperatures are shown in H65. 4 and 5. Thus, for operation at each of the turbine inlet temperatures shown, the compressor stall boundary lies between letters a and b; the exhaust plume boundary lies to the low ambient temperature side of letter a and the acid condensation boundary lies to the high am bient temperature side of letter b. For operation between letters a and b the pressure ratio is constant. This map further illustrates the substantial change in thermal efficiency and output between operation in the steam injection mode and operation without steam injection.

The generation of the data required to prepare a turbine performance map such as FIGS. 4 and 5 (considered together) requires a considerable amount of cut-and-try calculating and is, therefore, most effectively accomplished by the use of a computer, e.g., time-sharing. The development of a suitable computer program would employ steps as follows:

a. tentative selection of a range of turbine inlet temperatures providing a desired balance between thermal efficiency and power output for the gas turbine,

b. selection from the compressor map of a range of operating pressure ratios for the gas turbine along the I00 percent speed curve; the highest pressure ratio being that pressure ratio which the compressor can deliver without stalling and the lowest pressure ratio being the pressure ratio for the non-steam injected condition at lowest ambient temperature,

c. selection of an operating range of ambient temperatures,

d. calculation of the range of operating turbine inlet temperatures to be employed using known relationships of gas properties (at different temperatures and steam content) and turbine efficiency (as a function of pressure ratio, turbine inlet temperature, steam content and fuel content),

c. selection of a range for the amount of steam to be injected (i.e., rates of steam injection) into the gas,

f. calculation of a map of the efficiency of the turbine alone as a function of the parameters in the three selected ranges (pressure ratio, turbine inlet temperature and steam injection),

g. selection of some value of turbine inlet temperature from the calculated temperature range,

h. selection of an ambient temperature and a relative humidity of either zero or percent,

i. calculation of the compressor efficiency for the selected ambient conditions to determine the maximum pressure ratio available from the compressor,

j. calculation of the amount of steam and fuel flow required to create this maximum pressure ratio at the selected turbine inlet temperature,

It. determination of the efficiency of the turbine itself from the turbine performance map for the selected turbine inlet temperature, maximum pressure ratio and gas properties,

1. calculation of the turbine exhaust temperature (accounting for the effects of cooling and diluting of the gas flow),

m. calculation of the stack temperature considering any heat removal from the exhaust gas and, knowing the stack temperature, determining whether stack corrosion (acid condensation) will occur, and

n. determination of whether visible plume will be generated under the selected operating conditions at the selected ambient temperature and relative humidity by calculating the relative humidity of successive dilutions of stack effluent with the ambient air.

If it be determined that either an acid condition or visible plume would occur, the amount of steam being injected is too great. In such case, the procedure will have to be repeated using a smaller steam flow and considering the changes (lower pressure ratio) that accompany the reduced steam injection.

If neither acid condensation nor visible plume occur, the aforementioned steps are repeated using a different set of ambient conditions. When a sufficiently large number of sets of ambient conditions have been considered (e.g., at temperature increments of about 20F) one curve of gas turbine thermal efficiency and output will be generated for the single selected turbine inlet temperature as described hereinabove. Thereafter, the procedure is repeated until a map of gas turbine thermal efficiency and output referred to hereinabove (FIGS. 4 and 5 has been prepared for different turbine inlet temperatures (at increments of about 100F). This map provides the option of selecting at will a turbine inlet temperature for optimizing the combination of gas turbine thermal efficiency and gas turbine output (consistent with machine capabilities). Having determined this map, the method described hereinabove for the determination of the several options may be carried out.

If the gas turbine is one that may be operated at less than 100 percent speed a tachometer with a signal output proportional to speed may be introduced to sense the compressor speed and adjust the sensing of the pressure ratio (described hereinbelow) to reflect changes in speed. With known gas turbine construction, the selected ambient temperature range may be as narrow as about 60F or as wide as at least llF depending upon the selected turbine inlet temperature. The higher the turbine inlet temperature, the greater the available ambient temperature range. By way of example, in a General Electric M87000 gas turbine at peak reserve turbine inlet temperature the operating ambient temperature range available, which is free of visible plume or acid condensation in the exhaust, is 1 F (from 0 to 1 10F) at 14.17 psia inlet.

