CA1245282A - Steam turbine load control in a combined cycle electrical power plant - Google Patents

Abstract

ABSTRACT OF THE DISCLOSURE
In a cogeneration system embodying a heat recov-ery steam generator assisted with a gas turbine and an afterburner for supplying steam and a steam turbine sup-plied thereby, substantial change in the load plant is supported by control of the afterburner and of the gas turbine to ease the change of load on the steam turbine from its initial value to its targeted value.

Description

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l 50,086 IMPROVED STEAM TURBINE LOAD C~NTROL IN A
CO~BINED C~CLE ELECTRICAL POWER PLANT

BAC~GROUND OF THE INVENTION
The present invention relat~s to a combined cycle electric power plant in general, and more particularly, to coordinated control, in such a plant, of the steam turbine, the gas turbine and associated afterburner for loading, or unloading, the steam turbine.
Effecting load changes in a combined cycle power plant by steam turbine throttling is well known. By "throttling" is meant to control both the throttling valves and the governor valves for the admission of steam, taking into account steam admission in termæ of flow, pressure and temperature so as to change speed and/or load on the steam turbine.
For the purpose of disclosing a digital electro-hydraulic (DEH) control system suitable for controlling thethrottle valves and the governor valves of a steam turbine plant in a combined cycle plant, reference is made to U.S.
Patent Nos. 4,220,869 (Uram); 4,201,924 (Uram) and 4,222 J 229 (Uram), issued September 2, 1980; May 6, 1980 and September 9, 19~0, respectively.
In the design of modern electric power plants, it is a significant object to achieve the greatest efficiency possible in the generation of electricity. To this end, steam generators are designed to efficiently generate heat and the extracted heat is used to convert a fluid, such as water, into superheated steam at a relatively high ~2 ~ 2

2 50,086 pressure. Such steam generators have been incorporated into combined cycle electric generating plants embodying both gas and steam turbines, the exhaust gases of the gas turbine being used to heat water into steam transferred to the steam turbine. Typically, steam generators include a water heating section or economizer tube, a high pressure evaporator tube and a superheater tube, whereby water is gradually heated, while increasing levels of pressure are attained to provide, from the superhea~er tubine, superheated s-~eam which is supplied to the steam turbine. A condenser is associated with the steam turbine to receive the spen~ steam and for converting it into water condensate fed back to the steam generator.
In a combined cycle electric power plant, the steamt~rbine is combined with a gas turbine whereby the heated exhaust gases of the gas turbine) otherwise lost to the atmosphere, are used to heat the circulated fluid and to convert it into steam to drive the steam turbine. As a result, the heat contained in the gas turbine exhaust gases is effectively utilized. ~n afterburner is also associated with the exhaust of the gas turbine to additionally heat the gas turbine exhaust gases, whereby the heat required to generate steam to meet load requirements is provided. When-ever, under conditions of relatively high load, the heat of the gas turbine exhaust gases is insuficient to satisfy the steam requirements, the afterburner is turned on to heat further the gas turbine exhaust gases.
In combined cycle operation, there is a particu-lar need to coordinate the control of ~he separate gas and steam turbine and afterburners. It is desired that the steam turbine ~e operated in what is called a "follow mode"
whenever the plant is supplying electrical power to a load, such that the steam turbine follows the gas turbine, with the afterburner positively following the gas turbine. In this l'follow mode", the steam produced by .

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3 50,086 the gases exhausted from the afterburner is used in total by the steam turbine. In distributing load among the operating turbines, and in determining the load change rates for the respective turbines while responding to plant demand changes, control must be coordinated so as to optimize efficiency and response time. Further, a control system is required which can automatically determine which turbine and/or afterburner is in condition for coordinated control, or which has been selected for coordinated control, and to proceed with coordina-ted control while elements are simultaneously under a lowerlevel of control. Moreover, coordinated control flexibility is desirable through startup, synchronization, and throughout the full range of plant loading.
Load distribution optimization under coordinated control has been described in U.S. Patent No. 4,222,229 (Uram). This patent shows, besides automatic or coordinated control, by the operator with the assist of a programmed digital computer, of the steam turbine for startup and auto-matic loading or unloading, the use of bypass steam flow to the desuperheater and condenser from the inlet steam flow to accommodate load changes. Generally, the total plant power is controlled by controlling the operating level of the turbines and the afterburners, but the steam turbine goes into the "follow mode" after the steam bypass valves are closed and ~he steam turbine inlet valves are fully opened. Then, the steam turbine produces power at a level which depends upon steam conditions at the heat recovery steam generator output, conditions which are depending upon the input of heat from the gas turbine and/or the afterburner associated thereto. Control of such steam conditions is effected by controlling the fuel valves on the gas turb;ne and/or the afterburner.
It is also disclosed by U.S. Patent No. 4,201,924 to control a combined cycle electric power plant by main-taining a predetermined steam pressure as a function ofsteam flow, using the bypass valve, and having the control ':' 1~5~B~2 ~ 50,086 valve of the turbine respond to the speed/load demand only, except when the bypass valve is closed and the rate of gener-ation of steam has become insufficient to maintain such pre-determined pressure flow.
In a combined cycle plant such as described in the aforementioned U.S. Patent No. 4,201,924, a steam turbine works with two heat recovery steam generators, which involves two gas turbines and two respective afterburners. In such a plant, the turbine operates normally with its steam inlet control valves wide open without throttling, and with the load being governed by the rate of steam generation. The steam pressure is permitted to slide within certain limits depending on the loading of the steam turbine, and accepts whatever steam is generated.
The operation of a plant of this type is limited to a minimum steam pressure and flow because of the requirements of the heat recovery steam generators, and it is further limited to a maximum velocity of steam to minimize erosion of the steam generator tubes and to reduce the probability of water carryover into the turbine, which could damage the turbine blades. At the same time, it is desirable to minimize throttling of the steam turbine control valves in order to maintain optimum plant efficiency and stability. This presents certain problems in that the maximum steam velocity which can be permitted depends upon the steam pressure and the rate of steam generation. For example, with both heat recovery steam generators in service, the steam turbine may be able to maintain the minimum required pressure with its control valves open, provided the steam bypass valves are closed. This is true across the entire load range. However, with only one exhaust heat recovery steam generator in service, throttling of the steam turbine governor valves is required to maintain the minimum required pressure in order to limit the maximum steam velocity and satisfy drain separation pressure flow requirements. The amount of throttling may vary. For example, with one generator in service, the system can operate as low as in the neighborhood of 500 pounds ~
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50,086 operate as low as in the neighborhood of 500 pounds/pressure for a steam flow or load of approximately 70% maximum, but it must operate at 600 pounds pressure for a steam flow or load of approximately 80~, maximum if the steam velocity is to be S maintained below a predetermined maximum.
In such a plant, the rate of steam generation can change rapidly and substantially, for instance, in the event the rate of steam generation either increases, or decreases rapidly, it is desirable that the pressure/flow relationship be changed without creating excessive pressure for a particular loading, or decreasing pressure, thereby increasing the proba-bility of water carryover to the turbine. In starting up a plant of the type described, it is desirable tG be able to control the steam inlet, or control valves of the steam turbine, independently from the pressure/flow relationship. This can be accomplished by bypassing the generated steam to the condenser, and then, as the steam turbine control valve is opened to either accelerate the turbine or increase the load, and to modulate the bypass valve in order to maintain the proper pressure flow relationship to the turbine. Any minimum pressure flow relation-ship control, after the bypass valve is closed, can be maintained by the steam turbine control valves. Thus, the maximum velocity of the steam can be limited while still maintaining optimum efficiency. During a decrease in loading or speed, it is desir-able that none of the steam be bypassed to the condenser, unlessthe pressure/flow relationship becomes excessive. Therefore, it i.s desirable for the control valves to maintain control of the pressure/flow relationship with the bypass valve closed.
A sudden decrease, or increase, in pressure, depending upon the type of contingency, can trip the steam generator, or the turbine, unless such condition is remedied quickly by either preventing or causing a bypassing of the steam to the turbine. Therefore, the bypass valve should be able to respond quickly to such change regardless of the particular pressure/
flow condition prior to such change.

