WO2001034955A1 - Method for optimizing industrial gas turbine operation subject to emissions controls - Google Patents

Abstract

A process is described for achieving a reduction in regulated emissions of combustion products from power generation apparatus including an industrial gas turbine or turbines, while at the same time providing a desired level of power production from such apparatus, comprising displacing an increment of power generated by such apparatus with at least an equivalent increment of power provided by the application of wet compression in one or more of said gas turbines.

Description

METHOD FOR OPTIMIZING INDUSTRIAL GAS TURBINE OPERATION SUBJECT TO EMISSIONS CONTROLS

The present invention relates to the operation of large, land-based gas turbines such as are used for industrial and municipal power generation, and more particularly to the operation of such turbines which are subject to regulatory limits on the emissions of one or more combustion products - for example, nitrogen oxide gases (NO_x), carbon monoxide (CO), carbon dioxide (CO₂), volatile organic compounds (VOCs), sulfur oxides (SO_x) and particulate matter. In a series of related, commonly-assigned and copending United States Patent

Applications designated by Serial Numbers 08/645,781 (filed May 14, 1996, now issued as United States Patent No. 5,930,990), 08/715,675 (filed Sept. 18, 1996, now United States Patent No. 5,867,977) and 08/837,192 (filed April 14, 1997), with the last such application substantially corresponding to an application filed under the Patent Cooperation Treaty as PCT/US97/08757 and published on November 20, 1997 as WO 97/43530, a novel technology is described for augmenting the power production of large, land-based gas turbines as are used for industrial and municipal power generation purposes.

The augmentation technology in question fundamentally involves the addition, over an extended period of operation, of a significant volume of a liquid which is possessed of a high latent heat of vaporization (for example, water) to the working fluid acquired by the compressor sections of these turbines. For example, by the addition to the inlet air of an amount of water which is well in excess of that required for full humidification of the inlet air, through both latent heat compressor intercooling and mass flow effects more power is produced from the turbine than would normally be produced absent the water addition and with normally (even fully) humidified inlet air.

It has now been appreciated that, beyond the context only of capacity augmentation, the above-described technology can have very substantial operating benefits in other contexts as well. The present application is concerned with one of these contexts, namely, in providing a desired level of power production from an industrial gas turbine or an overall level of power production from a combination of power generation assets including one or more gas turbines, within the constraints of a regulatory environment including limits on the emissions of one or more combustion products - the nitrogen oxide gases (NO_x) and carbon described in the above-referenced application documents and patent can be used to optimize power generation operations in this context, where further reductions in emissions are desired, or indeed must be obtained because of changes in the regulatory environment or in order to achieve a greater level of power generation from the assets in question without transgressing existing emissions limits. Of course, where further emissions reductions are sought, the utility or industrial concern affected could on the one hand replace one or more of its generation assets with more efficient (from an emissions perspective) capacity in the form of a newer turbine or turbines, or could engage at least in substantial "hardware" modifications to the turbine or turbines. From an economic perspective, however, these may not be viable options for many generating entities, and in any event will not often be favored where other, less time-consuming and less costly or capital-intensive solutions are available.

Among these other known technologies for complying or helping to comply with such emissions limits in regards to existing industrial gas turbines and in a "retrofit" context, are those which have been principally developed around the issue of NO_x emissions, including direct water or pressurized steam addition to the combustors or pressurized steam injection through the engine's casing and into the compressor discharge section of the industrial gas turbine (the last being commonly referred to as "STIG"). Low NO_x combustion systems have also been developed as a still more complex and expensive alternative for reducing emissions of regulated nitrogen oxide gases, and for very stringent regulatory environments, still more complex and still more expensive catalytic oxidation or selective catalytic reduction (SCR) exhaust gas treatment technologies have been developed for turbines equipped with standard combustors and steam injection, for example, or with low NO_x combustion systems. Each of these various technologies has its advantages and disadvantages relative to the others, and while each may have some incremental and complementary bearing or effect on power generation in addition to NO_x emissions, likewise none of these conventional, less capital-intensive approaches have proven entirely satisfactory. The present invention, in summary, provides a process for achieving a reduction in the emissions of combustion products from power generation apparatus including one or more industrial gas turbines, while at the same time providing a desired level of power such apparatus with at least an equivalent increment of power provided by the application of wet compression in one or more of said gas turbines. Thus, a reduction in regulated combustion product emissions may be achieved while maintaining the same level of power production from the power generation apparatus as before, or these reductions may be realized even while providing an increased level of power production from the apparatus. In effect, an improvement in the emissions efficiency (on a volumetric or mass basis per unit of power production, or both) of power generation apparatus including an industrial gas turbine is enabled. In general terms, the displaced increment of power generation capacity should preferably be the least efficient such increment, portion or segment provided by the power generation apparatus in terms of power production and resulting emissions of regulated species, whether NO_x, CO or other combustion products. The manner in which wet compression is best used to displace less-efficient increments of power generation will depend on the particular factual circumstances confronting the operator, as will be readily appreciated by those skilled in the art in consideration of the remarks and examples provided below.

Figure 1 shows an overview of a typical gas turbine power generation facility (the affiliated electric generator is not actually shown in Figure 1 , but is conventionally known) used to generate electric power from the combustion of fuel with air.

Figures 2A and 2B show details of a gas turbine engine having an axial compressor.

Figure 3 shows the positioning of a spray rack group assembly used in the gas turbine power generation facility of Figure 1. Affiliated steam pipes are also shown.

Figure 3A is an enlarged view of details of the spray rack group assembly and steam pipes.

Figure 4 shows further details for the layout of the spray rack, showing an elevation view of the relative location of individual spray rack water pipes, the positioning of each spray rack water nozzle, and the use of spray rack stiffeners.

Figure 5 is a plan view showing details of the spray rack assembly of Figures 3 and 4 with a steam manifold for feeding steam to the steam pipes.

Figure 6 presents details for monitoring for deformation of the housing of the gas turbine engine system shown, for example, in Figures 1 and 2. Figures 7 and 8 show further details of a preferred apparatus for monitoring for deformation of the gas turbine housing, as described in commonly-assigned, copending United States Application Serial No. 09/255,553, filed February 22, 1999 for "Apparatus for Monitoring Wet Compression Gas Turbine Power Augmentation-Related Casing Distortions".

