GB2166198A - Improved steam turbine load control in a combined cycle electrical power plant - Google Patents

Abstract

A cogeneration system embodying a heat recovery steam generator assisted with a gas turbine and an afterburner for supplying steam to a steam turbine supplied in which substantial changes 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 whilst reduce steam by pass flow to a minimum. <IMAGE>

Description

SPECIFICATION Improved Steam Turbine Load Control in a Combined Cycle Electrical Power Plant The present invention relates to a combined cycle electric power plant and in particular 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 terms of flow, pressure and temperature so as to change speed and/or load on the steam turbine.

For the purpose of disclosing a digital electrohydraulic (DEH) control system suitable for controlling the throttle valves and the governor valves of a steam turbine plant in a combined cycle plant, reference is made to the specification of U.S.

Patent Nos. 4,220,869; 4,201,924 and 4,222,229.

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 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 superheater tubing, superheated steam which is supplied to the steam turbine. A condenser is associated with the steam turbine to receive the spent steam and for converting it into water condensate fed back to the steam generator.

In a combined cycle electric power plant, the steam turbine 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, a significant reduction in the fuel required to heat the steam is achieved and the heat contained in the gas turbine exhaust gases is effectively utilized. An 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. Whenever, under conditions of relatively high load, the heat of the gas turbine exhaust gases is insufficient 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 particular need to coordinate the control of the separate gas and steam turbines and afterburners. It is desired that the steam turbine be operated in what is called a "turbine following" 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 "follow mode", the steam produced by the gases exhausted by 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 coordinated control while elements are simultaneously under a lower level 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 the specification of U.S. Patent No. 4,222,229 which discloses, besides automatic or coordinated control by the operator with the assist of a programmed digital computer of the steam turbine for startup and automatic 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 the 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 throttle valves on the gas turbine and/or the afterburner.

It is also disclosed in the specification of U.S.

Patent No. 4,201,924 to control a combined cycle electric power plant by maintaining a predetermined steam pressure as a function of steam flow, using the bypass valve, and having the control valve of the turbine to respond to the speed/load demand only, except when the bypass valve is closed and the rate of generation of steam has become insufficient to maintain such predetermined pressure flow.

In a combined cycle plant 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 is further limited to a maximum velocity of steam to minimize erosion of the steam generator tubes and 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 to maintain optimum plant efficiency and stability. This presents certain problems in that the maximum steam velocity which can be permitted depends on the steam pressure and the rate of steam generation. For example, with both heat recovery steam generators in service, the steam turbine may succeed in maintaining 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 varies.

For example, with one generator in service, the system can 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 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 increasing the probability of water carryover to the turbine. In starting up a plant of the type described, it is desirable to 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 the bypass valve can be modulated in order to maintain the proper pressure flow relationship to the turbine.

Any minimum pressure flow relationship 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 desirable that none of the steam be bypassed to the condenser, unless the pressurefflow relationship becomes excessive. Therefore, it is desirableforthe control valves to maintain control of the pressure/flow relationship with the bypass valve closed.

A sudden decrease, or increase, in pressure, depending on the type of contingency, can trip the steam generator or 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. When a transfer of control of the pressure/flow relationship 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 relationship must of necessity be controlled by the control valve, or the rate of steam generation.

Even under these conditions, the bypass valve is arranged to respond quickly to contingencies requiring responses.

Also, in stand alone steam turbine electric power plant of the sliding pressure type 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 prssure at a minimum on initial loading. The load function generator establishes a load setpoint corresponding to the highest allowable load. These modes and conditions of operation are established by the plant unit master (PUM) controller of the total plant, of all the turbines, which supervises and controls the plant through loading and unloading. As earlier 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 is 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 desirable rate. One of the main limitations, besides the limitations for the steam at the inlet to attain new 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 temperature. For this reason, once a new load has been recognized as the setpoint for the steam turbine controller, the operator will usually set a predetermined rate acceptable for the operation. A ramping setpointfor load changes on the steam turbine is parallelled in a combined cycle with ramping setpoints for the gas turbine and for the afterburner, 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, as disclosed in the specifications of U.S. Patent Nos.