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6 50,086 When a transfer of control of the pressure/flow relation-ship occurs at a particular transition point, the control system would not necessarily react quickly enough for certain contingencies.
When the bypass valve is closed, any further valve restriction to maintain a proper minimum pressure/flow relation-ship must of necessity be controlled by the control valve, or by the rate of steam generation. Even under these conditions, the bypass valve is arranged to respond quickly to contingencies requiring responses.
Also, in situations of stand alone steam turbine electric power plant of the sliding pressure type fluctuating between a low and a high steam generation rate, which are often unattended, a fast steam pressure/flow control is desirable.
In the normal operating mode of the steam turbine, the controller follows steam flow by opening the throttle valve so as to set pressure at a minimum on initial loading.
The load function generator establishes a load setpoint cor-responding to the highest allowable load. These modes andconditions of operation are initially established by the plant unit master (PU~) controller of the total plant, for all the turbines, which supervises and controls the plant through loading and unloading. As earlîer mentioned, once a certain level of megawatts has been established for the steam turbine, the controller is set to the follow mode, e.g., one for which the steam turbine in taking all the steam it can get from the heat recovery steam generator, with the throttle fully opened under steam turbine pressure/flow criteria. In this mode, the system automatically takes care of load transients, of steam inlet fluctuations.
The present invention addresses itself to the problem of establishing a new level of megawatts on the steam turbine. It is desirable to reach the new demand level as quickly as possible. However, with the steam turbine, as well as with the heat recovery steam generator, load changes cannot be accomplished at the fastest ~5~3Z
7 50,086 desirable rate. One of the main limitations, besides the '. limitations for the steam at the inlet to attain ne~"
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conditions of flow, pressure and temperature, is the steam turbine which can be exposed to unacceptable stresses in the rotor, the inner casing, under rapid changes of temper-ature. For this reason, once a new load has been recog-nized as the setpoint for the steam turbine controller, the operator will usually set a predetermined rate acceptable for the operation. A ramping setpoint for load changes on the steam turbine is paralleled in a combined cycle with ramping setpoints for the gas turbine and for the after-burner, respectively. It is the purpose of the present invention to overcome these limitations so as to obtain a quick adjustment of the steam turbine to new loading, or unloading, requirements in the operation of a combined cycle electric power plant.
Fast valving of a steam turbine is not new. See for instance U.S. Patent No. 3,657,552~where this is done in an emergency situation,,~not to establish a new level of operation. Fast valving is also disclosed in U.S. Patent No. 3,998,058 under conditions where there is a threat to stability.
While the turbine at a given load level normally follows the boiler, or rather is set to follow the set conditions of the inlet of steam, the boiler has to be set independently from the turbine, thereby imposing limita-tions due to boiler capacity or steam delivery. When it is 5y5~e~required to adjust the t-~b~e- to meet a new load demand, the turbine will no longer be able to follow the boiler and maintain the maximum possible admission of steam under conditions of flow, pressure and temperature to generate a maximum of megawatts in the conversion from steam to electrical energy. This is coupled with the difficulty of going to such new load level as quickly as possible.

8 50,086 SUMMARY OF THE INVENTION
The operator, or a remote load dispatch system, sets a load change which is in excess of what the combus-tion and steam turbines would normally allow, and this is made possible by concurrently changing fuel firing on the afterburner or both the afterburner and the combustion turbine of the steam ~enerating system, thereby to permit steam temperature ramping on the steam turbine at an accept-able rate. With this approach, sliding pressure steam turbine operation is effected to accommodate large ranges in the mega-watt demand without excessive changes in the steam temperature.
Upon a sudden reduction of the load demand, in the prior art, such reduction is first accommodated by reducing steam flow to the turbine, by simultaneously modulating the steam turbine governor valve toward its closed position and modulating the steam turbine bypass valve toward the open posi~
tion. This is very inefficient since bypassed steam is wasted.
According to the present invention, lnstead, for a load decrease the afterburner fuel flow and the gas turbine load are ramped downward at their normal rate and the steam turbine power and steam flow are reduced under the plant unit master (PUM) control, both actions concurring in decreasing power due to both the decreased steam turbine steam flow and reduced steam production resulting from reduced temperature 2S at the inlet of the heat recovery steam generator under reduced afterburner fuel flow.
For a load increase, the afterburner and the gas turbine loads are ramped upward, thereby allowing steam flow at the inlet of the steam turbine to be increased while the steam turbine inlet valves reach their wide open position and in the follow mode there is gain load as a result of taking up steam at increased temperature.

~5~82 9 50,086 Under load decrease should the steam turbine resume its follow mode at the new load level, the efficiency of operation will no longer be optimum as it was initially at the previous level. Therefore, also according to the present invention, the afterburner and the gas turbine are further controlled to attaîn the optimum by reducing the participation of the afterburner and maximizing the utilization of fuel in the gas turbine, at which t;me the new steady-state condition will have been reached for the plant. Thereafter, the follow mode is resumed at the new target level to take up normal transient changes, with bypassing and throttling.
The invention allows a fast rate of unloading and subsequent reloading without exceeding rotor stress limits.
For the purpose of describing the plant unit master (PUM) control system, the following additional patents are of interes~:
U.S. Patent No. 4,031,404 (Martz and Plotnic~) which discloses control of the afterburner and the gas turbine of a combined cycle electrical power plant to improve ~0 temperature control of the steam generated.
U.S. Patent No. 3,973,391 (~eed and Smith) which discloses inlet guide vane control for the air intake and fuel valve control for the afterburner and gas turbine of a combined cycle electrîcal power plant.
U.S. Patent No. 3,953,966 (Martz and Plotnick) which shows the heat supply from the gas turbine reduced by placing a reduced load level signal thereon and by terminating the flow of fuel to the afterburner. This is there for the purpose of controlling the heat recovery steam generator of a combined cycle electrîc power plant to obtain dry steam.
U.S. Patent No. 3,943,0h3 (Martz) which in a combined cycle electrîc power plant provides for coordi-nated fuel transfer between gas turbîne and afterburner.