As an introductory comment, while Figures 1 through 8 appropriately depict a single industrial gas turbine of the large, land-based, non-aircraft derivative variety, and while the principles and benefits of wet compression technology as used in the process of the present invention are explained and illustrated below with reference to this single power generation asset, it should be always kept in mind that the power generation assets to which the emissions management process of the present invention may be applied can include a variety of different power generation devices - for example, steam helper turbines, standalone boilers, aeroderivative turbines equipped with a spray device or devices before one or a plurality of the compressor sections implicated in such turbines. Figures 1 - 8 and the accompanying discussion are consequently largely reproduced from the prior, copending applications for the limited purpose only of providing background information concerning the use of wet compression technology, and should not be taken as limiting in any sense of the present, related but distinct invention. The terminology employed in the published PCT application is adopted herein as well:

"Industrial gas turbine" means at least a 20 megawatt or a larger megawatt turbine used for land-based power generation in industrial and utility power-generating applications. The term industrial gas turbine can include heavy duty as well as aircraft derivative turbines. "Heavy duty gas turbine" refers to a type of gas turbine which, from a design standpoint, is not specifically designed to accept abrupt changes of significant magnitude in power output. Heavy duty gas turbines are thus intended to be distinguished, particularly, from aircraft derivative turbines.

"Working fluid". The typical working fluid of a gas turbine is a gas; the typical working fluid in the compressor of a gas turbine is humidified air. In the present invention the working fluid for at least one gas turbine is expanded to include an added liquid (such as demineralized water) which is subsequently vaporized in the gas turbine thermodynamic gas turbine (due to injection of materials and from the combustion process). In this regard, the working fluid can, at various positions along the axis of the gas turbine as it progresses through the working cycle of the gas turbine, be either a gas mixture, a two-phase liquid in gas mixture, a two-phase mixture of solid particles in gas, or a three-phase mixture of liquid and solid particles in gas.

"Net output" is in reference to the net output of a gas turbine and means the available shaft power for driving a generator or process compressor (external to the gas turbine). Net output of a gas turbine is measured by torque and speed of the rotor shaft and can be expressed in terms of either horsepower or megawatts. When expressed in terms of megawatts, the term net output generally includes generator losses. When comparing net outputs under comparable conditions, but with and without a high latent heat of vaporization liquid being added, the comparable conditions include a comparable process for measuring net output. "Addition of heat and humidity" references the concurrent addition of heat and moisture to the working fluid up to the saturation point of the working fluid.

"Angular deformation" refers to a condition of bowing or distortion of the housing which can result in interference between the rotor and housing of the turbine.

"Damage" means harmful alteration of any of the components of the gas turbine beyond that which would be anticipated in the course of reasonable use and operation. With the contemplated liquid addition to the compressor of at least one gas turbine, a certain acceptable degree of erosion of the blade coating or blade material is to be anticipated.

"Water" means water which, in compositional nature, is useful for ingestion into a wet compression-equipped gas turbine for purposes of the present invention. It can include impurities and conventional or beneficial additives such as, for example, a freezing point depressant or materials to reduce or remedy any tendency of the water added to corrode turbine components or to leach out components of alloys used in constructing the various structural elements of the gas turbine with which the water may come into contact. "Varying a number of mass flow increments in a balanced manner" refers to increments of water (or other liquid generally) added to the working fluid. The term

"balanced manner" refers to an increment as having been qualified to not cause a distortion of the gas turbine housing which exceeds an acceptable angular distortion limit when the unacceptable angular distortion in the housing after an increment(s) has either been added to or subtracted from the previous set of combined increments.

"Sufficiently uniform distribution" refers to a distribution of added liquid in the working fluid acquired by the compressor of a wet compression-equipped gas turbine, which will in turn result in a distribution of liquid within the compressor that will not cause a distortion of the gas turbine housing exceeding an acceptable angular distortion limit.

"Improved fuel efficiency" means the production of more net power output per unit of fuel when a vaporizable liquid is added to the working fluid than would be achieved under comparable conditions but without said liquid having been added to the working fluid.

Turning now to Figure 1 , an overview is provided of a gas turbine power generation facility 100 used to generate electric power from the combustion of fuel with air (the affiliated electric generator is not actually shown in Figure 1 , but is presumed to be apparent). The gas turbine power generation facility 100 comprises, in one preferred, illustrative embodiment, a gas turbine or gas turbine engine 101 which as shown in Fig. 2A includes an axial-flow compressor or axial compressor section 103, the axial compressor section 103 having a compressor inlet 102 for acquiring a working fluid comprising air. An inlet air filter 109 is defined in an inlet air duct 133 preceding the compressor inlet 102 (see Figure 2A), which inlet air filter 109 may in turn be preceded (or followed in certain embodiments) by a conventional, media-type evaporative inlet air cooling apparatus (not shown). The inlet air duct 133 is made of an inlet air duct convergent portion 135, an inlet air duct constricted portion 137 (having a lower surface 136), and an inlet air duct manifold portion 139 with a viewport 413. Silencers are also conventionally employed in the inlet air ducts of gas turbines like the turbine 101 for reducing noise levels in operation, though these are not shown in the present Figure 2A.Figures 2A and 2B show further detail respecting gas turbine engine 101. After entering the compressor inlet 102, the air is compressed in the axial compressor section 103 by using a series of compressor stages 113. After compression, the compressed air then flows into combustion chambers 105 in the combustion section where it is mixed with fuel and the fuel is combusted to generate a hot pressurized gas for use in driving the turbine section 107. The turbine section 107 has a series of turbine section stages 108 which incrementally (1) convert the energy of the hot components in the turbine section 107) and (2) generate an exhaust gas having a lower temperature and pressure than the hot pressurized gas which entered the respective turbine section stage 108. The exhaust gas from the first such turbine section stage 108 is then the hot pressurized gas for the second stage; the exhaust gas from the last stage is also the exhaust gas from the turbine section 107.