3,657,552 and 3,998,058.

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 limitations due to boiler capacity or steam delivery. When it is required to adjust the turbine 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.

According to the present invention, a combined cycle electric power plant includes a cogeneration system having a steam turbine supplied with steam from a heat recovery steam generator (HRSG) having at least one gas turbine and an afterburner associated therewith for producing an electrical load jointly with said steam turbine, said steam turbine being operable in one of a follow mode and a plant unit master (PUM) mode, with said steam turbine in the follow mode being controlled to generate power in accordance with the HRSG steam output to satisfy a current predetermined plant load level, in which first controlling means is operable in the PUM mode in relation to a substantial change in said current predetermined plant load for controlling the afterburner, second controlling means operable in the PUM mode in relation to said plant load change for controlling the gas turbine to effect a corresponding load change therein, and third controlling means operable in the PUM mode in relation to said plant load change for controlling said steam turbine to effect a corresponding load change therein, said first, second and third controlling means concurring in setting a new predetermined plant load for said steam turbine in the follow mode.

Conveniently, the operator, or a remote load dispatch system, sets a load change which is in excess of what the combustion 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 generating system, thereby to permit steam temperature ramping on the steam turbine at an acceptable rate. With this approach, sliding pressure steam turbine operation is effected to accommodate large ranges in the megawatt 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 position. This is very inefficient since bypassed steam is wasted.

According to the present invention, instead, for a load decrease the afterburner fuel flow and the gas turbine load are ramped downward at their normal rate. This results in the steam turbine power and steam flow, under the plant unit master (PUM) control, increasing automatically in order to offset the reduced power level occurring with the gas turbine and with a correlative reduction of the bypassed steam due to both the increased steam turbine steam flow and reduced steam production resulting from reduced temperature at the inlet of the heat recovery steam generator under reduced afterburner fuel flow.

Conversely, 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 and the steam turbine to gain load as a result of taking up steam at increased temperature.

In each instance, thereafter, 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 attain the optimum by reducing the participation of the afterburner and maximizing the utilization of fuel in the gas turbine, at which time 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 loading and unloading without exceeding motor stress limits.

For the purpose of describing the plant unit master (PUM) control system, the following additional specification of patents are also incorporated by reference: U.S. Patent No. 4,031,404 which discloses control of the afterburner and the gas turbine of a combined cycle electrical power plant to improve temperature control of the steam generated.

U.S. Patent No. 3,973,391 which discloses inlet guide vane control for the air intake and fuel valve control for the afterburner and gas turbine of a combined cycle electrical power plant.

U.S. Patent No. 3,953,966 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 electric power plant to obtain dry steam.

U.S. Patent No. 3,948,043 which in a combined cycle electric power plant provides for coordinated fuel transfer between gas turbine and afterburner.

U.S. Patent No. 4,010,605 which describes the plant unit master (PUM) control for startup, shutdown, synchronization and loading in a coordinated manner.

U.S. Patent No. 4,184,324 which shows coordinated gas turbine control.

In addition are incorporated by reference the following patents: U.S. Patent No. 3,934,128 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 which shows digital computer controlled steam turbine for adjusting steam flow and pressure at the inlet to meet speed and load requirements.

Finally, U.S. Patent No. 3,939,328 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 (PU M), the illustration being for boiler control and steam turbine control.

The invention will now be described, by way of example, with reference to the accompanying drawings in which: Figure lisa 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. 1; Fig. 3 shows the organization of a coordinated control system for the steam turbine and the gas turbine and afterburners of Fig. 1; Figs. 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.

Fig. 1 shows a functional block diagram of a combined cycle electric power generating plant.

Reference numeral 10 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 controlsthe 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 efficiency. The fuel supplied by the throttle valve 14 is burned in the gas turbine 12 and the resulting high temperature exhaust gas is passed through an afterburner 16, then through a heat reccvery steam generator 18, and is thereafter exhausted into the atmosphere.