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50,086 U.S. Patent No. 4,010,605 (Uram) which describes the plant unit master (PU~) control for startup, shutdown synchronization and loading in a coordinated manner.
U.S. Patent No. 4,184,324 (Kiscaden, Martz and Uram) which shows coordinated gas turbine control.
U.S. Patent No. 3,934,128 (Uram) which describes digital computer controlled throttle and governor valves of a steam turbine for speed and load control.
U.S. Patent No. 4,267,458 (Uram and Giras) which shows digital computer controlled steam turbine for adjust-ing steam flow and pressure at the inlet to meet speed and load requirements.
Finally, U.S. Patent No. 3,939,328 (Davis) is cited to illustrate adaptive process control providing a ramp at a predetermined rate for applying a reference to a controller in a control process involving DEH speed/load control, follow mode, coordinated control, constant throttle pressure steam operation, sequential governor valve operation at an appropriate load level and a plant unit master (PUM), the illustration being :Eor boiler control and steam turbine control.
BRIEF`D~SCRIPT`ION OF`TME DRAWINGS
Figure 1 is a block diagram of a combined cycle electrical power plant of the prior art;
Fig. 2 shows the lines and valves of the fluid system of the steam turbine of Fig. l;
Fig. 3 shows the organization of a coordinated control system for the steam turbine and the gas turbine and afterburners of Fig. l;
F;gs. 4A, 4B and 4C are curves illustrating the operation of the steam turbine load control system according to the invention; and Figs. 5A, 5B and 5C are circuitry typifying the preferred embodiment of the invention.

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ll 50,086 DESCRIPTIOM OE T~E PREFERRED EMBODIMENT
Referring to Fig. 1, there is shown a functional block diagram of a combined cycle electric power generating plant. Reference numeral lO is to identify the combined cycle plant as a whole. As such, the plant 10 includes a first gas turbine 12 (sometimes referred to as "gas turbine No. 1", or CT1) which drives a first electric generator 13.
Fuel is supplied to the gas turbine 12 by way of a fuel control valve or throttle valve 14. Air enters the gas turbine 12 by way of a variable inlet guide vane (IGV) mechanism 15 which controls the degree of opening of the turbine air intake and which is used to adjust air flow during the startup phase and to increase part load effi-ciency. The fuel supplied by the throttle valve 14 is burned in the gas turbine 12 and the resulting high temper-ature exhaust gas is passed through an afterburner 16, then through a heat recovery steam generator 18, and is thereaf-ter exhausted into the atmosphere.
Heat recovery steam generator 18 (sometimes referred to as "heat recovery steam generator No. l", or HRSG1) includes boiler tubes which are heated by the gas turbine exhaust gas passi.ng through the steam generator 18.
Afterburner 16 (ABl) includes a burner mechanism for further increasing the temperature of the gas turbine exhaust gas before it enters the steam generator 18. Fuel is supplied to the burner mechanism in the afterburner 16 by way of a fuel control valve or throttle valve 19. The primary heat source for the steam generator 18 is the gas turbine 12, the afterburner 16 being in the nature of a supplemental heat source. Typically, 80% of the fuel is used in the gas turbine 12 and 20% is used in the after-burner 16.
The combined cycle plant lO further includes a second gas turbine 22 (sometimes referred to as "gas turbine No. 2", or CT2) which drives a second electric generator 23. Fuel is supplied to the gas turbine 22 by way of a fuel control valve or throttle valve 24. Air 12 50,086 enters the gas turbine 22 by way of a variable inlet guide vane mechanism 25 which is used to adjust air flow during turbine startup and to increase part load efficiency. The fuel supplied to throttle valve 24 is burned in the yas turbine 22 and the resulting high temperature exhaust gas is passed through an afterburner 26 and a heat recovery steam generator 28, thereafter exhausted into the atmosphere.
Heat recovery steam generator 28 (sometimes referred to as "heat recovery steam generator No. 2", or HRSG2) includes boiler tubes which are heated by the gas turbine exhaust gas passing through the steam generator 28.
Afterburner 26 (AB2) includes a burner mechanism for further increasing the temperature of the gas turbine exhaust gas before it enters the steam generator 28. Fuel is supplied to the burner mechanism in the afterburner 26 by way of a fuel control valve or throttle valve 29. The primary heat source for steam generator 28 is the gas turbine 22, the afterburner 26 being in the nature of a supplemental heat source for providing supplemental heating when needed.
A condensate pump 30 pumps water or condensate from a steam condenser 31 to both of the steam generators 18 and 28, the condensate flowing to the first steam generator 18 by way of a condensate flow control valve 32 and to the second steam generator 28 by way of a condensate flow control valve 33. Such condensate flows through the boiler tubes in each of the steam generators 18 and 28 and is converted into superheated steam. The superheated steam from both steam generators 18 and 28 is supplied by way of a common header or steam pipe 34 and a steam throttle valve or control valve 35 to a steam turbine 36 for driving the steam turbine. Steam from the first steam generator 18 flows to the header 34 by way of a steam pipe 37, an isolation valve 38 and a steam pipe 39, while steam from the second steam generator 28 flows to the header 34 by way 13 50,086 of a steam pipe 40, an isolation valve 41 and a steam pipe 42.
Steam leaving steam turbine 36 is passed to the condenser 31 wherein it is converted back into condensate.
The condensate is pumped back into the steam generators 18 and 28 to make more steam. Steam turbine 36 drives a third electric generator 44.
A steam bypass path is provided for diverting desired amounts of steam around the steam turbine 36. This steam b~pass path includes a steam turbine bypass valve 45 and a desuperheater 46, the output side of the latter being connected to the condenser 31 by way of a pipe 47. A vent valve 48 is provided for the first steam generator 18, while a vent valve 49 is provided for the second steam generator 28.
The operation of the combined cycle electric power generator plant 10 is controlled by a control system 50~ via control signal lines 51. The control system 50 offers a choice of three different control operating levels providing different degrees of automation. From highest to lowest in terms of the degree of automation, these control operating levels are: (1) plant unit master (PUM) control;
(2) operator automatic control; and (3) manual control.
The control system 50 i 5 constructed to provide complete and safe operation of the total plant 10~ or any part thereof.
When operating at the highesk level of control, namely, at the plant unit master (PUM) control level, the control system 50, among other things, automatically coordinates the settings of the fuel valves 14, 19, 24 and 29, the inlet guide vanes 15 and 25 and the steam turbine throttle and bypass valves 35 and 45 to provide maximum plant efficiency under static load conditions and optimum performance during dynamic or changing load conditions.
To summarize, Fig. 1 shows in block diagram a combined cycle electrical power plant such as described in U.S. Patent Nos. 4,184,324; 4,333,310 and 3,953,966 x~
14 50,086 Two heat recovery steam generators (18, 28) have each a gas turbine (19, 22) and an afterburner (16, 26) supplying hot gases which are passed through the stack of the associated heat recovery steam generator (HRSG). A common steam turbine (36) is supplied with superheated steam from steam supply lines (37, 40) coming from the respective HRSG. The steam turbine is coupled to an electric generator (44), the gas turbines are coupled to electric generators (13, 23). While in the afore-stated patents the control system 50 controls the operation of the gas turbines, the afterburners and the steam turbine in order to generate electrical power under various operative con-ditions for the generation of steam and for the operation of the steam turbine i.n terms of speed and load, in contrast, according to the present invention and as explained hereinafter, distri-buted control is effected between the steam turbine, the gas turbines and the afterburners in the system, in order to operate at maximum efficiency despite changes of load in the plant.
Coordinated control of a combined cycle plant has been described in U.S. Patent Nos. 4,168,608 and 4,222,229, for instance, which indicate how the separate controls of the gas turbine, the afterburner and the steam turbine can be co-ordinated to overcome specific problems.
Control of the gas turbine is explained, although in a specific context, in U.S. Patent Nos. 4,010,605 and 3,973,291, while control of the afterburner is more specifically referred to in U.S. Patent Nos. 4,184,324; 4,333,310 and 4,031,404.
Coordinated control of the gas turbine and afterburner is shown in U.S. Patent No. 3,943,043.
Control of the steam turbine, especially by the technique of a digital electrohydraulic (DEH) system is empha-sized in U.S. Patent Nos. 4,220,869; 4,201,924; 4,267,458;