The rotor 111 is a part of both the turbine section 107 and the axial compressor section 103 and includes the rotor shaft 127 and the set of all rotor blades (115, 121) in both the turbine section 107 and the axial compressor section 103 mounted to rotor shaft 127. Rotor shaft 127 powers both the axial compressor section 103 and an electric generator or some other useful machine such as, without limitation, a large compressor used in chemical processing. In this regard, rotor shaft 127 is usually either a single structural component or, alternatively, a series of individual components which are mechanically attached together to form a virtual single structural component. The various gases and fluids within the gas turbine engine 101 are generally contained by a housing 125 which defines an inner space of the gas turbine engine 101 to (a) channel the pre-compression air, (b) contain the compressed air in its progression through the sequential compressor stages 113, (c) provide a pressure shell to contain the compressor discharge around the combustion chamber(s) 105 in the combustion section, (d) contain the hot pressurized gas in which fuel has been combusted as it expands in the turbine section 107, and (e) channel exhaust gas while resident within the combustion engine 101. The housing 125 is usually constructed of several different pieces which are essentially connected together.

In axial compressor section 103, each compressor stage 113 is made up of a series of compressor rotor blades 1 15 mounted on the rotor shaft 127 and both the preceding and following sets of compressor stator blades 117 where, for each set, compressor stator blades 117 are mounted as a series in a radially disposed manner as a stationary blade row. The compressor stator blades 117 are (a) proximately fitted closely to the internal wall of housing 125 and (b) sealed to the rotor 11 1 (typically with labyrinth seals) in such a manner as to enable, in operation, an essential fluid isolation of one compressor stage 1 13 from its companion compressor stage(s) 113. The compressor rotor blades 115 and the compressor stator blades 117 collectively function to increase the pressure of air passing through compressor stage 113 by (1) transferring kinetic energy to the air (or gas flow) from the pressure and temperature rise in the air as the air is decelerated by the compressor stator blades 117 following the compressor rotor blades 115. The pressure ratio of exit pressure to inlet pressure in one compressor stage 113 is limited by intrinsic aerodynamic factors, so several compressor stages 113 are usually required to achieve a higher overall pressure ratio for the axial compressor section 103 than could be achieved by a single axial compressor stage 113.

After addition of fuel in the combustion chamber(s) 105 of the combustion section and oxidation of the fuel by the oxygen within the compressed air, the resultant hot pressurized gas is converted into work within turbine section 107; this process is achieved by transferring the high kinetic energy of the expanding hot pressurized gas to the turbine section rotor blades 121 in a series of turbine section stages 108.

Each turbine section stage 108 is made up of a series of turbine section rotor blades 121 mounted on the rotor shaft 127 and the preceding set of turbine section stator blades 122 which are mounted as a series in a radially disposed manner as a stationary blade row. The turbine section stator blades 122 are (a) proximately fitted closely to the interior wall of housing 125 and (b) sealed to the rotor 111 (usually with labyrinth seals or brush seals) in such a manner as to enable, in operation, an essential fluid isolation of one turbine section stage 108 from its companion turbine section stage(s) 108. The turbine section rotor blades 121 and the turbine section stator blades 122 collectively function to incrementally decrease the pressure of the hot pressurized gas by (1) channeling the hot pressurized gas and (2) transferring kinetic energy from the expanding hot pressurized gas to the rotating turbine section rotor blades 121, producing work which is manifested in the rotation of the rotor 111 as it drives its load. Figure 3 now shows a means for providing vaporizable liquid particles to the working fluid acquired by the axial-flow compressor 103, and preferably thereafter, for controllably augmenting (and correspondingly, controllably reducing) the amount of liquid provided to the working fluid in the context of wet compression. As has been indicated previously, a preferred, high latent heat of vaporization liquid to be added is water, and the description hereafter while speaking most often of adding liquid water should be understood as contemplating and encompassing the addition of other vaporizable liquids. axial compressor section 103 in the context of the prior copending, augmentation-related applications and the published PCT application, as well as in the context of the present invention, comprises a spray rack group assembly 201 communicating with the compressor inlet 102 of the axial compressor section 103. The spray rack group assembly 201 can be positioned anywhere between the inlet air filter 109 and the compressor inlet 102, but is preferably inserted into the inlet air duct 133 in the inlet air duct constricted portion 137 after the inlet air duct convergent portion 135, and preferably also downstream of any conventional silencer elements used in the inlet air duct 133. This positioning has benefits in that sufficient separation from the compressor inlet 102 is provided so that a nozzle 305 (or other damaged part of either a steam addition system to be described more particularly hereafter or of the spray rack group assembly 201) which might become detached from spray rack group assembly 201 will be gravitationally pulled to the lower surface 136 of inlet air duct 133 before the nozzle 305 (or damaged part) is pulled into the rotating rotor 111.

In commonly-assigned United States Patents No. 5,867,977 and 5,930,990 and in the prior published PCT application, of course, the objective and focus is exclusively on power generation capacity augmentation from a given gas turbine, as opposed to achieving a desired level of power production from power generation assets consisting of or inclusive of a gas turbine in spite of certain emission limit constraints, which is the objective and focus of the present invention - whether this means, for example, maintaining or increasing a given net power output from a single turbine while reducing emissions of regulated combustion products, or maintaining or increasing a net power output across a plurality of single point emissions sources/generation assets inclusive of a gas turbine while reducing emissions overall.

In the former, augmentation-focused context, very substantial quantities of water are generally contemplated for addition to the compressor of an industrial gas turbine, whereas in regards to the present invention, it may be that much lesser amounts of water are required (taking into account any existing emissions-limiting capabilities) to be added to the compressor of any given gas turbine in order to achieve the desired level of power production from the turbine or group of turbines and other generation assets while also electric power generation assets.

Consequently, while significant teaching is provided in the commonly-assigned United States Patents No. 5,867,977 and 5,930,990 and the prior published PCT application of various arrangements of water-addition apparatus for delivering large volumes of nebulized water to the compressor of a large, land-based industrial gas turbine such as turbine 101 while maintaining a sufficiently uniform distribution of the nebulized water in the working fluid to avoid exceeding an acceptable angular distortion limit, it may be sufficient for purposes of the present invention to use a water delivery means or apparatus (a coarse spray, water wash apparatus positioned near the compressor inlet, for example) that does not provide the same finely nebulized, uniform distribution of water as preferred in the earlier-filed applications.