The unexpected aspect of this invention is that having made the aforementioned determinations, the rate (e.g., pounds of steam/hour) of injection of steam remains the only control parameter that is required to simultaneously achieve:

a. the maximum power and efficiency of which the machine is capable in the selected operating range of ambient temperature,

b. freedom from visible plume and c. freedom from the formation of acid condensation.

This invention, thus, provides optional means that enable control of the steam injection rate. These devices vary in their capabilities for accommodating the extent of ambient temperature range, when the pressure ratio is not held constant. In the simplest arrangement (control signal generator device 31) the selected pressure ratio must be held constant and the turbine is operated at the constant selected turbine inlet temperature.

Increased efficiency can be obtained by utilizing superheated steam with a penalty of a slightly higher rate of production of nitric oxide. Still further increases in specific output and efficiency can be achieved by increasing the turbine inlet temperature. This is made possible by utilizing internal cooling. Arrangements for liquid cooling are described in U.S. Pat. Nos. 3,446,48 l Kydd and 3,446,482l(ydd. Internal cooling, of course, results in heat losses from the gas stream. However, by using this lost heat to generate steam for injection into the gas turbine in addition to that generated from the turbine exhaust, approximately 70 percent of the performance decrease due to the heat losses can be recovered.

The liquid-cooled turbine parts actually function as a boiler in the cooling sequence. The liquid coolant may either be circulated in a fully closed circuit or, in the case of water as the coolant, in an open circuit from which the steam that is generated may be withdrawn and replaced with make-up water. The former arrangement has the advantage of minimizing contaminant content. Such is the arrangement shown in FIG. 6.

Gas turbine 60 comprises compressor 61, combustor 62 and liquid-cooled turbine 63. In addition to the steam injection means and control means therefor shown in FIGS. 1-3 the liquid coolant for turbine 63 and liquid coolant for com bustor 62 are used as sources of steam generation. The rate of steam generation from these added sources is fixed by the amount of cooling required and is substantially constant. Although the rate of steam generation (and steam injection) is not subject to the control means for the exhaust-generated steam, this does not pose a problem, because the turbine inlet temperature for a liquid-cooled turbine may be set sufficiently high to adequately accommodate the maximum rate of steam generation from the liquid coolant for turbine 63 and from the cooling of the liner of combustor 62 without visible plume or acid condensate formation.

As in the arrangement shown in FIG. 1, the flow bypass 64 receives exhaust gas from turbine 63 via line 66. Motorized actuator 64a receives control voltage E; from control voltage generator 67 electrically connected thereto and fixes the position of damper 64b in response to voltage 5;. The position of damper 64b determines what proportion of the exhaust gas passes through bypass unit 64 to boiler 68 via line 66a and what proportion of the exhaust gas passes through bypass unit 64 to mixer 69 via line 71. Control voltage generator 67 may be any of the options 31, 41 or 51 described hereinabove.

Thus, water circulated by pump 72 through line 73 passes through combustor liner 74, heat exchanger 76 and boiler 68. Steam generation may occur in heat exchanger 76 and liner 74 and will always occur in boiler 68 depending on the setting of damper 64b. The steam/water mixture proceeds to steam separator 77 wherein liquid and steam are separated, the liquid passing via line 78 to feed pump 72. Valved blow-down line 79 connected to conduit 78 is used to remove contaminating material.

Steam from steam separator 77 passes to combustor 62 via line 81. Valve 82 in steam line 81 is controlled in the conventional manner to compensate for large increases or decreases in gas turbine load. Fuel is supplied to combustor 62 via pipe 83 and compressed air flows to combustor 62 from compressor 61 to burn the fuel and generate hot gases, which pass to liquid-cooled turbine 63.

In alternate construction (not shown) instead of employing a fully closed circuit for the turbine liquid coolant and passing the water flow in line 73 through heat exchanger 74, the turbine cooling circuit would be made part of the steam injection circuit.