4,258,424 and 3,934,128.
Besides being independent, control of the gas turbine, the afterburner and the steam turbine to reach another operative level cannot be instantaneous, they are ,~ ~

50,086 set by the operator to meet a specific rate of change, thereby avoiding stresses and other operating constraints.
The control system of Fig. 1 will be hereinafter refer-red to as the plant unit master (PUM) control system, expressing in this fashion the versatility offered by the system under mon-itoring and control by the operator in selecting operating condi-tions for either one of the gas turbine, afterburner and steam turbine controls, or in providing coordinated operation there-between. Also, for the sake of simplicity, control in terms of load and speed of the steam turbine providing automatic operation of the throttle and governor valves under the admission of steam to the turbine, will be referred to hereinafter as the DEH (digital electro-hydraulic) system of the turbine.
Also, for the sake of simplicity, only one gas turbine will be considered, referred -to as CTl (for combustion turbine), while the afterburner will be referred to as AB. The steam turbine will be ST and the turbine proper including rotor, blades, and inner core will be referred to as TB.
Referring to Fig. 2, the throttle and governor valves relative to the upper and lower sides of admission of steam to the turbine appear as (308a, 35a) and 308b, 35b), respectively, while a bypass valve 45 is provided in derivation from the main admission line 34 via line 404 to the desuperheater 46 and the condenser. Playing between direct admission of steam to the turbine and bypassing steam directly to the condenser, in order to regulate the load of the turbine, will be, hereinafter, refer-red to as throttling and bypassing. This mode of control has been described in U.S. Patent Nos. 4,201,924 and 4,220,869.
Once the steam turbine has been set to operate at a predetermined level of megawatts, all other things considered, the steam turbine is maintained at such level in a "follow"
mode, that is, all of the steam generated is flowing through the steam turbine, none through the bypass.

16 50,086 Generally, the total plant power is controlled by controlling the operating level of the turbines and the afterburners, but the steam turbine goes into a follow mode of operation once the steam bypass valves are closed and the steam turbine inlet valves are fully opened. In such follow mode, the steam turbine produces power at a level dependent upon the s-team conditions generated under the specific heat inputs to the steam generators.
As shown in Fig. 3, the control system 50 in-cludes a plant unlt master (PUM) controller 58G, a monitor ,i~ computer lOOC and various analog controls for operating theplant equipment in response to process sensors lOlC~while achie~ing prescribed objectives. An operator panel 102C
,0d~;SeSses ~ r-o~e~ numerous pushbutton switches and displays.
Pushbutton switches provide for operator control actions including plant and turbine mode selections and setpoint selections.
In the operator analog or manual mode of opera-tion, the operator sets the fuel level for the gas turbines 12 and 22 and the afterburners 16 and 26, through gas turbine controls 104C and 106C during loading. An analog startup control is included in each of the gas turbine 5c~pl~
controls, to automatically schedule fuel,d~lrlng gas turbine startups. In addition, sequencer 108C starts and stop auxiliary equipment associated with the gas turbines during gas turbine startups. Automatic control functions are performed for the steam and gas turbines by controls 104C, 106C and llOC.
Afterburner controls 112C and 114C, and boiler controls 116C and 118C, operate under operator setpoint control during plant unit master (PUM) and operator auto-matic modes.
Under PUM control, PUM controller 58G performs all the plant load control functions that can be assigned to it, directing the plant operation through loading and unloading to produce the plant power demand. In all automatic control situations, boiler controls 116C and 118C

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17 50,086 react automatically to operator setpoints and to signals generated by the process sensors lOlC to control the steam generators according to plant conditions produced by co-ordinated turbine and afterburner operations. PUM controller 58G pro~ides setpoint signals for the afterburners in the PUM mode. P~ control provides the highest available level of plant automation, and the operator automatic mode provides progressively less automation. Some parts o the plant control function in all of the plant modes.
Normally 7 the boiler BLR follows the turbine ST.
The boiler is set to provide the required steam 10w. Instead, according to the present in~ention, the boiler is set inde-pendently and the steam turbine is adjusted so as to meet the load demand within, however, the boiler capacity and delivery.
In the follow mode, the steam turbine is adjusted to deliver the maximum load, or megawatts, possibly accord-ing to the present condition of steam flow and pressure. The follow mode allows to obtain all the megawatts to be gener-ated under the inlet steam conditions. Under such controlmode, the governor valve is normally wide open, unless modu-lation is required to satisfy minimum steam pressure require-ments. A recent disclosure o~ such prior art approach is given in U.S. Patent No. ~,222,229, where the follow mode was maintained with the assist of a computer.
The problem remains. When a load change on the steam turbine is required which cannot be handled in the follow mode, because it is not in the nature of transient changes, the operator, or the automatic control, estab-lishes the set point of the new demand, and such new levelof megawatts is to be obtained as quickly as possible without exceeding the plant imposed rates o change for the steam turbine and the gas turbine and afterburner firing rates.

