Accepted for presentation at the Power Systems Computation Conference, June 24-28 2002, (PSCC02), Sevilla, Spain
SOLVSIM POWER STATION – A NEW SAFE WAY OF TESTING THE FREQUENCY CONTROL AND ISLAND OPERATION CAPABILITY OF POWER STATIONS
[email protected]
Abstract – SolvSim Power Station is a unique hardware-in-the-loop simulator, which makes it possible to test speed droop, speed governor time constant and island operation capability when the power station is synchronized to the main grid. The simulator is adopted to fit all types of power stations and is a suitable tool for the power system operator to use when validating ancillary services. Tests show that the speed droop can vary considerably with the loading. It also emphasizes the need to perform island operation tests as faults in the power station and improper parameter settings can be discovered.
Keywords: SolvSim Power Station, frequency control, speed droop, island operation, field measurement. 1 INTRODUCTION The restructuring of the electricity market, which is taking place in many countries around the world, has changed the situation for the producers of electricity. In addition to the energy trading there is also a market for speed droop, ramping, frequency control reserve and disturbance power reserve. In some countries the restructuring has also lead to a situation where there is a shortage of power during peak power. When operating the power system close to the maximum the risk for customers to be disconnected from the grid will increase. The risk for a major blackout will also be higher. During such situations it is necessary to be well prepared for the restoration process in order to be able to restore the power system as fast and secure as possible. The restoration process can take place in one or several islands in parallel and it is important that the speed governors of the power stations in these islands are tuned also for island operation. For processing industries having in-house production an alternative during severe situations on the main grid can be to operate the plant or parts of the plant together with the own generator(s) in island operation. This paper gives a description of the HWIL simulator SolvSim Power Station, SSPS, which is used for testing speed droop and island operation capability of different power plants. Results from two of the field studies performed at a hydro unit and a gas turbine are presented. Based on these field studies the unit responses are explained and conclusions are drawn.
Håkan Hermansson Vattenfall AB Elproduktion Stockholm, Sweden
[email protected]
2 WHAT IS SOLVSIM POWER STATION? In order to meet some of the new challenges in the electricity market Solvina and Svenska Kraftnät (national grid owner and system operator) have designed a hardware-in-the-loop simulator called SolvSim Power Station. The simulator technique is based on the work performed in [1]. The simulator is used for verifying the speed droop of power stations and for testing of the island operation capability. Previously these types of tests have not been possible to perform without varying the frequency in the entire system or by disconnecting a power plant and some load from the main grid and run it in a real island operation. As these tests are risky they are not often performed. The principle of SolvSim Power Station, SSPS, is that the normal frequency feedback of the governor is replaced by a simulated frequency from a simulator – i.e. hard-ware-in-the-loop. Power Station
Measurements
[email protected],
[email protected]
Morgan Emanuelsson Svenska Kraftnät Stockholm, Sweden
Control Signals
Evert Agneholm and Niclas Krantz Solvina AB Göteborg, Sweden
Gen.
Actual Frequency
Frequency Controller
Generated Active Power
Simulated Frequency
SSPS HWIL (Data Aquisition and RT Simulation)
National Power System ARISTO
Remote PC Network
Figure 1 The principle of SSPS. SSPS is a combined real-time simulator, data acquisition system and controller designed for generating various signal types and levels in order to fit any type of regulator. Due to its flexibility SSPS can be used in most types of power plants. SSPS has several different operating modes. In “Open-Loop test” a predefined frequency signal feeds the speed governor. This signal can be a step, a ramp or an arbitrary signal, for instance a recorded frequency signal from a real event in the power system. This operating mode is suitable for testing the speed droop of the power plant. In “Simulation On-Line” the frequency is simulated from an island system, which includes the tested generator. The simulated system can
Accepted for presentation at the Power Systems Computation Conference, June 24-28 2002, (PSCC02), Sevilla, Spain include production plants with speed governors, turbines, boiler and fuel control for thermal plants and the water conduits for hydro plants. Loads can have arbitrary frequency dependencies and be equipped with load shedding. Also HVDC with frequency control capacity can be included in the model. For production plants and loads it is important to know the inertia since it has a strong impact on the dynamic behaviour of a power system, especially in a small island system. From the investigated power station a number of signals can be measured. When operating the simulator in “Simulation On-Line” the active power of the generator is used as an input to the simulation model. Other parameters can be measured for off-line analysis or for supervision and alarm settings for critical variables. The safety functionality for SSPS is rigorous in order to minimize the risk for trip or damage of the plant. The simulator is equipped with watchdog functions and several levels of emergency shut down functions, which are automatically activated by specified alarms or manually by the operator. As can be seen in Figure 2 the model only takes the active power into consideration whereas the network and the voltage dynamics are neglected.