If desired, the exhaust of the turbine may be used in part or in whole to generate steam at a substantially constant rate in which case the adjusting means would be disposed between the steam generating means and the combustor with which it is in flow communication. The control voltage generator options of this invention would then be used to control the admission of steam to the combustor, the steam not injected into combustor 62 being diverted to other uses, such as process steam or space heating. Such an arrangement is shown in FIG. 7 in which elements the same as those in FIG. 1 have like numerals. Flow splitter 91 with an adjustable baffle is connected between exhaust lines 38 and 38a. The baffle is positioned so that the amount of exhaust gas passing through boiler 21 is sufficient to generate steam at the maximum useable rate. Control voltage generator 92 would be a modified version of options 31, 41, 51 described hereinabove and controls the admission of steam to combustor 12 by adjusting the setting of bypass unit 93 in which baffle 93b is positioned by motor actuator 93a. Unused steam is conducted to an alternate use via pipe 94. if too much steam is being generated for the combined demands of steam injection and the alternate use, the baffle in flow splitter 91 is reset.

The proper setting of flow splitter 91 will, therefore, depend on the requirements for injection steam and for the alternate use and the amount of steam generated in excess of that required for steam injection will affect the stack gas temperature. If the stack gas temperature is reduced to too low a level, the amount of steam that may be injected at low and at high ambient temperatures without the formation of visible plume or acid .condensate will be reduced. A control signal derived from stack gas temperature sensor 96 should, therefore, be used to generate an additional signal to control voltage generator 92 contributing to bias voltage E in the same manner as humidity sensor 54 and interpolation circuit 59 contribute to signal E in control voltage generator 51.

As an alternate to this modification, the stack gas temperature can be raised and additional steam can be generated by the use of a supplemental burner (not shown), that would be located between flow splitter 91 and boiler 21.

Conditions may be encountered in which it is preferred to use a source of steam, which employs some heat energy source for the conversion of water to steam other than the turbine exhaust or coolant streams. in such instances the source of steam may be placed in flow communication with the combustor with a control voltage generator of this invention being used either to adjust the rate at which heat energy is provided for the steam generating function (as in FIGS. 1 and 6) or to adjust the admission of steam to the combustor (as in FIG. 7).

By utilizing the arrangements of the instant invention for automatically controlling steam injection, very significant improvements in performance resulting from optimized steam injection may be achieved in varying degrees in conventional gas turbines having fixed geometry components depending upon which option is selected.

The control devices of this invention may be incorporated either into existing machines or into new machines as described herein.

What we claim as new and desire to secure by Letters Patent of the United States is:

1. In a gas turbine power plant wherein the turbine is mechanically connected to and drives a compressor; said compressor supplies compressed air to a combustor in flow communication therewith; steam injecting means including steam generating means is in flow communication with said combustor and generates and supplies steam thereto; means in flow communication with said combustor supplies fuel thereto for combustion thereof with air in said combustor for the generation of hot gases. and said combustor supplies the hot gases generated therein to said turbine being in flow communication therewith, the combination with said steam generating means of means to automatically control the generation of steam for admission to said combustor, said control means comprising:

a. means in flow communication with said compressor for generating a control signal and b. means connected to said control signal generating means and responsive to said control signal for adjusting the rate of heat energy input to said steam generating means.

2. The combination of claim 1 wherein said steam generating means is in flow communication with the exhaust system of said turbine and said adjusting means determines the flow of exhaust gas thereto.

3. The combination of claim I wherein said steam generating means comprises a first steam generator in flow communication with the exhaust system of said turbine and a second steam generator in series with said first steam generator, said first steam generator alone having the exhaust gas input thereto adjustable by said adjusting means.

4. The combination of claim 1 wherein the means for generating a control signal comprises:

a. electrical signal comparing means having first and second inputs and having an output, said output being electrically connected to said adjusting means,

. means electrically connected to said first input of said comparing means and in flow communication with the compressor discharge for sensing the compressor discharge pressure and generating a pressure-response signal quantitatively related thereto and c. means electrically connected to said second input of said comparing means for applying a bias signal thereto, said comparing means supplying a control signal to said adjusting means via said output when the relationship between said bias signal and said pressure-response signal deviates from some predetermined value.

5. The combination of claim 4 wherein said means for applying a bias signal is a fixed voltage source.

6. The combination of claim 4 wherein said means for applying a bias signal includes a voltage generator and a temperature sensor having an electrical signal output quantitatively related to the temperature sensed, said temperature sensor being located adjacent the inlet to said compressor and being electrically connected to said voltage generator, said voltage generator being electrically connected to said second input and the bias signal generated thereby being quantitatively related to the signal from said temperature sensor.