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18 50,086 Referring to Figs. 4A-4C, Fig. 4A sets forth curves which show control of steam flow when passing from an initial steam flow AB to a final flow level E between time tl and t4.
The curves of Fig. 4~ show the steam turbine and gas turbine loads in the same process. In Fig. 4C, the curve shows fuel flow which characterlzes firing of the afterburner, also in the same process.
It is assumed that up to time tl the steam turbine was in a steady state at the level AB under the "follow mode".
At time tl, for instance, the operator wants to reduce the load of the turbine from, typically, 100 megawatts to 60 mega-watts. Consequentiy, steam flow through the steam turbine will be reduced from, typically 900,000 lbs/hour a~ time tl to 600,000 lbs/hour, at time t4. Coming out of the follow mode for that purpose, the plant unit master (PUM) at time tl takes over.
In the prior art, the plant unit master load controller would select between three control elements 1) open the steam turbine governor valves to the full open condition to use the maximum of the available steam under the steady condition; 2) modulate both the steam turbine and bypass valves to accommodate load transients; (these are the "follow mode" condition) and 3) control -the bypass valves to more drastically change the load on the turbine and/or control the gas turbine and/or afterburner to effect such load change, iE necessary.
According to the present invention, when changing the steam turbine load to satisfy a new demand, the gas turbine and afterburner firing are conveniently controlled so as to minimize steam waste and to maintain predetermined desirable rates of change on the steam turbine, the gas turbine and the afterburner, whereby such load change can be obtained more quickly and more efficiently.
~eferring again to Figures 4A-4C, a system is given as illustration which is not part of the present invention.
Assuming a load decrease as afore-stated illustratively, ; 35 the plant unit master load ~ ~ SZ ~2 19 50,086 controller causes the gas turbine and afterburner firing to ramp down but only after the steam turbine flow has been reduced to a substantially lower level by bypassing steam.
The latter effect appears from time tl to time t2 along curves BC' and bc which are the steam turbine flow decrease and concurrent bypass flow increase called for by the PUM
load controller. Concurrently, on the steam generating and steam inlet side, the afterburner is fired down to its minimum along BC as shown from tl to t2 in Fig. 4C. Thus, the PUM controller, at time tl modulates both the steam turbine bypass valve (BPV) and the steam turbine governor valves (GVL and GVU) to rapidly unload the steam turbine, while reducing iring-of the afterburner (A/B~ to a minimum, at time t2. Accordingly, a bypass flow has been established as shown by curve bc for Fig. 4A. The remaining portion of the steam goes through the turbine (curve BC' of Fig. 4A).
At time t2, the PUM controller starts to gradually ramp down the load of the gas turbine CT subsequent to the minimum firing level being reached for the afterburner. As a result, there is a ramping down of the total flow (curve BCD in Fig 4A between tl and t3) caused by the reduced firing of the gas ~urbine CT and the afterburners A/B. This results through the PUM controller in causing first the governor valves to reduce less, then, to open more (C'D'E in Fig. 4A) and the bypass valve to reduce,then, to close (cde). There-fore, as shown from time t2 to time t4, steam turbine flow is decreasing slowly between time t2 and t3, then, increasing from t3 to t4, while bypass flow is going to zero from t2 to t4, since from t3 to t4 more steam is demanded and the inlet steam flow is being reduced. The gas turbine loading is going slo~er (DE on Fig. 4B) while steam turbine loading is increas-ing (D'E in Fig. 4A). The final net result is a new steady state at time t4 with no bypassing of steam, while afterburner and gas turbine firing have been reduced to the level required to produce the desired steam flow and resulting new steam turbine load (level E).

50,086 It appears that at time t4 the plant has achieved the target, and the system goes to a new steam turbine "follow mode" for-which all of the steam being produced is flowing into the steam turbine; the governor valves are fully open and there is no waste of steam through bypassing to the condenser.
In the process of reaching this new stage, the efficiency of the plant could have been disturbed. The illustrative steps of Fig. 4A-4C show how by controlling the generation of steam concurrently with the load of the steam turbine toward the target the waste of steam is minimized while the generatîon of power is maximized. Thus, from time tl to time t2 the consumption of energy to produce steam flow, which could be more effectively utilized by the gas turbine which produces electricity, is reduced from B
to C (Fig 4A), while steam turbine flow is reduced by increasing bypass flow (BC' and bc in Fig. 4A). Moreover, this has been done in the shortest time, e.g. at the maximum rate acceptable. Then, from time t2 at a slower rate the gas turbine load is decreased (CD, Fig. 4B), while the bypass flow (cd in Fig. 4~) is being decreased while still reducing steam turbine flow (C'D'), but at a much lower rate. Finally, from time t3 to time t4 the steam turbine load is increased to reach the target (D'E) from below, rather than from above, while the bypass flow is being reduced to zero (de). Con-vergence to the target is now obtained by transferring load from the gas turbine to the more efficient steam turbine. In the same process, from instant t2 to instant t4, the gas turbine has been able to reach in a gradual way the still efficient level of operation at E for normal operation at the new load targeted for the steam turbine.
This approach to plant master unit control of steam valve positioning in order to achieve quickly a desired megawatt load, distinguishes itself from the computer-controlled turbine steam flow modifying system to satisfy a turbine speed and load demand which is disclosed in U.S.

~ ~ ~ 5Z 8~
21 50,086 Patent No. 4,258,42~ (Giras and Birnbaum). In this patent is described the relationship between the operator panel, the plant unit master and the speed and load control for the steam turbine valves, to achieve sequential governor level. The steady state power or load is achieved with the steam turbine at substantially constant throttle pressure steam. The plant master unit controller selects load control by way of steam turbine control loops involving limited change rates, so as to avoid excessive thermal stress on the turbine parts. Once at the steady state, a boiler "follow mode" is maintained.
U.S. Patent No. 4,222,229 discloses coordinated control between gas turbine fuel valve and IGV control, and afterburner control, in accordance with the overall plant loading. However, there is no object there to load or unload the steam turbine, indepe~dently, and afterburner control is to maintain a following mode with the steam turbine through gas turbine operation.
In contrast to the two last cited U.S. patents, U.S. Patent No. 4,201,92~ discloses sliding pressure bypassing and throttling for a steam turbine.
In such a plant, the turbine operates normally with its steam inlet control valves wide open without throttling, and with the load being governed by tne rate of steam generation. The steam pressure is permitted to slide within certain limits depending on the loading of the turbine, and the turbine accepts whatever steam is generated.
The operation of a plant of this type is limited to a minimum steam pressure and flow, because of the require-ments of the heat recovery steam generators, and it is furtherlimited to a maximum velocity of steam to minimize erosion of the steam generator tubes and reduce the probability of water carryover into the turbine, whic~ could damage the turbine blades. At the same time, it is desirable to minimize throttling of the steam turbine control valves to maintain optimum plant efficiency and stability.