Heat recovery steam generator 18 (sometimes referred to as "heat recovery steam generator No.

1", or HRSG1 ) includes boiler tubes which are heated by the gas turbine exhaust gas passing through the steam generator 18. Afterburner 16 (AB1) 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 afterburner 16.

The combined cycle plant 10 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 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 gas 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 condenser31 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 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 bypass 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 is constructed to provide complete and safe operation of the total plant 10 or any part thereof.

When operating at the highest 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 the specification of U.S. Patent Nos.

4,184,324; 4,333,310 and 3,953,966. Two heat recovery steam generators (18,28) having 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) 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 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 conditions for the generation of steam and for the operation of the steam turbine in terms of speed and load, in contrast, according to the present invention and as explained hereinafter, distributed 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 the specification of 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 coordinated to overcome specific problems.

Control of the gas turbine is explained, although in a specific context in the specification of U.S.

Patent Nos. 4,010,605 and 3,973,291, while control of the afterburner is more specifically referred to in the specification of U.S. Patent Nos. 4,184,324; 4,333,310 and 4,031,404. Coordinated control of the gas turbine and afterburner is in the specification of U.S. Patent No. 3,943,043.

Control of the steam turbine, especially by the technique of a digital electrohydraulic (DEH) system is emphasized in the specification of 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 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 referred to as the plant unit master (PUM) control system, expressing in this fashion the versatility offered by the system under monitoring and control by the operator in selecting operating conditions for either one of the gas turbine, afterburner and steam turbine controls, or in providing coordinated operation therebetween. Also, for the sake of simplicity, control of the steam turbine providing automatic operation of the throttle and governor valves upon the admission of steam to the turbine in terms of load and speed, will be referred to hereinafter as the DEH (digital electro-hydraulic) system of the turbine.

Also, for the sake of simplification, only one gas turbine will be considered, referred to as CT1 (for combustion turbine), and 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, referred to as throttling and bypassing.

Once the steam turbine has been set to operate at a predetermined level of megawatts, all otherthings considered, the steam turbine is maintained at such level in a "foilow" mode, that is, all of the steam generated is flowing through the steam turbine, none through the bypass.

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 steam conditions generated under the specific heat inputs to the steam generators.

As shown in Fig. 3, the control system 50 includes a plant unit master (PUM) controller 58G, a monitor computer 100C and various analog controls for operating the plant equipment in response to process sensors 101 C while achieving prescribed objectives. An operator panel 102C provides 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 operation, 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 controls, to automatically schedule fuel during 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 110C.

Afterburner controls 1 12C and 114C, and boiler controls 11 6C and 118C, operate under operator setpoint control during plant unit master (PUM) and operator automatic 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 11 6C and 11 8C react automatically to operator setpoints and signals generated by the process sensors 101 C to control the steam generators according to plant conditions produced by coordinated turbine and afterburner operations.

PUM controller 58G provides setpoint signals for the afterburners in the PUM mode. PUM control provides the highest available level of plant automation, and the operator automatic mode provides progressively less automation. Some parts of the plant control functions in all of the plant modes.

Normally the boiler BLR follows the turbine ST.

The boiler is set to provide the required steam flow.

Instead, according to the present invention, the boiler is set independently and the 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 according to the present conditions of steam flow and pressure. The follow mode allows to obtain all the megawatts to be generated under the inlet steam conditions. Under such control mode, the governor valve is normally wide open, unless modulation is required to satisfy minimum steam pressure requirements.

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, establishes the set point of the new demand, and such new level of megawatts is to be obtained as quickly as possible without exceeding the plant imposed rates of change for the steam turbine and the gas turbine and afterburner firing rates.

Referring to Figs. 4A-4C, Fig. 4A has curves which show control of steam flow when passing from an initial steam flow AB to a final flow level E between time t, and t3, in accordance with the present invention. The curves of Fig. 4B show the steam turbine and gas turbine loads in the same process. In Fig. 4C, the curve shows fuel flow which characterizes firing of the afterburner, also in the same process and iri accordance with the present invention.