Having made this observation, it is generally expected that because of the efficiency of wet compression-based power generation in terms of fuel usage and in terms of emissions of combustion products for a given level of power production, not to mention the added flexibility provided to accommodate greater power demands in the future, it will be preferred to use wet compression via apparatus of the type shown in Figure 3 (optionally including supplemental water-addition means, as described in the PCT application, upstream or downstream of the apparatus shown in Fig. 3). With respect now to the spray rack group assembly 201 depicted in Figure 3, the assembly 201 is made up of a group of individual spray racks 301 , where each individual spray rack 301 is made up in turn of a spray rack water pipe 303 with a group of spaced spray rack water nozzles 305 for nebulizing the water which is sent through the spray rack water pipe 303. Additionally, a spray rack steam pipe 313 with spray rack steam hole(s) 315 can in an optional further refinement be provided to add steam heating to the inlet air. Mounting sleeve(s) 336 are periodically employed on each spray rack steam pipe 313 to provide free movement during thermally induced expansion and contraction of the spray rack steam pipe 313.

Preferably very clean water, for example, water having a conductance of 5.0 micromhos or less with no particulates, whether as condensate water or distilled, deionized water, is in this manner nebulized (or atomized) to form a preferably very fine spray or fog of water. A number of known, commercially-available nozzle designs could be employed Technical Services, Ltd. under the "FYREWASH" identifier (such entity having an office at 610 N. Milby Street, Suite 100, Houston, Texas 77003), a 1-7N-316SS12 nozzle from Spraying Systems Co. (P.O. Box 7900, Wheaton, Illinois, 60189) which provides a spray characterized by a volume mean diameter of 153 microns (2 gallon per minute (7.6 litres per minute) flow rate) at a pressure drop of 80 psig (550 kPa, gauge) and a temperature in the range of 45 to 165 degrees Fahrenheit (7.2 degrees Celsius to 73.9 degrees Celsius), or a 1- 7N-316SS16 nozzle from Spraying Systems Co. which provides a spray characterized by a volume mean diameter of 188 microns (2.6 gallon per minute (9.9 litres per minute) flow rate) at a pressure drop of 80 psig (550 kPa, gauge)and a temperature in the range of 45 to 165 degrees Fahrenheit (7.2 degrees to 73.9 degrees Celsius).

Another potentially useful nozzle type is a "spiral nozzle" such as sold by BETE Fog Nozzle, Inc., Greenfield, Massachusetts, being essentially characterized by the use of a helical spray vane extending from the valve body outlet and having a continuously decreasing diameter in the direction of flow, for shearing the liquid to be atomized into the desired droplet size. Nozzles of this variety were initially shown in United States Patent No. 2,612,407 and Re. 23,413, both to Bete.

In this last respect, preferably the liquid supplied to the compressor inlet will be a substantially uniformly distributed mist or fine spray of particles having a mean average droplet diameter of less than 200 microns, preferably being less than 120 microns in mean average droplet diameter, more preferably being less than 70 microns in diameter and especially being in the range of 50 down to 40 microns and less. Smaller particles more readily follow the velocity vectors established by fluid flow to the compressor, are less erosive of rotating compressor blades and other compressor components than larger droplet sizes, and generally facilitate achieving the full measure of the mass flow increase effect of wet compression by evaporation/densification and entrainment effects in the first compressor stage, but achieving smaller droplet sizes will at the same time obviously entail additional expense through higher pressures and additional nozzles for a desired flowrate of liquid into the compressor. As contemplated in the '977 and '990 patents and in the prior published PCT application, the amounts of liquid water to be supplied through the spray rack assembly 201 will preferably be added or removed in a controlled fashion. This controlled augmentation by the compressor 103, such as by increasing the water pressure to the spray rack assembly 201 or some portion of the assembly 201. In the alternative, the liquid water can be provided to the working fluid acquired by the compressor section 103 in a stepped, incremental fashion. As another alternative, a combination of smooth ramping and/or stepped modification of the amount of water provided to the working fluid acquired by the axial compressor section 103 can be beneficially employed either in a concurrent fashion or sequentially.

Most preferably, however, the liquid water, when either increasing or decreasing its flow, will be added or reduced in a stepped manner using a plurality of water mass flow increments. In this regard, those skilled in the art will appreciate that each nozzle 305 will have a range of pressures over which a particular liquid can be properly nebulized given an adequate supply of the liquid being nebulized, and that the nozzles 305 themselves may accordingly be viewed as individually essentially defining an increment of water addition; the smallest increment of water mass flow may then be the increment of water mass flow needed to activate the smallest nozzle 305 which might be deployed in facilitating wet compression.

Preferably, however, the increments of water mass flow will be defined at the level of individual spray racks 301 by controlling the pressure to a spray rack water pipe 303, whereby the group of spray rack water nozzles 305 connected to that spray rack water pipe 303 will operate to process a general increment of water mass flow equal to the sum of the individual spray rack water nozzle 305 mass flow increments.

As has been observed previously, in the context of the present invention and as regards an application of the present invention to power generation apparatus including a large, land-based non-aeroderivative gas turbine such as turbine 101, it may or may not be necessary to employ the wet compression power generation technology described in our prior copending applications to an extent whereby angular distortion of the casing and uniformity of nebulized water distribution in the compressor inlet become an issue. Proceeding again on the assumption that one would desirably make the fullest possible use of wet compression in such a turbine 101 to comply with emissions limits and in a particular demand context for the power generated, for example, the mass flow of liquid water provided to the working fluid (or removed therefrom) should be modified as necessary over compressor inlet 102) so as to moderate (a) thermal stresses imposed on the gas turbine 101 and (b) the rate of change of thermal expansion and thermal contraction related to the addition of liquid water to the working fluid. The spray rack group assembly 201 of Figure 3 provides an effective and convenient means for accomplishing these objectives.

The angular deformation of the housing 125 can be monitored and modeled using the laser emitter 403 and laser target 407 described in more detail hereinafter, and especially as part of an arrangement as shown in Figure 7 and described in commonly-assigned United States Patent Application Serial No. 09/255,553, filed February 22, 1999 for "Apparatus for Monitoring Wet Compression Gas Turbine Power Augmentation-Related Casing Distortions".

The use of a plurality of nebulized mass flow increments, as noted in the '977 and '990 United States Patents and in the published Patent Cooperation Treaty application WO 97/43530, is particularly suited to the measurement and control of water addition-related deformation of the housing 125, based on the amount of deformation previously measured as a function of the addition of each of the increments and the response of the housing 125 to the addition or removal of various increments over time, or with respect to position in relation to the compressor inlet 102 and to other increments. Those skilled in the art will appreciate that mathematical modeling of the addition of various increments of nebulized liquid water to the working fluid may also be used for this purpose.