7. The combination of claim 4 wherein the means for applying a bias signal includes a temperature sensor having an electrical signal output quantitatively related to the temperature sensed; first and second voltage generators electrically connected at their respective inputs to said temperature sensor; a humidity sensor hav ing an electrical signal output quantitatively related to the relative humidity sensed; a voltage multiplier having separate inputs electrically connected to the outputs of said second voltage generator and said humidity sensor, respectively; and the outputs of said first voltage generator and said voltage multiplier being electrically connected to a summing junction, the bias signal output of said summing junction being electrically connected to said comparing means and said temperature sensor and said humidity sensor being located adjacent the inlet to said compressor.

8. The combination of claim 4 wherein the means for sensing and generating a pressure-response signal is a pressure transducer.

9. The combination of claim 1 wherein said adjusting means is a flow bypass having powered actuating means, said flow bypass being in flow communication with said steam generating means.

10. The combination of claim 2 wherein said adjusting means is a flow bypass having powered actuating means, said flow bypass being in flow communication with the outlet of said turbine, with said steam generating means and with mixing means located downstream in the turbine exhaust system.

11. In a gas turbine power plant wherein the turbine is mechanically connected to and drives a compressor; said compressor supplies compressed air to a combustor in flow communication therewith; steam injecting means including steam generating means is in flow communication with said combustor and generates and supplies steam thereto; means in flow communication with said combustor supplies fuel thereto for combustion thereof with air in said combustor for the generation of hot gases, and said combustor supplies the hot gases generated therein to said turbine being in flow communication therewith, the combination with said steam generating means of means to automatically control steam flow to said combustor, said control means comprising:

a. means in flow communication with said compressor for generating a control signal and b. means for adjusting the admission of steam to said combustor, said adjusting means being in flow communication with both said steam injecting means and said combustor and being automatically responsive to said control signal.

12. The combination of claim 11 wherein said steam generating means is in flow communication with the exhaust system of said turbine.

13. The combination of claim 11 wherein the means for generating a control signal comprises:

a. electrical signal comparing means having first and second inputs and having an output, said output being electrically connected to said adjusting means,

b. means electrically connected to said first input of said comparing means and in flow communication with the compressor discharge for sensing the compressor discharge pressure and generating a pressure-response signal quantitatively related thereto and c. means electrically connected to said second input of said comparing means for applying a bias signal thereto, said comparing means supplying a control signal to said adjusting means via said output when the relationship between said bias signal and said pressure-response signal deviates from some predetermined value.

14. The combination of claim 13 wherein said means for applying a bias signal is a fixed voltage source.

15. The combination of claim 13 wherein said means for applying a control bias signal includes a voltage generator and a temperature sensor having an electrical signal output quantitatively related to the temperature sensed, said temperature sensor being located adjacent the inlet to said compressor and being electrically connected to said voltage generator, said voltage generator being electrically connected to said second input and the bias signal generated thereby being quantitatively related to the signal from said temperature sensor.

16. The combination of claim 13 wherein the means for applying a bias signal includes a temperature sensor having an electrical signal output quantitatively related to the temperature sensed; first and second voltage generators electrically connected at their respective inputs to said temperature sensor; a humidity sensor having an electrical signal output quantitatively related to the relative humidity sensed, a voltage multiplier hav ing separate inputs electrically connected to the outputs of said second voltage generator and said humidity sensor, respectively; and the outputs of said first voltage generator and said voltage multiplier being electrically connected to a summing junction, the output of said summing junction being electrically connected to said comparing means and said temperature sensor and said humidity sensor being located adjacent the inlet to said compressor.

17. The combination of claim 13 wherein the means for sensing and generating a pressure-response signal is a pressure transducer.