Simulated frequency
Pgenerated +
? P
Load Loads 1
HVDC
1 2 ? Hn Sn
+
1 s
f0
In Figure 3 a specific case where the difference between “real” island operation and the “SSPS” way of island operation is demonstrated. 51
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3 POWER STATION TESTS At the end of 2001 island operation tests have been performed in several types of power stations. So far three Kaplan units and one gas turbine have been tested. In the near future tests of combined heat and power units will be performed. In this section the results from tests of a Kaplan unit and a gas turbine unit are presented. 3.1 72MW hydro power plant with Kaplan turbine The hydro power station investigated consists of three parallel units with Kaplan turbines. The three units are equipped with ASEA speed governor FRVA and operate with the wicket gate opening as feedback signal. The power station provides ancillary services for frequency control and black start capability. In order to assure the capability of frequency regulation SSPS was used to test one unit in the station. The main purposes of the test were to: Verify speed droop and speed governor time constant Evaluate the island operation capability
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Power prod
Figure 2 The Principle of SSPS frequency calculation.
10 -10
load and a SSPS island operation test performed in the power system laboratory at Chalmers University of Technology. In the “real” island case the motor is exposed to a step increase in the mechanical load whereas in the “SSPS” test case the load step is simulated. The curves are almost identical, except for the fact that the “real” system is slightly better damped.
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Figure 3 Comparison between “real” island operation (green) and an island operation test with SSPS (blue). The curves in the figure show a “real” island test system using a generator, a long radial line and a motor
3.1.1 Verification of speed droop and speed governor time constant When verifying the speed droop and the speed governor time constant various step increases and decreases of the frequency for the five different operating modes were performed at 30 and 70% loading. An example from such a test is shown in Figure 4 where both the wicket gate opening and the active power are presented for a step decrease in frequency from 50 to 48 Hz. The results of the tests showed that the speed droop and the time constant agree with the parameter settings when studying the wicket gate opening response. However, when studying the active power the speed droop varied considerably with the wicket gate opening. The speed droop varied from 60-170% of the specified parameter setting 100%. The lowest speed droop was achieved for a step decrease at 70% loading whereas the highest speed droop was achieved for a step increase at 30% loading, i.e. the speed droop decreases with the load level.
Accepted for presentation at the Power Systems Computation Conference, June 24-28 2002, (PSCC02), Sevilla, Spain 95
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Wicket gate opening Active power
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65 ? P=21.25 MW
80 63.2% ? P
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Wicket gate opening (%)
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dP da 0
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Figure 4 Step decrease in frequency from 50 to 48 Hz at t=0. Parameter settings of speed droop R=20% and speed governor time constant 60 s. Rated power 72 MW.
where P is the active power and a0 is the wicket gate opening. As can be seen in Figure 6 the active power derivative will be less than 100% when the wicket gate opening is small whereas it will be larger than 100% when the wicket gate opening is large. For large wicket gate openings a change of the opening with x% will result in an active power change that is greater than x%, i.e. the derivative is larger than 100% For small wicket gate openings a change of the opening with x% will result in an active power change that is less than x%, i.e. the derivative is less than 100%. When the derivative is 100% a small change of the wicket gate opening with x% will result in a change of the active power with x%.
. . .
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Speed droop, R or Ep, is defined [2] as the change in
R ? Ep ?