4S~
22 50,086 While U.S. Patent No. 4,201,924 shows steam by-passing and steam throttling on the steam turbine to accommo-date load changes, U.S. Patent No. 4,031,404 shows gas turbine and afterburner control for temperature regulation and U.S.
Patent No. 3,948,043 shows gas turbine and afterburner control as part of a megawatt load control system for the gas turbine.
In contrast, the present invention, as explained hereinafter, is concerned with controlling the gas turbine and afterburner as part of a megawatt load control system for the steam turbine.
In all the patents already cited herein, reference is made at various places to adaptive control involving feedforward setpoints, for temperature, steam flow, megawatts, valve positioning, etc.... It is also stated that in so doing a linear increase, or decrease, of the independent variable concerned is desired and selected at predetermined limited rate.
Ramping is an important consideration for startup, shutdown, loading and unloading. In particular, this involves megawatt rates, and flow rates, as well as temperature rates.
Referring to Figs. 5A-5C, from the operator panel the system can be transferred from the PUM mode to the follow mode and conversely. In the PUM mode the controller according to the present invention is set by line 22~ and switch 300 (Fig. 5B) to respond to line 223, whereas in the follow mode line 225 is the active line. In the follow mode, the combustion turbines (CT#l and CT#2) and after burners are controlled by theîr respective controllers (349 and 249 for CT#l, 349' and 24g' for CT#2, în Fig. 5~. and 305, 305' for the afterburners in Fig. 5C) to operate at maximum efficiency for the partîcular level of the load (MWl on lines 369 and 201 ~or CT#l, MW2 on lines 3~9' and 202 for CT#2 in Fîg. 5A and MW3 on lines 203, 397 and 211 for the steam turbine S.T. in Fig. 5B). In the process, the steam turbine is automatîcally controlled by the DEH system operating on the governor valves for maxîmum utilization of the steam received in terms of temperature, , . . .
,,, ~f~45~ 2 23 50,086 pressure and flow from the header. All transient load changes are taken up. Also the skid controller of the system takes into account the rotor temperature and steam temperature to minimize stress. More generally, in the follow mode the steam turbine utilizes all the steam it gets under most efficient conditions while producing electricity. Thus, the throttle temperature tT~I is derived on line 237 (Fig. 5C) and the throttle pressure Pth control set point is derived on lines 236 and 225 for the follow mode, line 236 being used for afterburner A/B control. When the system goes to the PUM mode, control is according to lines 223 for the steam turbine and lines 352, 352l for the gas turbines, as will appear from the description hereinafter.
The megawatts generated by the gas turbines CTl, CT2 and the steam turbine ST are respectively derived on lines 201, 202 and 203. These are summed by summer 204 to provide a signal representing the total demand on line 205.
Line 205 also conveys such total demand to a differentiator 207 which further receives from line 206 a plant target of megawatts imposed by the plant unit master (PUM). An error is derived by differentiator 207 which belongs to the computer system. The error outputted on line 208 is indica-tive of a want of megawatts, or an excess of megawatts, depending upon the sign thereof imposed by the plant target.
The present megawattage from the steam turbine is derived from line 203 and carried by line 211 to a steam demand circuit 216 belonging to the computer system. Circuit 216 adds the error of line 208 to the steam turbine generated megawatts, thereby providing at the output on line 217 a target for the steam turbine. The invention pertains to how such new demand translated onto line 223 in the PUM
Mode (switch 300 in the N-position) will be met by the control system at a time the steam turbine is in the follow mode (switch 300 in the Y-position).
The skid controller (SKID, Fig. 5C~ o~ the steam turbine calculates the throttle pressure set point and 24 50,08~
establishes on lines 225, 236 a signal which is used in the follow mode to control by line 231, via ramp 228, the DEH
system of the turbine in order to maintain a proper flow of steam while respecting the prescribed pressure/flow rela-tionship during turbine control valve operation in asliding pressure type of steam bypass and control valve control like described in U.S. Patent Mo. 4,201,924.
In the follow mode, the signal of line 236 by line 225 to the ramp circuit 228 establishes on line 229 a ramping signal which is applied to a low select circuit 230. Assuming the signal of line 229 prevails, in the follow mode the governor valves are controlled in accor-dance with the signal of line 236, at a rate determined by ramp circuit 228. In addition to this signal, low select circuit 230 also responds to the signal of line 236, received directly via line 236. Circuit 230 also receives on line 240, a signal whi'ch is obtained by conversion from a steam turbine inlet temperature tTH representative signal, also provided by the skid controller, on line 237.
Such signal is converted into percent of megawatts by a function generator 239, as illustrated in Fig. 5C. The function f(x) in block 239 provides a rate of change in terms of % megawatts to be translated by the DEH of the steam turbine on line 231. Typically 100% MW corresponds to 952F the desired operative temperature for the steam, and 0% MW to only 700F at the inlet, the intermediate ,~ percentages being linearly distributed. This is to insure that the steam turbine takes load only in tation to the actual turbine temperature, thereby to prevent wetness.
Depending upon the relative levels of the signals of lines 229 and 230, the signal of line 240 may override the follow mode command from lines 229 and the one of line 238.
"Follow mode" operation is determined by the signal of line 224 to the two-position switch 300, as selected by the plant unit master. Assuming the signal of lines 224 to switch 300 establishes the Y-position, e.g., the follow mode, the connection is from line 225 to line 25 ~2~5~2 50,086 301. The signal of line 301 is passed to 105 via another switch 302 onto line 303, then to substractor 303 and from there, via line 327, to a multiplier 307 which establishes a ramp signal of slope defined by line 313. The outputted ramp signal appears on line 308 via a hold circuit 309. At the rate defined by line 313 onto multiplier 107, the signal of line 225 is applied as a ramping signal on line 229 to low select circuit 230. This is prior art when considering the follow mode per se. In the follow mode, a fast rate (typically 30 MW/minute) is set by line 252 via a selector switch 314, and such rate controls, by line 313, the multiplier 307. Such fast rate insures that in the follow mode the set point from line 236 to line 225 is quickly followed in commanding the DEH by line 231.
A new plant MW target is assigned (at time tl, Fig. 4A) to the system on line 206 (Figs. 5A, 5B). The new target is carried by line 206 over to a subtracter 207 where an error is developed on line 208 from the comparison o line 206 with the actual total plant MW derived on line 205. Such total plant MW is as totalized by summer 204 from a consideration of the steam turbine load MW3 on line ~ 203 and the two gas turbine loads (MWl, MW2) on lines 202 `~ ~ and 202, respecti~ely. An error due to an excess ~ a ~an~
of MW appears on line 208. The error is added by summer 216 (Fig. 5B) to the actual load (MW3) of the steam turbine derived on line 211. Therefore, line 217 indicates what the load of the steam turbine should be if it would take up the difference assigned by the new target. At this time, the two gas turbines CT~l and CT#2 were set by lines (369, 368) and (369', 368') to operate at the present loads MWl on line 369 and MW2 on line 369'. Inhibit signals on lines 507, 507', respectively have set equal both inputs 365 and 506 to subtracter 500 so that no response by the ramps RMPl, RMP2 occurs to a new target on lines 206 and 376 to the gas turbine demand computer 379 (Fig. 5A). Considering again the steam turbine under the new demand on line 217, a lo~ select circuit 218 establishes by line 219 a maximum ~2~5~82 26 50,086 set point, typically of 117.2MW, whereas the output on line 220 goes to a high select circuit 221 establishing by line 222 a minimum steam turbine throttling demand. The signal of line 223 is the demand established between those two limits.
Between these two limits, the outputted control signal o~ line 223 goes through preliminary circuit 226 and the ramp circuit 228, translated on line 231 into a control signal for the DEH controller establishing the required new steam turbine load demand. The plant MW error of line 208 also goes by line 250 to summer 252 for proper scaling by set point 251, and thereafter by line 253 as an input to summer 258 of the afterburner controlling branch. The throttle pressure PTH signal of line 236 is compared by li~e 227' with the ramp output on line 229 ~or the steam turbine.
The output signal thereof on line 554 is inputted into a high select circuit 255 having a zero signal on line 456 at its other input. It is the outputted signal of line 257 which is summed up with the signal of line 253 by summer 258.
After proper gain a signal on line 261 is generated, typically varying ~rom zero to 10 volts, such that for 5 volts there is no change in load. The ater burners are controlled in paralle~ via lines 305 and 305' for loading the detected MW error into the afterburners. Reference should be had in this respect to United States Patent 4,578,944, issued May 13, 1986.
When the afterburners, concurrently with a steam turbine decrease, under the assumption made of a lower target, has been reduced to its minimum, (time t2 in Fig.
4C), the inhibit signals of lines 507, 507' clear and the gas turbine are ready to accept participation, thus, in accordance with the time intervals beyond instant t2.
Considering gas turbine CT#l, the inhibit signal of line 507 shift switch 505 into position N whereby line 506 no longer passes the same signal as line 365, but rather a signal of zero magnitude. Therefore, the signal of line 528~
27 50,086 365 is now effective into ramp RMP to generate a ramping signal on line 361 in accordance with the error between the feedback signal of lines 36 and 363 and ~ the gas turbine demand signal of line 352.
Considering the plant MW target of line 206, this signal is inputted by line 376 into a gas turbine demand computer, e.g. a circui-t which takes into account the plant target of line 376, the actual steam turbine demand on lines 203 and 397, as well as the participation of the afterburners fed back from line 257 by line 378. In other words, at time t2, the share- of the gas turbines in achieving the new target is ascertained on line 380.
Depending upon whether two gas turbines or a single one is used, switch 410 is controlled by line 411 to assume one amount by line 380 from circuit 379 or twice the amount by lines 380 and 380' in summer 381. This divider by two insures that the same error on line 380 is taken up via line 352' by CT#2 when CT#l is OFF or via lines 352 and 352'`when both are ON.
Considering again only gas turbine CT#l, the signal of line 352 is compared with the feedback control signal of lines 361 and 363 to generate an error into comparator 364 and apply through summer 500 on lines 365, 565 a set point control signal to ramp PMP1. The output of ramp RMPl will increase or decrease to catch on the as-signed set point of lines 365, 565 at a rate defined by line 402 from switch 370 depending upon the position thereof imposed on this switch by line 412 (under opera-tor's manual station control). These two positions are either for a fast rate in position Y, e.g. from line 252 (the fast rate setting is typically of 30 MW/min), or in position N for the rate appearing on line 248, as set by the operator on line 377. The set rate is obtained via gain amplifler 382 and line 383 as applied to MW rate 35 corrector circuit 384 which outputs its signal on lines 247 and 248 going to switch 370. Typically, the rate setting ranges for the gas turbine vary between O and 20 MW/min.