It is assumed that up to time tithe steam turbine was in a steady state at the level AB under the "follow mode". At time t1, for instance, the operator wants to reduce the load of the turbine form, typically, 100 megawatts to 60 megawatts.

Consequently, steam flow through the steam turbine will be reduced from, typically 900,000 Ibs/hour at time t, to 600,000 Ibs/hour, at time t4.

Coming out of the follow mode for that purpose, the plant unit master (PUM) at time t, 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 if 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.

To this effect assuming a load decrease as afore-stated illustratively, the plant unit master load 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 t, to time t2 along curves BC' and be 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 after burner is fired down to its minimum along BC as shown from t1 to in Fig. 4C. Thus, the PUM controller, at time t, 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 firing of the afterburner (A/B) to a minimum at time t2. Accordingly, a bypass flow has been established as shown by curve be 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 t, and t3) caused by the reduced firing of the gas turbine 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).

Therefore, as shown from time t2 to time t4 steam turbine flow is decreasing slowly between time t2 and time t3, then, increasing from t3 tot4 while bypass flow is going to zero from t2 tot4, since from to to t4 more steam is demanded and the inlet steam flow is being reduced. The gas turbine loading is going slower (DE on Fig. 4B) while steam turbine loading is increasing (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).

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 generation of power is maximized. Thus, from time t1 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 (Bd and be 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. 4A) 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). Convergence 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 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. Patent No. 4,258,424. In this patent is described the relationship between the operator panel, the plant unit master and the speed and load control forthe 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.

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 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 is further limited to a maximum velocity of steam to minimize erosion of the steam generator tubes and 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 to maintain optimum plant efficiency and stability.

The present invention is concerned with controlling the gas turbine and afterburner as part of a megawatt load control system for the steam turbine.

In all the references 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 process 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. SA-SC, 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 224 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&num;1 and CT&num;2) and afterburners are controlled by their respective controllers (349 and 249 for CT#1, 349' and 249' for CT&num;2, in Fig. 5A and 305,305' for the afterburners in Fig. 5C) to operate at maximum efficiency for the particular level of the load (MW1 on lines 369 and 201 for CT&num;1, MW2 on lines 369' and 202 for CT&num;2 in Fig. 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 automatically controlled by the DEH system operating on the governor valves for maximum utilization of the steam received in terms of temperature, 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 tTH is derived on line 237 (Fig. 5C) and the throttle pressure Pth control set point is derived on lines 236 and 225 for the following mode, used by line 236 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, 352' for the gas turbines, as will appear from the description hereinafter.

The megawatts generated by the gas turbines CT1, 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 indicative 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) of the steam turbine calculates the throttle pressure set point and 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 relationship during turbine control valve operation in a sliding pressure type of steam bypass and control valve control.

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 governorvalves are controlled in accordance 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 which 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 952 F the desired operative temperature forthe steam, and 0% MWto only 700'F at the inlet, the intermediate percentages being linearly distributed. This is to insure that the steam turbine takes load only in station 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 301. The signal of line 301 is passed to 105 via another switch 302 onto line 303, then to subtractor 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 t1, Fig.

4A) to the system on line 206 (Figs. 5A, 5B). The new target is carried by line 206 over to a subtractor 207 where an error is developed on line 208 from the comparison of 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 (MW1, MW2) on lines 202 and 202, respectively. An error due to an excess or a want 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#1 and CT&num;2 were set by lines (369, 368) and (369', 368') to operate at the present loads MW1 on line 369 and MW2 on line 369'.Inhibit signals on lines 507, 507', respectively have set equal both inputs 365 and 506 to subtractor 500 so that no response by the ramps RMP1, 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 low select circuit 218 establishes by line 219 a maximum set point, typically of 117.2 MW, 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 of 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 Pm signal of line 230 is compared with the ramp output on line 229 for 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 from zero to 10 volts, such that for 5 volts there is no change in load. The after burners are controlled in parallel via lines 305 and 305' for loading the detected MW error into the afterburners.

