Available online at www.sciencedirect.com
ScienceDirect Procedia Technology 12 (2014) 716 – 722
The 7th International Conference Interdisciplinarity in Engineering (INTER-ENG 2013)
Simulation of speed steam turbine control system Mircea Dulaua,*, Dorin Bicab a,b
Department of Electrical and Computer Engineering, “Petru Maior” University of Tîrgu-Mureş, 1 N.Iorga st., 540088
Abstract Steam turbine control systems are being designed with today’s technology to operate a turbine in a safe and reliable manner. There are many considerations to be taken when choosing a controller for steam turbine applications. Many benefits may be realized by choosing the proper steam turbine control system, whether it is a mechanical, an electrical or a programmable controller system. This paper presents the basic concepts of the steam turbine control system and develops the fundamentals of the speed control. Using Matlab/Simulink software facilities, have been simulated the speed variations, of the steam turbine-load unit, connected with a mechanical-hydraulic system, than the speed deviations of the steam turbine-load unit, to different load deviations, proportional and proportional-integrative control algorithms. © 2013 The Authors. Published by Elsevier B.V. © 2013 The Authors. Published by Elsevier Ltd. Open access under CC BY-NC-ND license. Selection and peer-review under responsibility of Department of Electrical and Computer Engineering, Fac ulty of Engineering, Selection and peer-review under responsibility of the Petru Maior University of Tirgu Mures. “Petru Maior” University of Tîrgu Mureș. Keywords: steam turbine; mechanical-hydraulic governor; speed control; frequency control;
1. Introduction Steam turbines are energy conversion machines. They extract energy from the steam and convert it to torque, which rotates the shaft of the turbine. The amount of energy that t m is a function of its temperature and pressure, as outlined in [5, 7, 9, 11]. There are two categories of steam turbine controls as follow: safety (protection) system and process system. The
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2212-0173 © 2013 The Authors. Published by Elsevier Ltd. Open access under CC BY-NC-ND license. Selection and peer-review under responsibility of the Petru Maior University of Tirgu Mures. doi:10.1016/j.protcy.2013.12.554
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turbine safety systems are intended to eliminate/minimize the possibility of damage to the machine or the hazard to operators. It protects the turbine from overspeeding, monitors all critical turbine parameters, and trips the turbine if a condition exists that could cause equipment damage. The main safety control element on a turbine is the steam supply valve. This safety valve can be a separate on/off valve or the shut-off function can be incorporated into the controls of the steam supply valve that is used for speed control. The process systems control the operation of the steam turbine, so as to follow the load in a stable and efficient manner. The steam turbine is controlled by the governor, which can be mechanical-hydraulic (developed from James Watt’s original flyball governor) and/or electrical. They all include a pilot valve, or controller, which modulates the turbine’s inlet valve in order to keep the shaft speed on set point. An electro-hydraulic control system use electronic circuits, is more flexibility, but the overall requirements are similar. A digital electro-hydraulic control system, use a digital controller and a lot of functions can be implemented through software. Even the advanced controls usually operate the high-pressure and low-pressure valves through the existing electro-hydraulic controls of the turbine. A typical governor model for steam turbines has two main sections, the governor and steam control valve, whose output is effective control valve area in response to speed deviation of the machine, and a section modelling the turbine, whose input is steam flow and output is mechanical power applied to the rotor (Fig. 1) [4,5,7,9,11]. Speed deviation
Governor control Steam valve
Steam flow
Control valve position
Steam Turbine
Mechanical power
Steam pressure at Control valve Fig. 1. Typical model for steam turbine control.
In this block diagram, steam flow to the turbine is the product of valve area and throttle pressure. Thus, if throttle pressure drops due to an increased demand in steam flow, the valve area must further increase to maintain the same flow as compared with the simplified model. 2. Fundamentals of speed steam turbine control A steam turbine control system is a closed loop system. The simplest application is one in which a turbine is used to operate a rotor to constant speed (Fig. 2). The controller senses the shaft speed, compares the actual speed with the desired set point. If there is a difference between the actual speed and desired speed, the controller sends a signal to the actuator operating the steam valve, which will adjust the speed until the two are again balanced [1,2,3,5]. Variations in load, caused by shaft loading or variations in pressure supply, affect the balance between the energy supplied to the turbine from the steam system and the work removed from the turbine’s shaft. If more energy is available than is being used, the shaft will speed up. The controller will detect this increase in speed and act to eliminate it. Its means of doing so is to reduce the energy supplied to the turbine by closing the supply valve. Valve position Set point
Controller (Governor)
Mechanical power Steam turbine
Feedback Fig. 2. Control system block diagram.