18. The combination of claim 11 wherein said adjusting means is a flow by-pass having powered actuating means.

19. In a gas turbine power plant wherein a liquidcooled turbine is mechanically connected to and drives a compressor; said compressor supplies compressed air to a combustor in flow communication therewith; steam injecting means including steam generating means is in flow communication with said combustor and supplies steam thereto; means in flow communication with said combustor supplies fuel thereto for combustion thereof with air in said combustor for the generation of hot gases and said combustor supplies the hot gases generated therein to said turbine being in flow communication therewith, the combination with said steam injecting means of:

a. first steam generating means in flow communication with the exhaust system of said turbine,

b. second steam generating means in series with said first steam generating means; said second steam generating means being in heat exchange relationship with the cooling circuit of said turbine,

c. means in flow communication with said compressor for generating a control signal and d. means connected to said control signal generating means and responsive to said control signal for ad justing the flow of exhaust gas to said first steam generating means.

20. The combination of claim 19 wherein the means for generating a control signal comprises:

a. electrical signal comparing means having first and second inputs and having an output, said output being electrically connected to said adjusting means,

b. means electrically connected to said first input of said comparing means and in flow communication with the compressor discharge for sensing the compressor discharge pressure and generating a pressure-response signal quantitatively related thereto and c. means electrically connected to said second input of said comparing means for applying a bias signal thereto, said comparing means supplying a control signal to said adjusting means via said output when the relationship between said bias signal and said pressure-response signal deviates from some predetermined value.

21. The combination of claim wherein said means for applying a bias signal is a fixed voltage source.

22. The combination of claim 20 wherein said means for applying a bias signal includes a voltage generator and a temperature sensor having an electrical signal output quantitatively related to the temperature sensed, said temperature sensor being located adjacent the inlet to said compressor and being electrically connected to said voltage generator, said voltage generator being electrically connected to said second input and the bias signal generated thereby being quantitatively related to the signal from said temperature sensor.

23. The combination of claim 20 wherein the means for applying a bias signal includes a temperature sensor having an electrical signal output quantitatively related to the temperature sensed; first and second voltage generators electrically connected at their respective inputs to said temperature sensor; a humidity sensor hav ing an electrical signal output quantitatively related to the relative humidity sensed; a voltage multiplier having separate inputs electrically connected to the outputs of said second voltage generator and said humidity sensor, respectively; and the outputs of said first voltage generator and said voltage multiplier being electrically connected to a summing junction, the bias signal output of said summing junction being electrically connected to said comparing means and said temperature sensor and said humidity sensor being located adjacent the inlet to said compressor.

24. The combination of claim 20 wherein the means for sensing and generating a pressure-response signal is a pressure transducer.

25. The combination of claim 19 wherein said adjusting means is a flow bypass having powered actuating means, said flow bypass being in flow communication with said steam generating means.

26. The combination of claim 19 wherein said adjusting means is a flow bypass having powered actuating means, said flow bypass being in flow communication with the outlet of said turbine, with said steam generating means and with mixing means located downstream in the turbine exhaust system.

27. In the operation of a gas turbine power plant in the steam injection mode wherein the following steps are performed: generating steam from liquid water; compressing atmospheric air to superatmospheric pressure; passing the compressed air to a combustion zone, where fuel is introduced and continuous combustion occurs; passing the generated steam to said combustion zone, and passing hot gases continuously from said combustion zone through an expansion zone where mechanical energy is abstracted in substantially greater amount than the mechanical energy absorbed in the compression step, the combination with said series of step of:

a. automatically controlling the flow of steam to said combustion zone by means of a control signal, said gontrol si nal esulting from the interrelation of a ias signa an a signa quantitative y comparable to the compressor pressure ratio.

28. The steps of operation of a gas turbine power plant as recited in claim 27 wherein the bias signal is a constant voltage signal.

29. The steps of operation of a gas turbine power plant as recited in claim 27 wherein the bias signal is quantitatively related to the ambient temperature.

30. The steps of operation of a gas turbine power plant as recited in claim 27 wherein the bias signal is quantitatively related both to the ambient temperature and to the ambient humidity.