Figure 4 shows further details for the layout of the spray rack group assembly 201 shown in Figure 3, showing, in an elevation view, the relative location of individual spray racks 301 , the positioning of each spray rack water nozzle 305, and the use of spray rack stiffeners 31 1. In this regard, the dimensions and connections for spray rack stiffeners 311 are confirmed empirically to define a stable system which will be structurally robust. A system which can also be used as desired to monitor the spray rack group assembly 201 for overall integrity during operation is a spray rack vibration monitor 411 , for detecting unacceptable resonance in the assembly 201.

Figure 5 shows plan view assembly details of the spray rack assembly of Figures 3 and 4 and illustrates a preferred manner of adding both heat and humidity to the working fluid in an optional further refinement, to allow continued operation of the spray rack assembly 201 during periods when the temperature of the working fluid would otherwise method involves providing steam to the inlet 102, as for example where steam is added to the spray rack steam pipes 313 via steam manifold 319. The steam is added in the embodiment of Figures 3, 4, and 5 to provide steam sufficient to achieve a temperature in the inlet air which is above a point where water in the air freezes in the compressor inlet 102. At least one steam hole 315 is used for each spray rack steam pipe 313, although a preferred construction is that several steam holes 315 are provided for each spray nozzle 305; these steam holes 315 are equally dispersed along each steam pipe 313 for enabling a correspondingly substantially uniform addition of heat and humidity to the working fluid as is desired for the liquid water addition. Generally, the compressor inlet 102 may be most susceptible to icing due to cooler inlet air proceeding along or being channeled along the walls of the housing 125 in the vicinity of the compressor inlet 102, and so preferably sufficient steam will in all embodiments be provided by means of the pipes 313 or by other means at the periphery of the inlet air duct constricted portion 137, to prevent icing from occurring in this manner. Inlet air heating can also be provided by other conventional means, of course, for example by means of a heat exchanger positioned in the flow path of the inlet air to the compressor inlet 102. In order to further assure that the gas turbine engine 101 is not adversely affected by any inrush of liquid which will result if any spray rack water nozzle 305 should become detached from its spray rack water pipe 303, a restricting orifice 317 or other suitable flow restricting means (which is sized to limit the throughput of water in the respective spray rack water pipe 303) is preferably inserted into the source feed line for the spray rack water pipe 303. A steam flow restricting orifice 335 can also be used to restrict the amount of steam added in case of any breakage in the steam delivery system whether steam addition is employed or not, it is important to ensure that the inlet air temperature at the compressor inlet 102 is high enough to prevent the water added (whether added directly as liquid water droplets, or whether condensed from the inlet air stream or condensed from water added in the form of steam) from freezing on surfaces in the vicinity of the inlet guide vanes of the compressor. Ice may starve the compressor into surge or may break free and encounter the rotating blades 115 in the axial compressor section 103.

The temperature of the working fluid in the compressor inlet 102 can for this purpose be monitored with at least one temperature sensor (not shown). In the case of degrees Fahrenheit (although the appropriate minimum may vary somewhat from one turbine design to the next depending upon specific vendor inlet velocity designs and inlet vacuum designs, for example) to assure that icing will not be induced by adiabatic expansion in the compressor inlet 102.

An additional safeguard against potentially destructive icing occurring at the compressor inlet 102 can be provided by placing at least one viewport 413 in the wall of the inlet air duct manifold portion 139 which enables viewing and scanning for ice buildup by an operating technician. An optional and more conventional anti-icing enhancement to the system providing water to spray rack group assembly 201 is to mix a material into the water stream which depresses the freezing point of the water particles. In this regard, freezing point depressants (for example, alcohols such as methanol) can be used to provide for a lower working temperature in the inlet air and for operation of the system at lower ambient air temperatures, in lieu of or in addition to the use of steam addition for the same purpose. Figure 6 presents details for one means for monitoring liquid water addition-related deformation of the housing 125 of the gas turbine engine 101. In this regard, the addition of a substantial mass of nebulized water into the air being processed by the axial compressor section 103 can, as previously indicated, have a detrimental effect on the gas turbine engine 101 because of cooling effects which may not be symmetrical with respect to the inner surface (inner perimeter, inner wall) of the portion of the housing 125 containing the axial compressor section 103. If one portion of the housing 125 is cooled unequally with respect to another portion, then the housing can be distorted through different degrees of thermal expansion being experienced by those portions. Such distortion can precipitate the disruption of internal fluid flows in the axial compressor section 103, inducing a stall or a rotating stall leading to destructive stresses in the components of the axial compressor section 103, or such distortion can induce mechanical rubbing between components of the axial compressor section 103, resulting in either damage to these components or, possibly in the most extreme case, a compressor wreck.

Figure 6 shows the use of a laser emitter 403, a laser reflector 405 and a laser target 407 to achieve monitoring of distortion in the housing 125. It should be noted that the use of the laser reflector 405 is to provide a response to angular distortion, and a series of laser reflectors 405 can be used as desired to further enhance the sensitivity of the assembly to distance that the laser beam emitting from the laser emitter 403 will undergo prior to registering upon the laser target 407. In a less sensitive deployment of the laser, no laser reflector 405 is used. Multiple sets of laser emitters 403, laser reflectors 405 and laser targets 407 can be used to monitor the distortion of different portions of the housing 125, or the beam from the laser emitter 403 can alternatively be split, using a partially reflective mirror (not shown), and then directed to different laser reflectors 405 mounted on different parts of the housing 125 for sensing by different laser targets 407, each directed to monitoring distortion of a different part of the housing 125. In the embodiment of Figure 6, all of the components are mounted on the housing 125 or on other parts of the turbine 101 itself.

A more preferred distortion-monitoring arrangement includes the apparatus of Figures 7 and 8, wherein the laser emitter 403 and a position sensitive laser target 407 are affixed to a stationary portion of the turbine on or near an inlet bearing 415 of the turbine 101 (see Figure 6), and an outer ring member 417 is provided.