~5~32 , .-.
28 50,086 the required rate on line 383 is summed up with the output on line 246 from MW ~ rate controller 244. The latter is a PI controller responding to the difference between the required ~ MW setting (0 - 20 MW/min) and the computed value on line 243 derived from differentiator 2~2 which is converting the total plant MW of line 205. Thus, a correc-tion of + 10%, typically, is added to the assigned ~ MW
setting of line 383, by MW rate corrector 384. This corrected value is applied by line 247: to the steam 10 turbine ramp slope determinating circuit 307 (by line 316, switch 314 and line 313), to -the RMPl slope determinating circuit 354 (by line 248, switch 370 and line 402), to the RMP2 slope determinating circuit 354' (by line 248', switch 370 and line 402').
It appears that the enabling signal on lines 507, 507' will permit the gas turbines CT~1 and CT#2 to provide beyond time t2 (Fig. 4B) participation of the gas turbines to the decrease of the load together with the steam turbine.
In considering again the gas turbine load control circuits under CT#1 and CT#2, in Fig. 5A the actual MW of the gas turbine on line 369 (for CT#1 for instance) is by line 370 compared with the ramp output of lines 363, 371 in order to generate by high-low relay 372 a rate increase or 25 a rate decrease (by lines 373 or 374) to match the actual MW.
Figure 5B shows the plant MW error of line 208 being passed by line 385 to a dead band circuit 386 estab-lishing a + 5% deadband at the output 387 in order to enable the MW ~ rate controller 244, thereby allowing the +
10% corrective rate of change onto summer 384 in relation to the assigned rate of line 303.
Referring now to switch 302 of Fig. 5B, when controlled by line 304 to the Y-position rather than the N-position, the situation is such that the DEH no longer accepts the control input from line 231. In that case the controller is being set for tracking by line 388. The ramp ~ 2 ~S~ ~
29 50,086 228 is now taking the actual megawatts of the steam turbine from lines 203 and 211 rather than the plant demand from line 223. This positioning of switch 302 amounts to cancelling the target and takîng the actual demand of the steam turbine.
If the lower switch breaker is open as shown by line 304, this means zero megawatts being produced, and the setting by switch 310 accordîng to set point of line 311 is zero megawatts as it should for the ramp~
Considering the control system and control method of Figs. SA-5C in the light of the overall gas turbine-steam turbine cogeneration process, the following comments are in order:
The operator from the operator panel sets the desired MW target on 306, 306' and 206 at the initîal tîme.
An error is calculated at 201 whîch inputs a negative signal (assuming a lower target) into summer 216 which results in a reduced demand on the steam turbine.
If the ~ demand exceeds 5~/O at 386, the megawatt rate controller 244 is put into ser~ice by line 387. This controller compares the actual to the maxîmum rate, then, controls the steam turbine rate functîon ~ia lines 247, 316 and 313 and via lines 248 and 2~8' for the gas turbines.
The megawatt error by line 250 is also inputted into summer 253 to result in a reductîon of afterburner (A/B) firing level.
The steam turbine and afterburner will a~tempt to unload with all of the loading rate, set by the operator on line 377, being absorbed by the steam turbine. When the burner (A/B) reaches its minimum, î.e. no further modulation thereof is possible. At th;s point, by line 507 control upon switch 505 for gas turbîne CT#l (by line 507' upon switch 505' for gas turbine CT#2) will switch the position thereof from ~he zero setting on the Y-position to the N-position for which the error from line 305 manifests it-self through summer 500, whereby line 505 through ramp RMPl the gas turbine CT#l is brought to , ~, 5XI~
30 50,086 share the unloading rate (the same can be said for gas turbine CT#2 by line 565' and ramp RMP2).
This process will continue until the plant megawatt target is reached. In this respect, at time t3 the plant may be in a very inefficient operating mode. The control system, according to the invention, will restore the rnost efficient conditions for the plant by the following steps:
Summer 254 outputs a signal on line 554 any time the steam turbine power is less than what is required to maintain at the required level the inlet pressure. This signal goes to the high selector 255, the output signal of which on line 378 goes to the gas turbine megawatt demand summer 379. This reduces the megawatt demand on the gas turbines. This will in turn cause a megawatt error translated by the plant megawatt error computer at 207. This adjusting process will continue until the plant has been restored to the true "follow mode"
condition for which all the steam is going through the steam turbine.
It appears that upon a load transient the PUM control-ler according to the present invention selects between three control elements so as to 1) normally open the steam throttle to the full open position; 2) close the valve during combined cycle load reduction transient; and 3) reopen the valve at the completion of the load transient.
Also, low pressure (L.P.) steam turbine blading wetness protection is provided to prevent opening the throttle valve beyond an adaptive limit based on throttle steam temperature.
A steam turbine load demand signal is uniquely devel-oped whereby throttling will be required under the following conditions:

5~
31 50,086 a) The operatox (or a remove load dispatch system) requires a load reduction at a rate which it responds to by a reduced fuel firing alony (by either, or both, combustion turbines or afterburners) would result in excess steam temperature rate of change and hence thermal stress.
b) At the operator's discretion, the combustion turbine load is to be held constant; and, hence, all load swings are taken on the steam turbine preferably with afterburner participation.
Typically, the allowable steam turbine load function generator will ramp the load setpoint at a rate of 3 MW/min. ~hen the steam temperature is ramped at 7-1/4F
per min. This provides loading rate control on the steam turbine on initial loading.
The allowable steam turbine load function genera-tor maintains a load setpoint which corresponds to the highest allowable load which the steam turbine can instan-taneously assume without exceeding rotor stress limits.
20 Rèviewing now the control procedure for load changing with a combined cycle plant as in the preferred embodiment of the invention, the following is in order:
Load control for the plant can be at a given moment under the control of the Plant Unit Master (PUM), the primary operator panels of the combustion and steam turbines, or operator control stations for afterburner and steam control valves, or a combination of these.
In the Plant Unit Master (PUM) control mode, the operator can input a plant megawatt target and a plant megawatt rate of change to the PUM controller. The PUM
controller will then modulate the steam turbine, the afterburner and combustion turbine to attain the new load target. The resultant operating mode, after an adjustment period, will be the most efficient mode for the plant operating configuration. The PUM will not shut down afterburners or shut down one gas turbine to fully load the other.