* k I! i t

Patent Citations
Cited PatentFiling datePublication dateApplicantTitle
US2678531 *Feb 21, 1951May 18, 1954Chemical Foundation IncGas turbine process with addition of steam
US2959005 *May 18, 1959Nov 8, 1960Bbc Brown Boveri & CieGas turbine plant and method of operating the same
US3353360 *Feb 18, 1966Nov 21, 1967Foster Wheeler CorpPower plant with steam injection
US3649469 *May 22, 1968Mar 14, 1972Atomic Energy Authority UkPlant for producing both power and process heat for the distillation of water
GB614106A * Title not available
Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US3747336 *Mar 29, 1972Jul 24, 1973Gen ElectricSteam injection system for a gas turbine
US3826080 *Mar 15, 1973Jul 30, 1974Westinghouse Electric CorpSystem for reducing nitrogen-oxygen compound in the exhaust of a gas turbine
US3850569 *Sep 7, 1973Nov 26, 1974Phillips Petroleum CoProcess for reducing nitric oxide emissions from burners
US3893433 *Jul 2, 1973Jul 8, 1975Resonance Motors IncRotary engine with rotating cylinders
US3921389 *Oct 3, 1973Nov 25, 1975Mitsubishi Heavy Ind LtdMethod and apparatus for combustion with the addition of water
US3969899 *Aug 27, 1974Jul 20, 1976Sadaharu NakazawaFuel burning apparatus and heat engine incorporating the same
US3986347 *Dec 6, 1973Oct 19, 1976Phillips Petroleum CompanyCombustor process for low-level NOx and CO emissions
US4021190 *Aug 20, 1975May 3, 1977Rockwell International CorporationBurner block valve assembly
US4104869 *Jan 21, 1977Aug 8, 1978Vincent Ogden WSteam engine with steam heat recovery and steam compression
US4128994 *Jul 14, 1976Dec 12, 1978International Power Technology, Inc.Regenerative parallel compound dual-fluid heat engine
US4160362 *Mar 31, 1977Jul 10, 1979Westinghouse Electric Corp.Gas turbine and combined cycle power plant having reduced emission of nitrogen oxide and improved coolant injection flow control system therefor
US4224045 *Aug 23, 1978Sep 23, 1980Union Carbide CorporationCryogenic system for producing low-purity oxygen
US4248039 *Dec 6, 1978Feb 3, 1981International Power Technology, Inc.Regenerative parallel compound dual fluid heat engine
US4259837 *Jun 13, 1979Apr 7, 1981General Electric CompanyWater and steam injection system for emission control of gas turbines
US4297841 *Jul 23, 1979Nov 3, 1981International Power Technology, Inc.Control system for Cheng dual-fluid cycle engine system
US4327547 *Nov 5, 1979May 4, 1982Rolls-Royce LimitedFuel injectors
US4417438 *Jun 12, 1981Nov 29, 1983International Power Technology, Inc.Control system for Cheng dual-fluid cycle engine system
US4499721 *Mar 21, 1983Feb 19, 1985International Power Technology, Inc.Control system for Cheng dual-fluid cycle engine system
US4503681 *Jul 14, 1983Mar 12, 1985General Electric CompanyState-of-the-art gas turbine and steam turbine power plant
US4522024 *Sep 8, 1982Jun 11, 1985Bbc Brown, Boveri & Company, LimitedMethod for reducing the amount of nox and for raising the output of a gas turbine power station of the type utilizing an air reservoir, and a gas turbine power station, of this type, operating in accordance with this method
US4549397 *Mar 18, 1983Oct 29, 1985International Power Technology, Inc.Control system for Cheng dual-fluid cycle engine system
US4569195 *Apr 27, 1984Feb 11, 1986General Electric CompanyFluid injection gas turbine engine and method for operating
US4631914 *Feb 25, 1985Dec 30, 1986General Electric CompanyGas turbine engine of improved thermal efficiency
US4660376 *Oct 21, 1985Apr 28, 1987General Electric CompanyMethod for operating a fluid injection gas turbine engine
US4667465 *Jul 30, 1985May 26, 1987Michael MunkInternal combustion engine system and method with reduced noxious emissions
US4680927 *Jul 25, 1985Jul 21, 1987International Power Technology, Inc.Control system for Cheng dual-fluid cycle engine system