Rotor (inertia)
Speed
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If the net change in the energy balance were negative, the shaft would slow down and the controller would respond by opening the supply valve. On a steam turbine, two types of controls are highlights [5,6,7,8,9]: x droop control or proportional-only control (P), defined as a decrease in speed with an increase in load, produces a change in valve position proportional to the signal between the speed set point and the actual speed; the main disadvantage of proportional-only control is that it cannot completely eliminate the error caused by a change in load. x isochronous control, defined as no decrease in speed with an increase in load, maintain the speed of shaft rotation constant regardless of load; in order to eliminate the error and to minimize the overshoot, it is accomplished with proportional and integrative (PI) controllers, usually in conjunction with derivative (D) controller, resulting the steam PID type controllers. Depending on the control required and the number of valves, a steam turbine may employ several control loops, each of which requires a feedback loop. 3. Simulation of the speed steam turbine control system Depending on configuration, the steam turbine is equipped with high pressure valves (HPV), re-heater valves (RHV), and consist of high pressure (HP), medium pressure (MP) and low pressure (LP) sections (Fig. 3) [15]. As a requirement for any turbine - generator unit, the speed/load control function is achieved through the control of the HPV (adjust the speed/load set point to control admission of steam to the turbine through HPV pos). In addition to the HPV, a second valve is required. It controls the steam flow rate that is extracted from the HP section of the turbine and is sent to the MP, LP sections and crossover pipe (CP). The integrity of the turbine depends on the possibility to limit the speed, involving the reheat valve position (RHV pos). The re-heater stores a large amount of steam so, the HPVs control is not enough to limit the overspeed. The overspeed control involves fast control of the HPV and RHV, because the RHV controls about 60% to 80% of the total power (steam flow to MP and LP sections). The output of the speed sensor is compared with the speed set point and the error signal is used to control the HPV and RHV. The power servos are used to amplify the energy levels necessary to move the steam valves. Boiler
CP HPV pos
Shaft
HPV
HHP(s)
HMP(s)
HLP(s)
G
RHV RHV pos HRH(s) Power servos
Speed control Speed/load set point
Fig. 3. The steam turbine configuration with speed controller.
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Each of the turbine section is described by a transfer function H HP s , H MP s , H LP s , H RH s and depends on time constants THP , TMP , TLP , TRH . Neglecting the smallest time constants, a simplified transfer function of the steam turbine configuration (with re-heater) may be written, as follows [3,5,10,13]:
H T s
TRH K HP s 1
(1)
THP s 1 TRH s 1
where: K HP is the power fraction of the HP turbine section. The load is described by the simplified form:
H L s
1 TL s
(2)
If the control system is a mechanical-hydraulic type, the commonly referred is speed relay in conjunction with servomotor, described by the transfer functions [5]:
H SR s
1 TSRs 1
(3)
H SM s
1 TSM s
(4)
where: TL , TSR , TSM are time constants. The block diagram of the turbine-load unit, connected with a mechanical-hydraulic system is presented in Fig. 4. With Matlab/Simulink facilities, result the speed, as an output variable, depending on the control valves position (HPV pos and RHV pos), as input variables [14]. The results show the speed variations (Fig. 5a), obtained to different positions of the RHV (where 100% means fully open), and a profile of the input and command signals (Fig. 5b). The presented responses are computed with: TSR 0.1 sec., for speed relay, TSM 0.3 sec. for servo, TL 12 sec. for load, THP 0.3 sec., TLP 0.5 sec.,
TRH 7 sec. and K HP 0.3 for steam turbine. These demonstrate that, although the input signal is the same, there are significant differences in transient responses. If one parameter of the load varies within a specific range of values or percentage, result the process affected by uncertainties. In this case, the mechanical-hydraulic control system works properly, according to the simulation diagrams, presented in Fig. 6, where the nominal value of the load ranges with 25% [14]. SP
Kc
HSR(s) Speed relay
HSM(s) Servo
HPV pos Speed RHV pos
% RHV pos Fig. 4. Simulink block diagram with mechanical-hydraulic control system.
Turbine - load
Speed
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a
b
Fig. 5. Speed variation: (a) to different RHV positions; (b) with input and command signals.
Fig. 6. Speed variation, obtained to variable load.