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#1, 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 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 as 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 circuit 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&num;2 when CT&num;1 is OFF or via lines 352 and 352' when both are ON.

Considering again only gas turbine CT#1, 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 RMP1 will increase or decrease to catch on the assigned 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 operator'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 amplifier 382 and line 383 as applied to MW rate 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 0 and 20 MW/min the required rate on line 383 is summed up with the output on line 246 from MWA rate controller 244.

The latter is a PI controller responding to the difference between the required AMW setting (0 20 MW/min) and the computed value on line 243 derived from differentiator 242 which is converting the total plant MW of line 205. Thus, a correction of +10%, typically, is added to the assigned AMW setting of line 383, by MW rate corrector 384. This corrected value is applied by line 247: to the steam turbine ramp slope determinating circuit 307 (by line 316, switch 314 and line 313), to the RMP1 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 thatthe enabling signal on lines 507, 507' will permit the gas turbines CT&num;1 and CT&num;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&num;1 and CT&num;2, in Fig. the actual MW of the gas turbine on line 369 (for CT&num;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 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 establishing a ~5% deadband at the output 387 in order to enable the MWA 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 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 taking 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 according 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 initial time An error is calculated at 201 which inputs a negative signal (assuming a lower target as in Fig. 4) into summer 216 which results in a reduced demand on the steam turbine.

If the A demand exceeds 5% at 386, the megawatt A rate controller 244 is put into service by line 387.

This controller compares the actual to the maximum rate, then, controls the steam turbine rate function via lines 247,316 and 313 and via lines 248 and 248' for the gas turbines. The megawatt error by line 250 is also inputted into summer 253 to result in a reduction of afterburner (A/B) firing level.

The steam turbine and afterburner will attempt 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 (time t2 in Fig. 4C), i.e., no further modulation thereof is possible. At this point, by line 507 control upon switch 505 for gas turbine CT&num;1 (by line 507' upon switch 505' for gas turbine CT&num;2) will switch the position thereof from the zero setting on the Y-position to the N-position for which the error from line 305 manifests itself through summer 500, whereby by line 505 through ramp RMP1 the gas turbine CT&num;1 is brought to share the unloading rate (the same can be said for gas turbine CT&num;2 by line 565' and ramp RMP2). This effect is recognizable aftertimet2 in Fig. 4.

This process will continue until the plant megawatt target is reached at time t4 (Figs. 4A-4C).

In this respect, at time t3 the plant may be in a very inefficient operating mode, for instance with a lot of steam being bypassed around the steam turbine to the desuperheater and the condenser. The control system, according to the invention, will restore the most 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, namely at time t4.

It appears that upon a load transient the PUM controller 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 developed whereby throttling will be required under the following conditions: a) The operator (or a remove load dispatch system) requires a load reduction at a rate which it responds to by a reduced fuel firing along (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 when the steam temperature is ramped at7-1/40F per min. This provides loading rate control on the steam turbine on initial loading.

The allowable steam turbine load function generator maintains a load setpoint which corresponds to the highest allowable load which the steam turbine can instantaneously assume without exceeding rotor stress limits.

Reviewing 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.

Load changing can be affected with the PUM from the most highly automated to the least automated or combined PUM/manual control mode. It operates in both unloading and loading situations.

In accordance with the present invention PUM plant unloading and loading with the steam turbine is performed in the "PUM" or the "Follow" mode.

Such selectively control mode can be set by the operator at a selector switch on the steam turbine primary panel.