US4702074 *Jul 30, 1985Oct 27, 1987Michael MunkInternal combustion engine system with fog injection and heat exchange
US4731988 *Dec 31, 1986Mar 22, 1988Michael MunkInternal combustion engine system and method with reduced noxious emissions
US4731990 *Dec 31, 1986Mar 22, 1988Michael MunkInternal combustion engine system and method with reduced noxious emissions
US4733527 *Mar 12, 1987Mar 29, 1988Dreser Industries, Inc.Constant NOx control for gas turbine
US4753068 *Jan 15, 1987Jun 28, 1988El Masri Maher AGas turbine cycle incorporating simultaneous, parallel, dual-mode heat recovery
US4773846 *Sep 1, 1987Sep 27, 1988Michael MunkCombustion system and method with fog injection and heat exchange
US4823546 *Apr 13, 1988Apr 25, 1989International Power TechnologySteam-injected free-turbine-type gas turbine
US4893467 *Jul 13, 1988Jan 16, 1990Gas Research InstituteControl system for use with steam injected gas turbine
US4893468 *Nov 30, 1987Jan 16, 1990General Electric CompanyEmissions control for gas turbine engine
US4899537 *Feb 7, 1984Feb 13, 1990International Power Technology, Inc.Steam-injected free-turbine-type gas turbine
US4928478 *Jul 22, 1985May 29, 1990General Electric CompanyWater and steam injection in cogeneration system
US4955191 *Oct 26, 1988Sep 11, 1990Kabushiki Kaisha ToshibaCombustor for gas turbine
US4969324 *Jul 24, 1989Nov 13, 1990Gas Research InstituteControl method for use with steam injected gas turbine
US5349812 *Jan 28, 1993Sep 27, 1994Hitachi, Ltd.Gas turbine combustor and gas turbine generating apparatus
US5357741 *May 1, 1992Oct 25, 1994Dresser-Rand CompanyNOx and CO control for gas turbine
US5369951 *Nov 27, 1991Dec 6, 1994Rolls-Royce PlcGas generators
US5375409 *Oct 8, 1993Dec 27, 1994Ahlstrom Pyropower, Inc.Pressurized fluidized bed combined gas turbine and steam turbine power plant with steam injection
US5463873 *Dec 6, 1993Nov 7, 1995Cool Fog Systems, Inc.Method and apparatus for evaporative cooling of air leading to a gas turbine engine
US5540045 *Sep 16, 1994Jul 30, 1996Rolls-Royce PlcSteam injection system for a combustion turbine gas generator
US5566542 *Aug 24, 1994Oct 22, 1996Westinghouse Electric CorporationMethod for regulating and augmenting the power output of a gas turbine
US5720164 *Feb 20, 1996Feb 24, 1998Rolls-Royce PlcGas generators having dual fuel injector purge means
US6000211 *Nov 12, 1997Dec 14, 1999York Research CorporationSolar power enhanced combustion turbine power plant and methods
US6357218Jun 20, 2001Mar 19, 2002General Electric CompanySteam generation system and method for gas turbine power augmentation
US6389793Apr 19, 2000May 21, 2002General Electric CompanyCombustion turbine cooling media supply system and related method
US6389814Dec 20, 2000May 21, 2002Clean Energy Systems, Inc.Hydrocarbon combustion power generation system with CO2 sequestration
US6405521 *May 23, 2001Jun 18, 2002General Electric CompanyGas turbine power augmentation injection system and related method
US6446440Sep 15, 2000Sep 10, 2002General Electric CompanySteam injection and inlet fogging in a gas turbine power cycle and related method
US6481212Mar 26, 2002Nov 19, 2002General Electric CompanyCombustion turbine cooling media supply system and related method
US6484506 *Aug 26, 1999Nov 26, 2002York Research Corp.Solar power enhanced combustion turbine power plant and methods
US6523349Jun 19, 2001Feb 25, 2003Clean Energy Systems, Inc.Clean air engines for transportation and other power applications
US6553768Nov 1, 2000Apr 29, 2003General Electric CompanyCombined water-wash and wet-compression system for a gas turbine compressor and related method
US6584777 *Jun 13, 2000Jul 1, 2003Rolls-Royce PlcApparatus for and method of filtering a fluid
US6584779Nov 12, 2002Jul 1, 2003General Electric CompanyCombustion turbine cooling media supply method