?f ? 100 (%) ?P
(1)
The variation in speed droop for a Kaplan turbine, working with the wicket gate opening as feedback signal in the speed governor, can be explained by studying a principle description of the variation of active power as a function of wicket gate opening and runner blade angle. As can be seen in Figure 5 the use of runner blade angle regulation, see the cam curve, increases the efficiency of the unit considerably.
dP d a0
160 140 120 100 80 60
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40 20 0 0
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Figure 6 Principle description of a Kaplan turbine.
100 Cam curve
Active power (%)
180 Active power, power derivative (%)
power, ? P (%), after a frequency change, ? f (%)
(2)
Various runner blade angles
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In Sweden Francis turbines are also common. For Francis turbines the runner blade angles are fixed and there is only a variation in the wicket gate opening. In the same way as for the Kaplan turbine a principle description of the active power as a function of the wicket gate opening for Francis turbine is shown in Figure 7.
50 Wicket gate opening (%)
100
Figure 5 Principle description of a Kaplan turbine. In Sweden most of the hydro units have wicket gate opening as feedback in the speed governor since it has a positive impact on the stability. Therefore it is of interest to study the relationship between the active power and the wicket gate opening at different loadings of the unit. A suitable parameter to study is the active power derivative:
Active power, power derivative (%)
180 dP d a0
160 140 120 100
P
80 60 40 20 0
0
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30 40 50 60 70 Wicket gate opening (%)
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Figure 7 Principle description of a Francis turbine.
Accepted for presentation at the Power Systems Computation Conference, June 24-28 2002, (PSCC02), Sevilla, Spain
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3.1.2 Evaluation of island operation capability The island operation capability of the hydro unit was tested in a large regional island grid consisting of several production sources and a small simulated island grid consisting the tested unit as the only frequency controlled unit. The result from the large regional island grid test showed that the tested generator operated as expected. During this test large and small step increases and decreases of the load were performed. This in combination with a regional system equipped with HVDC emergency power and load shedding. The results from a disconnection of a load in the system are presented in Figure 8. As can be seen the load decrease results in an increase of the frequency and a decrease of the production in the studied unit. In the figure it can also be seen when the speed governor automatically changes operating mode and when the runner blade regulation starts. 50.3
70 50.2 Frequency
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Wicket gate opening
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Automatic change of speed governor operating mode
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Frequency (Hz)
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50 Start of runner blade regulation 45 -50
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Figure 8 Verification of the island operation capability in a large regional island grid. Response of the tested unit. The switch over to simulated island operation of the small system is shown in Figure 9. As can be seen the system becomes unstable and a manual emergency interruption of the test is performed. The reason for this
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Figure 9 Switch over to simulated island operation. The system becomes unstable. 3.2 63 MW one-axis gas turbine The main task of the two gas turbines in the tested power station is to be a system power reserve at power shortage. In case of a major blackout the power station will be black started and then together with other power stations it will be run in a regional island grid. In order to assure the frequency control capability SSPS was used to test the station. The main purposes of the test were to:
. . .
Verify speed droop and speed governor time constant Evaluate the island operation capability Validate simulator models
3.2.1 Inertia estimation In order to determine the total unit inertia, a 30 MW load rejection test was performed. The generator frequency was recorded and by means of the frequency derivative at the load rejection instant, the inertia was calculated to 9,4 MWs/MVA according to: 1 1 2 1 1 J? 2 ? T ? Pmek fPmek W kin 2 (3) H ? ? ? 2 ? 2 ? 2 d? d? df Sn Sn Sn Sn Sn dt dt dt where Pmek = Pel / ? = 30/0,972 = 30,86 MW Sn = 65 MVA df/dt= 1,2/0,95 = 1,26 Hz/s f = 50 Hz
Frequency (Hz)
.
behavior was too small pressure reserves in the hydraulic system in combination with bad parameter settings of the speed governor. The power plant owner has therefore performed modifications of the unit and the parameter settings, which will enable island operation capability. During the test also transmitter malfunctions were discovered. Active power and wicket gate opening (%)
As can be seen from Figure 7 the active power derivative will be less than 100% when the wicket gate opening is large whereas it will be larger than 100% when the wicket gate opening is small. For large wicket gate openings a change of the opening with x% will result in an active power change that is less than x%, i.e. the derivative is less than 100% For small wicket gate openings a change of the opening with x% will result in an active power change that is larger than x%, i.e. the derivative is larger than 100%. When the derivative is 100% a small change of the wicket gate opening with x% will result in a change of the active power with x%.