Three or more members 421 are spaced substantially equally over the ring member 417's inner circumference and extend radially inward, defining a central opening which is large enough to accommodate the outer ring's placement about the gas turbine housing 125 and in position to indicate wet compression-related deformation of the housing 125. A preferred placement in this regard will have the outer ring member 417 mounted about the end of the compressor case or on the combustor shell 422. The topmost of the inwardly- extending members 421 is equipped at its inner end 423 with a socket element 425 of a ball and joint socket 427, the corresponding ball element 427 being defined atop the housing 125. The remaining inwardly-extending members 421 are equipped at their respective inner ends 429 with low friction contact components 431 (for example, transversely disposed roller bearings or self-lubricating high temperature bronze sleeves - the latter being shown for purposes of illustration in Figures 7 and 8), for being biased into contact with, and moving over, flat receiving surfaces 433 defined on the turbine housing 125 and which are perpendicular to the longitudinal axis of the turbine 101. The three or more members 421 together define a common plane which is offset from the center of mass of the ring member 417, so that the weight of the ring member 417 is supported on the ball element 427 and the low friction contact components 431 are biased member 417 and by a compensating movement of the socket element 425 on the ball element 427 into contact with the flat receiving surfaces 433. Finally, a laser reflector 405 is positioned on the outer ring member 417, and as the low friction contact members 431 are biased into contact with the flat receiving surfaces, the reflector 405 defines a line of sight with the laser emitter 403 and with the position sensitive laser target 407. This arrangement on the whole, it will be appreciated, allows for some movement and expansion of the housing 125 which are unrelated to the unequal provision of liquid water to the working fluid acquired by the compressor of the turbine, while maintaining an appropriate reference plane relative to the turbine's housing 125 and enabling the detection of wet compression- related distortions of the turbine housing 125, as distinct from these unrelated movements which may occur especially in larger, newer turbines with more flexible or thinner housings 125. Ideally, the beam from laser emitter 403 is projected parallel to the center line of the turbine's rotor, though in practice useful and meaningful data can be obtained even with a significant departure from the ideal alignment, for example, by 30 degrees.

Parenthetically, while the use of laser emitters, reflectors and position sensitive targets according to the various embodiments and arrangements described herein provides a convenient means for monitoring for deflection of the turbine housing, it will be appreciated that other devices could be so employed, for example, a series of proximity sensors placed strategically on and about the turbine to sense wet compression-related deformation of the turbine's housing.

A final matter addressed in the prior, published PCT application, and which bears repeating here, concerns the different compressor cleaning needs and circumstances associated with the use of wet compression methods and apparatus generally. As a consequence of the levels of water addition which may be employed in the context of the present invention, and as precipitates are deposited on compressor elements by evaporation of the added liquid water, these deposits have been found to occur beyond the first several rows of compressor blades that are presently cleaned by conventional, impact-based methods and systems. Moreover, certain organic fouling deposits (diesel smoke, tars) that may otherwise be present through normal operation of the turbine can be displaced farther back in the compressor section because of wet compression, and these can be made even more difficult to remove from the compressor section as a result. for "OFF-LINE GAS TURBINE COMPRESSOR CLEANING PROCESS", filed as a continuation-in-part of United States Application Serial No. 08/837,192 on October 13, 1999, an off-line cleaning method is described which is especially suited for cleaning wet compression-related deposits from a gas turbine compressor.

According to this off-line cleaning method, on those turbines which are equipped with a turning gear and electric starter motor as opposed to a pneumatic starter capable of maintaining a low revolution rate of rotation (including virtually all large, land-based turbines but excluding some aeroderivative turbines), the turbine in question is initially brought off-line and cooled in a conventional manner, being taken from a turning gear rate of rotation of typically 1 to 2 revolutions per minute (or less) up to a crank speed for spin- cooling, and then allowed to spin down again to a turning gear rate of rotation pending verification that the turbine has been adequately cooled for a subsequent foam cleaning step. Thereafter: a) a foam cleaning composition is introduced into the compressor (as a foam, or as a liquid composition which forms a foam in the compressor upon introduction into the compressor) at a higher rotor speed but at less than conventional spin crank rotation rates, the desired speed being traversed during spin-down; b) the foam cleaning composition is maintained in contact with the compressor internal surfaces sought to be cleaned through a soak interval carried out at essentially a turning gear rate of rotation; c) the rotor speed is increased to a speed which is at least great enough to draw a rinse medium into the compressor but which is less than the spin crank speed of the turbine; and d) fouling deposits made ready for removal from the compressor through the agency of the foam cleaning composition are rinsed from the compressor, by supplying the rinse medium to the compressor when the rinse-suitable rotor speed is traversed during spin-down.

On those turbines which have been equipped with pneumatic starters or which are not otherwise operated with a turning gear to address rotor sagging concerns when the allow introduction of the foam cleaning composition, and then a foam cleaning composition is introduced into and distributed through the compressor(s) of the turbine at a suitably low rate of rotation. The foam cleaning composition is allowed to soak in place for a soak interval, typically without rotation of the rotor, and the fouling deposits rinsed from the compressor(s) while maintaining a suitable rotor speed.

Further, where organic fouling deposits are a significant source of performance losses, preferably the off-line cleaning process as just summarized is accompanied by an online process to volatilize and/or crack the organic fouling deposits by periodically removing or stopping the water addition to the compressor section and continuing to operate the turbine without the water addition.

This much having been described now by way of background, the manner in which wet compression can be employed to advantage in the context of the present invention may be shown. As an overall observation, the manner in which wet compression technology can best be used will depend upon what types of emissions controls apply, where current emissions stand with respect to those controls and what types of generation assets are available. Nitrogen oxide (or NO_x) and carbon monoxide emissions limits are especially of interest for purposes of the present invention, and may be expressed or applied on a volumetric or concentration basis (parts per million by volume) or a mass basis (usually in the form of an annualized average mass limit and an hourly maximum limit). These limits may variously apply on a single point source basis or on a site-wide basis where more than one point source is found, or a combination of single point sources and overall site-wide controls can apply. Understanding, however, that: a) wet compression fundamentally enables on one level the production of a given quantity of electric power with the combustion of lesser amounts of carbon- based fuels - thus enabling a corresponding reduction in emissions of those combustion products whose levels are tied to the amounts of fuel combusted and whose emissions may be subject to imposed limits, for example, carbon dioxide, particulates, sulfur oxides; and in the compressed air exhaust from the compressor section) for the formation of nitrogen oxides while also affecting flame temperature in the combustion section - a reduction in flame temperature is desirable for reducing NO_x formation but may contribute to increased production of carbon monoxide as a product of incomplete combustion,

one skilled in the art should be well able with the guidance of the illustrative scenarios below to use wet compression effectively to achieve a desired level of power production while operating within applicable emissions constraints. For clarity, the effects of the various courses of action or modes of operation described in the scenarios below on emissions of carbon dioxide, particulates and sulfur oxides - essentially those combustion products whose emissions are affected directly by the quantities of fuel combusted - are not specified, in the expectation that it will be understood that any mode of operation entailing a reduction in fuel consumption per unit of power produced will be understood by those skilled in the art, as beneficially enabling a reduction in the emissions of these combustion products.