US6598398May 21, 2002Jul 29, 2003Clean Energy Systems, Inc.Hydrocarbon combustion power generation system with CO2 sequestration
US6622470May 14, 2001Sep 23, 2003Clean Energy Systems, Inc.Semi-closed brayton cycle gas turbine power systems
US6637183May 14, 2001Oct 28, 2003Clean Energy Systems, Inc.Semi-closed brayton cycle gas turbine power systems
US6708496May 22, 2002Mar 23, 2004Siemens Westinghouse Power CorporationHumidity compensation for combustion control in a gas turbine engine
US6715295May 22, 2002Apr 6, 2004Siemens Westinghouse Power CorporationGas turbine pilot burner water injection and method of operation
US6824710May 14, 2001Nov 30, 2004Clean Energy Systems, Inc.Working fluid compositions for use in semi-closed brayton cycle gas turbine power systems
US6868677May 24, 2002Mar 22, 2005Clean Energy Systems, Inc.Combined fuel cell and fuel combustion power generation systems
US6910335Aug 22, 2003Jun 28, 2005Clean Energy Systems, Inc.Semi-closed Brayton cycle gas turbine power systems
US6941759Nov 22, 2002Sep 13, 2005Jasper Energy Development LlcSolar power enhanced combustion turbine power plants and methods
US6945029Nov 17, 2003Sep 20, 2005Clean Energy Systems, Inc.Low pollution power generation system with ion transfer membrane air separation
US7021063Mar 10, 2004Apr 4, 2006Clean Energy Systems, Inc.Reheat heat exchanger power generation systems
US7043920Jul 8, 2003May 16, 2006Clean Energy Systems, Inc.Hydrocarbon combustion power generation system with CO2 sequestration
US7353654Jun 4, 2004Apr 8, 2008Alstom Technology LtdMethod and apparatus for achieving power augmentation in gas turbines using wet compression
US7353655Jun 4, 2004Apr 8, 2008Alstom Technology LtdMethod and apparatus for achieving power augmentation in gas turbine using wet compression
US7353656Sep 1, 2006Apr 8, 2008Alstom Technology LtdMethod and apparatus for achieving power augmentation in gas turbines using wet compression
US7520137Jun 2, 2005Apr 21, 2009Alstom Technology LtdMethod of controlling the injection of liquid into an inflow duct of a prime mover or driven machine
US7784286Sep 1, 2006Aug 31, 2010Alstom Technology LtdMethod and apparatus for achieving power augmentation in gas turbines using wet compression
US7882692Apr 30, 2007Feb 8, 2011Clean Energy Systems, Inc.Zero emissions closed rankine cycle power system
US8033115 *Jan 5, 2006Oct 11, 2011General Electric CompanyWater injection manifold pressure relief vent
US8033116May 6, 2008Oct 11, 2011General Electric CompanyTurbomachine and a method for enhancing power efficiency in a turbomachine
US8454350Oct 29, 2008Jun 4, 2013General Electric CompanyDiluent shroud for combustor
US8539750 *Apr 30, 2010Sep 24, 2013Siemens Energy, Inc.Energy recovery and steam supply for power augmentation in a combined cycle power generation system
US8887390Aug 15, 2008Nov 18, 2014Dresser-Rand CompanyMethod for correcting downstream deflection in gas turbine nozzles
US20110265444 *Apr 30, 2010Nov 3, 2011Bellows James CEnergy recovery and steam supply for power augmentation in a combined cycle power generation system
USRE43252Sep 22, 2003Mar 20, 2012Vast Power Portfolio, LlcHigh efficiency low pollution hybrid Brayton cycle combustor
DE3514718A1 *Apr 24, 1985Oct 31, 1985Gen ElectricGasturbinentriebwerk und betriebsverfahren
DE3514718C2 *Apr 24, 1985Jun 29, 2000Gen ElectricGasturbinenanlage und Verfahren zu ihrem Betrieb
WO1981000280A1 *Jul 7, 1980Feb 5, 1981Int Power TechControl system for cheng dual-fluid cycle engine system
WO1986004957A1 *Feb 5, 1986Aug 28, 1986John T PattonHybrid steam/gas turbine machine
WO1992009791A2 *Nov 27, 1991Jun 11, 1992Rolls Royce PlcImprovements in or relating to gas generators
Classifications
U.S. Classification60/775, 60/39.55, 60/39.3
International ClassificationF01K21/04, F01K21/00
Cooperative ClassificationY02E20/14, F01K21/047
European ClassificationF01K21/04E