Accepted for presentation at the Power Systems Computation Conference, June 24-28 2002, (PSCC02), Sevilla, Spain results of the following settings of gas turbine 1 and 2 are shown below to illustrate the possibilities with the SSPS test method.
Frequency
50.0
-0.5
0.5 Time (s)
0
1
1.5
Figure 10 Frequency at a 30 MW load rejection test. 3.2.2 Verification of speed droop and speed governor time constant According to the regulator settings the speed droop Ep is 6 %. When verifying the speed droop and speed governor time constant a step decrease of 0.5 Hz was applied to the speed governor. As a result the active power production increased which can be seen in Figure 11. From this test the speed droop and the speed governor time constant were calculated. The results agree with the parameter settings of the speed governor. Since the droop is created by means of the electrical power, the droop value will be accurate at any load level, compare the hydro unit in 3.1.1. 50.2 0
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Figure 12 A load step of 24 MW, Ep1=6%, Ep2=6%. The load is shared equally between the two units both dynamically and stationary. 45
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Frequency derivative 50.8
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Figure 11 Verification of the speed droop and the speed governor time constant. 3.2.3 Evaluation of island operation capability The island operation capability of the gas turbine was tested using a small simulated island system in SSPS. Tests were performed both with the tested unit as the only production source and with the tested unit together with an additional identical gas turbine. During the test various steps of the simulated load were performed. These load changes resulted in simulated frequency changes, which the speed governor was exposed to. Different strategies can be used regarding load sharing. One machine can be master and both can contribute equally to the power/frequency control. The
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Figure 13 A load step of 12 MW, Ep1=0%, Ep2=6%. Initially both units contribute to the frequency control but stationary unit one takes the whole power increase. From these tests it was concluded that the island operation capability was excellent. Load steps of 20% of installed production capacity were no problem. This is due to the high inertia and the fast response of these gas turbines. If there is no clear strategy for how to set different parameters, this type of test is beneficial both for tuning and for verification of the settings and the dynamic behavior. 3.2.4 Model development and validation When making island operation studies, the demand for accurate power station models is quite high. As the model and data availability often is poor, simulation results could be quite doubtful if there is no possibility to verify and validate the results.
Frequency (Hz)
51.2
Accepted for presentation at the Power Systems Computation Conference, June 24-28 2002, (PSCC02), Sevilla, Spain the phase displacement increased for higher frequencies, as can be expected. The dotted line denotes the undamped response caused by the droop factor.
With SSPS the possibilities to make verifying tests have been shown. In addition there are also huge opportunities to improve the simulator models using registration results for model development and validation during Step response tests Frequency analysis and phase and angle characteristics. Figure 14 shows a comparison between an off-line simulation and the result from the test performed. The test method is ideal for model validation due to the possibility of the off-line simulation mode. Instead of running the real power unit a model is simulated, with the same surrounding island system, loads, power units etc.