Scenario I - Stand-Alone Gas Turbine, or Single-Point Source-Emission-Regulated Turbine in Multi-Turbine Setting

In this operating scenario, the applicable emission limits and desired level of power production are concerned with a single, stand-alone turbine, or a desired overall level of power production is to be obtained from a plurality of gas turbines, with the emissions controls being applicable however on a turbine by turbine basis.

Sc. I, Option A - Standard Burn Combustors and No Existing NO_Y Control Technology

For a turbine equipped with standard burn ratio combustors and not employing steam or water injection to the combustors, for example, power output and efficiency may be increased and NO_x emissions can be reduced on a volumetric and mass basis (generally with some increase in carbon monoxide emissions) through the use of wet compression.

By following one of several possible courses of action, a reduction in NO_x emissions can be accomplished while maintaining a constant level of power generation. For turbines involve throttling the inlet guide vanes to reduce the airflow into the combustion section, while maintaining the firing temperature and using wet compression to offset the loss of power production capacity normally associated with throttling the inlet guide vanes. Compressor stationary and rotating blade wear may be more significant with this mode of operation.

Another alternative is to reduce the firing temperature while using wet compression, with the variable inlet guide vanes wide open. In this circumstance, NO_x emissions decline again on both a mass and volumetric basis, while CO emissions can be expected to increase on a volumetric basis and on a mass basis.

Alternatively, and provided the applicable carbon monoxide limits are sufficiently removed from the current actual carbon monoxide emissions levels, the variable inlet guide vanes can be throttled to an extent short of that required for fully achieving the desired NO_x reductions, and the turbine can also be underfired while employing a corresponding amount of power augmentation by wet compression.

Where the turbine in question is not equipped with adjustable inlet guide vanes, of course, the option that is available is to reduce the firing temperature while using wet compression, in keeping with the mode presented two paragraphs previous to this paragraph.

Sc. I, Option B - Standard Combustors, Equipped for Steam or Water Injection to Combustors for NO_* Control

For this case, at a fixed ratio of steam to fuel injection, power output and efficiency are increased, and NO_x emissions are reduced (with an increase in CO emissions), through the use of wet compression. Carbon monoxide emissions can be reduced (with some sacrifice in NO_x reductions) through reducing steam injection, and with sufficient reductions in steam injection, a reduction of both NO_x and CO emissions (as compared to initial operation with steam injection and no wet compression) can be achieved with minimal effect on (the increased) power and efficiency. Compared to direct steam or water injection, water mass added to the turbine per unit of fuel, by wet compression, is more effective in increasing power generation from the turbine, and is less effective in suppressing NO_x emissions. Water added by wet added by direct steam or water injection. Alternately, steam or water injection may desirably be employed to further reduce NO_x emissions.

At a minimum, steam or water injection may be employed to provide a redundant level of NO_x control for lower ambient temperature operation.

A reduction in NO_x emissions can be accomplished while maintaining a constant level of power generation from the turbine, by reducing steam or water injection (with an attendant reduction in power generation capacity at a given firing temperature), implementing wet compression (with an increase in power output and efficiency) and throttling the inlet guide vanes. In this manner fuel efficiency may be maintained or improved (compared to steam injection with no wet compression).

Underfiring in this example will enable a further reduction in NO_x emissions, but CO emissions can be expected to increase to a degree.

Where the turbine in question is not equipped with adjustable inlet guide vanes, of course, the option that is available is to reduce the firing temperature with a reduction in steam or water injection while using wet compression.

Sc. I, Option C - Low NO_x Combustors as NO_x Control Means

In this scenario, a principal concern is whether wet compression might have the effect of altering the fuel to oxygen ratio in the combustors and cause instabilities in combustion or give rise to increased emissions, particularly of carbon monoxide. An increased level of power generation, and a reduction in NO_x and CO emissions per unit of power generation (but maintained within volumetric and mass limits), can be realized for this arrangement by enriching the fuel in the fuel to air ratio with the implementation of wet compression.

A reduction in NO_x and CO emissions per unit of power generation (but maintained within volumetric and mass limits) can be accomplished while maintaining a constant level of power generation from the turbine, by appropriately throttling the inlet guide vanes in conjunction with the implementation of wet compression. In this manner fuel efficiency may be maintained or improved as compared to operation without wet compression. The common theme in each of the following arrangements under this basic operating scenario is to augment the level of power production from the most efficient point sources/assets (on an emissions basis, and generally but not necessarily also on a fuel consumption basis, dependent on which emissions are of most immediate concern to the operator - whether of NO_x and/or CO, or of those products tied to fuel consumption like CO , particulates, sulfur oxides) while correspondingly diminishing the level of power production from the least efficient assets. Ideally, power production from the most efficient asset or assets will be augmented to an extent whereby the least efficient asset or assets can be taken off-line or used to a minimal degree to preserve operability of the assets.

Sc. II, Option A - Power Generation Assets Are Plurality of Gas Turbines

In this situation, preferably wet compression power augmentation technology as described in the various related applications will be used on one or more of the more efficient gas turbines (where the assets comprise several different turbine types), and output on less efficient gas turbines will be reduced by throttling the adjustable inlet guide vanes of turbines equipped with such devices and/or by reducing the firing temperature (with downward adjustments in the exhaust control temperature or reference speed) of turbines without adjustable inlet guide vanes. The same fuel may be used in this situation from an overall perspective but more effectively relative to emissions of regulated combustion gases, or an overall reduction in fuel consumption can be achieved if the incremental heat rate of the segment of power production associated with wet compression is less than the heat rate increase of the turbine or turbines whose output is reduced. Again, preferably the degree of augmentation achieved on the most efficient turbine or turbines will be sufficient to take off-line entirely one or more of the least efficient turbines.