The frequency of the system is dependent on speed, which should remain nearly constant [5,12]. The block diagram from Fig. 7 includes representation of the speed controllers, turbine and load in a feedback connection [14]. With primary control loop action, a change in system load will result in a steady-state speed deviation, depending on the controller characteristic. Restoration of system speed to nominal value requires supplementary control loop with an integral action. Depending on power system type, the supplementary control loop takes effect after the primary control has stabilized the system speed. The step responses, for reheat steam turbine, are computed using typical parameters, presented in [5,15]. The turbine representation is based on the simplified transfer function, described by relationship (1), respectively: HT s 2.1s 1 > 0.3s 1 7s 1 @ . The load with damper is described by a first order transfer function, H L s 1 TL s 1 , where: TL
10 sec. is the load time constant. The P and PI controllers are classical, with tuning parameters: K P 20 , proportional value and TI 15 sec., integrative time [5,15]. Fig. 8 illustrates the speed deviation, obtained with P and PI controllers, to load deviation equal with 0.7 from load set point, both starting with zero time. Fig. 9a shows the speed deviation, obtained to a profile of load deviation equal with (0.7; 0.4; 0.9), applied to t0 0 sec., t1 15 sec. and t 2 22 sec. In Fig. 9b the speed deviation is
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obtained to a profile of load set point equal with (1; 0.5; 0.75), applied to t0 0 sec., t1 15 sec. and t 2 22 sec. [14]. The results demonstrate that, depending on the controller type, the transient responses are different and the integrative control action ensures zero speed error in the steady-state. Supplementary control loop Speed dev
Cmd
Cmd
Torque Torque
PI controller
Load deviation
Turbine Load dev
Load set point
Load ref
Torque Cmd
Speed dev
Cmd
Torque
Load
Turbine
P controller
Primary control loop
Fig. 7. Block diagram for speed deviation control.
Fig. 8. Speed deviation control with P and PI controllers.
a
Speed dev
Speed deviation
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b
Fig. 9. Speed deviation control, with P and PI controllers, to different: (a) load deviations; (b) load set points.
4. Conclusions In order to meet the frequency demand, which should remain nearly constant, the speed steam turbine must be controlled. There is a direct relationship between the turbine speed and the position of the turbine valve. The dynamic response of the steam turbine is influenced, mainly, by the entrained steam into high pressure turbine section and the storage action in the re-heater. When a turbine-load unit is connected and synchronized to the grid, the speed cannot be changed, but the speed set point can. If the speed set point is raised, the valve will open, increasing the load and if the reference is lowered, the valve will close and lower the load. In this case, the proportional-only (droop) controller is an excellent means of load control. In order to maintain the speed of shaft rotation constant regardless of load (an isolated power system case), a supplementary control loop is needed, which takes effect after the primary control has stabilized the system speed. Depending on the size of the load set point, load deviation and on the control type, the response of the stream turbines may be slower or faster. With the suitable speed controllers, steam turbines can provide very good speed stability. References [1] Azubalis M et al. Identification of model parameters of steam turbine and governor. Oil Shale. Vol. 26; No. 3 Special; Estonian Academy Publishers; 2009. p. 254–268. [2] Bennauer M et al. Automation and control of electric power generation and distribution system: steam turbine. Encyclopedia of Life Support Systems. Vol. XVIII; 2012. [3] Chaibakhsh A et al. Simulation modelling practice and theory. 2008. p. 1145–1162. [4] Feltes WJ et al. Boiler effects on steam turbine response. New York Power Technologies Inc; 2002. [5] Kundur P. Power system stability and control. McGraw-Hill Professional; 1994. [6] Inoue T et al. A thermal power plant model for dynamic simulation of load frequency control. IEEE Power Systems Conference and Exposition. Atlanta; 2006; p. 1442 – 1447. [7] Lamberson SJ et al. Steam turbine governing system and electronic governor retrofit. Proceedings of the 28th Turbomachinery Symposium. Texas; 2012; p. 157-164. [8] Lilje P. Stability analysis of an islanded generator. Power Plant and Power Control. IFAC Publications. Kananaskis; 2006, p. 159-164. [9] Liptak BG et al. Instrument engineers' handbook. Steam Turbine Controls. 2006; p. 2137-2151. [10] Moura FAM et al. Steam turbines under abnormal frequency conditions in distributed generation systems. InTech. 2012; p. 381-400. [11] Murty MS. Modelling of steam turbine and its governing system. Program for CEE on Power System Analysis and Operation. Colombo; 2010. [12] Vinotha KX. Frequency regulation by free governor mode of operation in power stations. IEEE International Conference on Computational Intelligence and Computing Research. 2010. [13] Yang T et al. Parameter identification of steam turbine speed governor system. IEEE Power and Energy Engineering Conference. Shanghai; 2012; p. 1 – 8. [14] ***. Matlab and simulink tutorial. The MathWorks; 2010; www.mathworks.com. [15] ***. Technical documentation. Iernut thermoelectric power plant; 2010.