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Frequency Simulated using measurements
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Figure 14 Comparison between a test and an off line simulation. Frequency analysis can be made in the open-loop mode i.e. the frequency is varied with a specific range of frequencies and amplitudes. Registration is made of the response in an arbitrary number of places in the system, from regulator, servo and valves to the generator. In this way model identification or validation can be carried out in a very effective way. Figure 15 shows the frequency characteristic in a bode plot for the tested gas turbine. 6
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Turbine power
Amplitude 120
3 80 2 1 0 120
40
Phase 50.25
21.04 8.81 Period time (s)
3.69
0 1.55
Figure 15 Bode plot of the frequency characteristic of the gas turbine unit including the frequency controller, turbine and generator. The frequency signal was varied in logarithmically equidistant frequencies from 0.08Hz to 0.65Hz. As can be seen from the figure the amplitude is damped and
Active power (MW)
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Power: Phase (degrees)
Power: amplitude (MW)
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3.2.5 Power vs gate opening feedback In order to achieve the speed-droop characteristic, a feedback loop is needed in the speed governor. The feedback signal can be either the gate opening signal or the produced active power. If the non-linearity between the gate opening and active power is neglected the behavior will be the same whereas it will vary considerably if the non-linearity is taken into account. In an island grid with one or a few production units it can be important which type of feedback signal that is used as the stability differs essentially between the use of power feedback and gate opening feedback. In some cases there can be an important connection between voltage regulation and type of feedback. Machines with automatic voltage regulation try to keep the voltage at a constant level in the network independently of the frequency. In a typical island grid where most of the loads consist of lightning and heating there will be no changes in the load despite changes of the frequency if there is automatic voltage regulation. As a result there are either no reaction from the power feedback signals and speed droop circuits. A resistive load can, however, be very dependent of the frequency if the machine is running without voltage regulation but with constant field current. If the turbine governor use gate opening feedback in the speed droop circuit there will be no influence from principals of voltage regulation. Figure 16 shows a case with one gas turbine in island operation at a load step of 12 MW. Power feedback is compared with gate opening feedback. As can be seen the use of gate opening feedback gives much better stability (damping) compared to the use of power feedback.
50
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Figure 16 12MW load step on gas turbine in island operation, speed droop 6 %. The curves show turbine power and frequency for power feedback (green lines) and gate opening feedback (red lines). When studying the behavior after the load increase it can be concluded why the gate opening feedback is
Accepted for presentation at the Power Systems Computation Conference, June 24-28 2002, (PSCC02), Sevilla, Spain better than the power feedback in island operation. As can be seen in Figure 17 the frequency and the power/gate error are summarized before the signal enters the PI-regulator in order to create the powerfrequency droop. f0+
1 f0
f
Kf
1+T1*s 1+T2*s
droop P0
1 Pn
P
1 Pn
+ 1 1+TLP *s
ep
++
Frequency/ power control bgpf
+ ++
bgif s
LP-filter
Figure 17 Gas turbine speed governor. At the load step instant the immediate step of “droop error” using power feedback causes the regulator to act in the wrong direction using power feedback. This is not the case with gate opening feedback since there is a continuous increase of the gate opening. This explains the smaller “first swing”. There is also a big difference in damping. Using power feedback there is only a steady state addition of the control error. (Assuming the load is frequency independent). The gate opening varies approximately with the turbine power and at the curves in Figure 16 it appears that the feedback works as an extra D-action of the frequency, which has a considerable and positive effect on the damping. 4 CONCLUSIONS The development of SolvSim Power Station has made it possible to perform safe field studies of speed
droop, speed governor time constant and island operation capability when the power station is synchronized to the main grid. It has also given a suitable tool, which can be used for model development and validation. The field studies performed have shown that it is very important to perform real tests in order to study the island operation capability as faults in the equipment and bad tuning of regulators have been discovered. For hydro units working with the wicket gate opening as feedback signal in the speed governor the speed droop will vary with the wicket gate opening. For Kaplan turbines equipped with runner blade angle regulation the speed droop (%) will be larger than specified for small wicket gate openings whereas it will be less than specified for large openings. A Francis turbine will have the opposite behavior, i.e. for small openings the speed droop will be less than specified whereas it will be larger than specified for larger openings. For the tested gas turbine it was shown that the use of turbine power as feedback signal to the speed governor resulted in less power and frequency oscillation compared to when using active power as feedback signal.
REFERENCES [1] J. Andersson, “The Analysis of Thermal Power Stations and their Interaction with the Power System using Simulator test Methods”, Technical Report, Chalmers University of Technology, Sweden, September 1996, ISSN 0346-718-X, July 1981 [2] P. Kundur, “Power System Stability and Control”, McGraw Hill, 1994, ISBN 0-07-035958-X.