Sc. π. Option B - Power Generation Assets Are Combination of HRU-Equipped Gas Turbines, Stand-Alone Steam Boilers and Steam Turbines

In this asset arrangement, the least efficient assets are the stand-alone steam boilers. Augmenting one or more of the gas turbines to an extent whereby one or more of the standalone steam boilers can be removed from service should provide a decrease in overall fuel consumption. A factor to be considered in this scenario is that on a gas turbine with a heat associated with a mass flow increase from the gas turbine exhaust with wet compression. The additional steam generation from the HRU will allow additional fuel savings and/or higher steam turbine power generation, which can then be used as an offset against less- efficient assets.

Sc. π. Option C - Power Generation Assets Are Combination of Gas Turbines, Duct-Fired Heat Recovery Units (HRUs) and Steam Turbines

Duct-fired HRUs may be employed, in a first circumstance, wherein the exhaust gas from the gas turbines in question is not sufficient for creating the high pressure steam desired to supply the operator's steam turbines. In this situation, the reduction in emissions associated with the increase in power, efficiency and steam production made possible through the use of wet compression more than offsets the increased emissions resulting from the increase in fuel consumption associated with the use of the duct-fired HRUs. In a second circumstance, wherein the exhaust gas from the gas turbines in question is sufficient to produce the steam pressure desired to supply the operator's steam turbines, duct burners may yet be employed to produce additional steam to increase power generation via the operator's steam turbines. In this situation, the reduced emissions enabled through a wet compression-related increase in power, efficiency and steam production are combined with reduced emissions from reduced fuel consumption of the duct-fired HRUs.

The effects of wet compression on NO_x and carbon monoxide emissions in certain operating contexts are further shown by the following illustrative, non-limiting Examples:

Example 1 On successive days, emissions tests were conducted on an industrial gas turbine

(having wet media inlet evaporative cooling) manufactured by the former Westinghouse Electric Corporation, Pittsburgh, Pennsylvania under the model designation W501-A, and which was equipped with a spray rack group assembly including five individual spray racks for wet compression power augmentation according to the teachings of the prior, copending applications. The gas turbine used a standard combustor design from Westinghouse.

During the first day of testing, carbon monoxide and NO_x emissions were measured according to standard methods prescribed by the United States Environmental Protection instance, and with one spray rack engaged in a second instance. During the second day, successive one hour runs were conducted with two racks of spray nozzles operating and then with three racks of nozzles operating, while on the third day tests were conducted on the one hand with four spray racks working and then with all five racks fully engaged. The results of the first day's testing are shown in Table 1 as follows:

Table 1

^a) PPMV is parts per million, volumetric basis (dry). ^b) Corrected to 15 percent oxygen c) Combined Cycle Output from Steam Helper Turbine and Gas Turbine combination.

The results of the second day's testing are shown in Table 2 as follows:

Table 2

Table 3

As can be seen from these tables, as additional liquid water was added to the working fluid acquired by the compressor, even as the turbine output was increased NO_x emissions were progressively reduced. Carbon monoxide emissions were increased.

Example 2

A Westinghouse W-501D5 heavy duty gas turbine (again equipped with wet media inlet evaporative cooling), using standard burn ratio combustors and steam injection to the combustors for NO_x control, was equipped with a wet compression system as described in United States Patents No. 5,867,977 and 5,930,990. Fuel consumption, steam consumption and emissions of NO_x and CO were measured as a function of power generation from the turbine, following the teachings of Scenario I, option B above. Results are shown in Table 4, and clearly demonstrate the benefits of the present invention related above:

Table 4

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Claims

1. A process for achieving a reduction in emissions of combustion products from power generation apparatus including an industrial gas turbine or plurality of such turbines while providing a desired level of power production from such apparatus, comprising displacing an increment of power generated by such apparatus with at least an equivalent increment of power provided by the application of wet compression in one or more of said gas turbines.

2. A process as defined in claim 1, wherein the power generation apparatus consists of a plurality of gas turbines subject to an overall emissions control, and the process for reducing emissions from the plurality of gas turbines includes adding one or more increments of wet compression capacity on one or more of the more efficient of said plurality of gas turbines, and reducing power production from the least efficient turbine or turbines of said plurality of gas turbines.

3. A process as defined in claim 2, wherein wet compression is utilized to an extent on the more efficient turbine or turbines of said power generation apparatus whereby one or more of the least efficient such turbines can be shut down.

4. A process as defined in claim 1 , wherein the power generation apparatus comprises a combination of one or more gas turbines with one or more additional, less emissions-efficient power generation devices, which combination is subject to an overall emissions control, and wherein the process of reducing emissions from said apparatus includes augmenting the power generation capacity of at least one of the gas turbines through wet compression to an extent whereby a less emissions-efficient power generation device can be shut down.

5. A process as defined in any one of claims 1 through 4, wherein a process control computer is employed to alter the power generation capacities associated with a plurality of single point emissions sources included within the power generation apparatus and for optimizing the emissions profile produced by said power generation apparatus, responsive to a change in the emissions produced from said power generation apparatus.

6. A process for achieving a reduction in regulated emissions of nitrogen oxide gases or carbon monoxide or both from a gas turbine employing standard burn ratio combustors and steam or water injection to such combustors while also increasing the net power output from said turbine, comprising removing at least a portion of the steam or water formerly injected to the combustors, and employing wet compression to an extent whereby the net power output from the turbine is increased.

7. A process as defined in Claim 6, wherein emissions of both nitrogen oxide gases and carbon monoxide are reduced on a volumetric basis as well as on a mass basis.

8. A process for reducing emissions of both nitrogen oxide gases and carbon monoxide on a mass basis from a gas turbine equipped with lean burn ratio combustors and variable inlet guide vanes while maintaining a desired constant level of power generation from such gas turbine, comprising throttling the inlet guide vanes while employing wet compression power augmentation to offset the reduction in power generation capacity otherwise occurring as a result of throttling the inlet guide vanes.