32 ~5~8~ 50,086 Load changing can be affected with the PUM from the most highly automated to the least automated or com-bined PUM/manual control mode. It operates in both unload-ing and loading situations.
In accordance with the present invention PU~
plant unloading and loading with the steam turbine is performed in the "PUM" or the "Follow" mode. Such selec-tively control mode can be set by the operator at a selec-tor switch on the steam turbine primary panel.
In the PUM mode, the plant will be more respon-sive to rapid load changes with the steam turbine in such mode when the afterburners are in their modulation range.
This is achieved by the steam turbine unloading at the Plant Unit Master (PUM) megawatt rate causing steam to bypass the steam turbine through the bypass system if the loading rate is faster than the rate which can be achieved by the afterburners unloading. In contrast, the plant ~`, cannot respond to the load changes ~ rapidly when the steam :~?~
turbine is in the "Follow" mode. Then, the steam load change ramp will be established by the afterburner tempera-ture change rate without bypassing steam to the condenser.
In such case, plant operation during the load change will be more efficient because all the HRSG steam produced is flowing through the steam turbine.
Considering first, load reduction from full load, the following events will occur once the operator has selected a new, lower megawatt target:
The steam turbine first begins to unload at the operator input PUM rate and continues to do so until load target has been reached or the steam turbine load has reached a minimum value. Thereafter, the afterburner will begin to unload at either the afterburner runback rate, or the rate corresponding to the steam turbine unloading rate (whichever is less). If the target has been reached within the afterburner modulating range, the steam turbine loadwill hold and the afterburners will continue to modulate until the steam turbine bypass valve is fully closed. All ~5; :8~
33 50,08~
the steam produced by the boilers is, then, flowing through the steam turbine. If, however, the afterburner(s) reach their minimum firing set point before the load target has been reached, the sequence will be as follows:
The combustion turbine begins to unload and share the plant unloading rate with the steam turbine, until the plant load target is established. The operator may opti-mize the plant full efficiency by shutting down the after-burners if the combustion turbines are below base or full load. The PUM controller will respond to the afterburner shutdown by increasing the combustion turbine load to compensate for reduced steam flow and steam turbine load.
This will restore the plant load to the target value and enhance plant operating efficiency.
Considering now plant loading to full load the following events will occur once the operator has selected a new, higher megawatt target:
The combustion turbine load will begin to in-crease if it is not at base load. Then, the steam turbine load will begin to increase as steam flow increases in response to increased combustion turbine load, and the afterburners will begin to increase the HRSG inlet tempera-ture after the combustion turbines have reached base (full) load. The afterburners will continue to increase the HRSG
inlet temperature at a rate equal to either the operator input Afterburner Gas Temperature Rate or the rate neces-sary to produce the desired steam turbine loading rate (whichever is less). Finally, the plant megawatt target will have been reached.
Another situation is PUM load changing with the steam turbine in the follow mode. Considering first load reduction from full load, the following events will occur once the operator has selected a new, lower megawatt target:
The afterburners begin to unload at a rate equal to the operator input Afterburner Gas Temperature Rate, or the rate required to produce the desired steam turbine ~528~
34 50,086 megawatt rate or change (whichever is less). Then, the steam turbine will unload as steam flow reduces. The steam turbine will remain in the "Follow" mode. All steam produced will flow through the steam turbine and the steam turbine governor valves will remain fully open unless modulation is required to maintain HRSG outlet steam pressure. If target is reached within the afterburner modulation range, the afterburner gas temperature and steam turbine load will hold and maintain target load. If the afterburner(s~ reach its minimum firing set point before the lGad target is reached, the combustion turbine(s) will begin to share the plant unloading rate until the plant megawatt targe-t is reached. Here, again, the operator may optimize the plant full efficiency by shutting down the afterburners if the combustion turbines are below base or full load. The PUM will respond by increasing the combus-tion turbine load to compensate for reduced steam flow and steam turbine load. This will restore plant load to the megawatt target value.
Considering now plant loading to full load, the sequence is as follows:
The combustion turbine load will begin to in-crease. The steam turbine load will begin to increase as steam flow increase in response to increased combustion turbine load. The steam and combustion turbines share the combustion turbine loading rate. The afterburners begin to increase the HRSG inlet temperature once the combustion turbines have reached base (full) load. The afterburners will continue to increase the HRSG inlet temperature at a rate equal to either the operator input afterburner gas temperature rate (operator station on the CT/HRSG Primary Panel) or the rate necessary to produce the desired steam turbine loading rate, whichever is less. Finally, the plant megawatt target has been reached.
In the previous examples of PUM mode plant load changing the PUM controller modulates the load of the steam -turbine~, afterburners, and combustion turbine~
~.

~ 2~
50,086 automatically. The PUM controller will also modulate the plant load when the control system is in a less automated mode, specifically when one (l) or both of the afterburners are in the manually selected afterburner temperature target or one (1) or both combustion turbines are in the manual megawatt control.
Load changing with either afterburners or combus-tion turbines in manual setpoint control may result when the plant is operating under conditions which are undesir-able, such as operation with high afterburner firingtemperature operation when the combustion turbines are not fully loaded; unequal afterburner firing temperature; and unnecessary steam bypassing to the condenser. These conditions will then require operator action to restore the plant to its most efficient operating mode.

Claims

CLAIMS:

1. In a cogeneration system including a steam turbine generating a steam turbine electrical load when supplied with steam from at least one heat recovery steam generator (HRSG) having one gas turbine generating a gas turbine electri-cal load, and an afterburner associated with said gas turbine, the steam turbine load and the gas turbine load being used jointly to meet a plant target in megawatts, said steam turbine being operable in response to a throttle pressure control set point signal when in a follow mode; the system further including:
first controlling means responsive to a first megawatt error existing between the plant target and the present demand for megawatts from said gas turbine and steam turbine for con-trolling at a predetermined rate the afterburner;
second controlling means responsive to a megawatt error between the plant target and the present demand for mega-watts from said steam turbine for controlling at a predetermined rate the load of the gas turbine;
third controlling means operative to control the load of the steam turbine at a predetermined rate in response to a first load demand reference signal for providing a load control signal of selected rate for said steam turbine; said first load demand reference signal being representative of said throttle pressure control set point when the system is in the follow mode under a present megawatt target; characterized by:
means responsive to said first megawatt error and to said present steam turbine load for deriving a combined signal as a second load demand reference signal;

switching means operative in the following mode to apply said first load demand reference signal to said third controlling means, and operative in a plant master (PUM) mode of the system to apply said second load demand reference signal to said third controlling means;
said PUM mode being triggered in the system upon a new target being assigned to the plant, with said new target being substantially below said present target follow mode;
feedback means being provided responsive to said load control signal of selected rate for controlling said first controlling means, thereby to reduce the afterburner firing;
whereby, upon a new target below said present target, the load of said steam turbine is reduced at said selected rate in priority to the predetermined rate of control of said gas turbine.