In the PUM mode, the plant will be more responsive 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 isfasterthanthe rate which can be achieved by the afterburners unloading. In contrast, the plant cannot respond to the load changes s rapidly when the steam turbine is in the "Follow" mode. Then, the steam load change ramp will be established by the afterburner temperature 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 runbackrate, 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 load will hold and the afterburners will continue to modulate until the steam turbine bypass valve is fully closed. All 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 optimize the plant full efficiency by shutting down the afterburners 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 increase 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 temperature 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 necessary 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 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 governorvalveswill 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 load target is reached, the combustion turbine(s) will begin to share the plant unloading rate until the plant megawatt target 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 combustion 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 tull load, the sequence is as follows: The combustion turbine load will begin to increase. 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 turbines, afterburners, and combustion turbines automatically. The PUM controller will also modulate the plant load when the control system is in a less automated mode, specifically when one (1) 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 combustion turbines in manual setpoint control may result when the plant is operating under conditions which are undesirable, such as operation with high afterburner firing temperature 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 (12)

1. A combined cycle electric power plant including a cogeneration system having a steam turbine supplied with steam from a heat recovery steam generator (HRSG) having at least one gas turbine and an afterburner associated therewith for producing an electrical load jointly with said steam turbine, said steam turbine being operable in one of a follow mode and a plant unit master (PUM) mode, with said steam turbine in the follow mode being controlled to generate power in accordance with the HRSG steam output to satisfy a current predetermined plant load level, in which first controlling means is operable in the PUM mode in relation to a substantial change in said current predetermined plant load for controlling the afterburner, second controlling means operable in the PUM mode in relation to said plant load change for controlling the gas turbine to effect a corresponding load change therein, and third controlling means operable in the PUM mode in relation to said plant load change for controlling said steam turbine to effect a corresponding load change therein, said first, second and third controlling means concurring in setting a new predetermined plant load for said steam turbine in the follow mode.

2. A system as claimed in claim 1 in which said first controlling means being responsive to a steam pressure related control signal established for said steam turbine and to said plant load change.

3. A system as claimed in claim 2 in which said second controlling means including means responsive to said current predetermined plant load for generating a corresponding plant load rate representative signal and first ramp means for said gas turbine for generating a first ramp signal in relation to said plant load change, said gas turbine being controlled in accordance with said first ramp signal.

4. A system as claimed in claim 3 in which said third controlling means including second ramp means operative in the follow mode in relation to said steam pressure related control signal for generating a second ramp signal to control said steam turbine, and operative in the PUM mode in relation to said plant load change for generating a third ramp signal to control said steam turbine.

5. A system as claimed in claim 4 in which said first ramp means being also responsive to said third steam pressure related control signal.

6. A system as claimed in claim 5 in which said first ramp means being also responsive to a signal representative of current steam turbine load.

7. A system as claimed in claim 6 in which said first ramp means being selectively controlled into one of a hold and an operative mode.

8. A system as claimed in claim 7 in which said second ramp means being selectively controlled into one of a follow mode and PUM mode; said first ramp means being set in its operative mode while said second ramp means is its PUM mode.

9. A system as claimed in claim 8 in which said second ramp means being adapted to be selectively controlled to be responsive to a steam turbine load representative signal for tracking thereof.

10. A method of reducing from an initial load the operative load of a steam turbine supplied with steam from at least one cogenerating gas turbine assisted with an afterburner comprising the steps of assigning a lower load for said steam turbine, controlling said steam turbine and afterburner concurrently to a lower unit of said afterburner while throttling said steam turbine, whereby, to partially reduce steam to initial load, controlling said gas turbine after said afterburner limit of control to further reduce said load while reducing said steam turbine throttling, and increasing said steam turbine load toward said assigned lower load while reducing throttling of said turbine to zero and reducing said gas turbine load to a predetermined shared cogeneration load.

11. A method as claimed in claim 10, in which the method includes increasing from an initial load to operative load of a steam turbine supplied with steam from at least one cogenerating gas turbine assisted with an afterburner and assigning a higher load for said steam turbine, controlling the gas turbine to raise load thereof up to base load so as to increase steam turbine load, controlling the afterburner operation up to a higher limit after said gas turbine is at base load, and controlling the steam turbine to reach said higher load.

12. A combined cycle electric power plant, constructed and adapted for use substantially as hereinbefore described and illustrated with reference to the accompanying drawings.