December 6-7, 2000 SERC Presented by Les Hajagos Kestrel

1
Generator Controls Testing Modelling

• December 6-7, 2000
• SERC
• Presented by
• Les Hajagos
• Kestrel Power Engineering
• [phone], les_at_kestrelpower.com

2
Testing to Meet NERC Requirements

• Reactive Capability
• Generator Modelling
• Excitation Systems/Limiters
• Power System Stabilizers
• Governors Prime Movers

3
Turbine-Generator Controls
4
Generator Reactive Capability
5
Generator Reactive Capability Tests

• Commonly misunderstood test
• Steady-state versus dynamic
• Q f (V, P)

6
Testing Reactive Capability - Single Unit

• Normal operation, high Q results from low system
  and generator voltage
• Test operation high Q results from high generator
  voltage with normal system voltage
• Often ends up being limited by voltage not truly
  reactive capability
• Function of stiffness of system and transformer
  impedance

VS
Q
VG
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Testing Reactive Capability - Multiple Units

• Maintaining Q1Q2 constant allows for relatively
  constant generator voltage
• Perform tests simultaneously
• Normally one limit is reached first, meaning that
  it still may not be possible to measure both
  reactive limits
• Use calculations to extrapolate results

VS
QT
VG
Q1
Q2
1
2
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Case Study - Combined Cycle Peaker
VS
Q1
Q2
Q3
2
3
1
Combined Cycle
Peaker
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Reactive Capability Tests

• Use other units in plant wherever possible to
  control net reactive power
• System may be able to switch capacitors or time
  tests for high and low voltages
• Test or calibrate exciter UEL and OEL first
• Check all relevant relay settings (LOE, O/V,
  V/Hz, U/V on unit and auxiliary buses)
• Monitor aux bus voltages and currents, switch
  loads where possible
• Use calculations to supplement measurements

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Excitation Limiters

• Field current limiters (see ANSI C50.13-1977)
• Time (seconds) 10 30 60 120
• Field Voltage () 208 146 125 112
• Coordinate with excitation capability
• V/Hz (over-flux) or Terminal voltage
• Under-Excitation Limiters (UEL) coordinated with
  LOE and Core-End

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Testing Over-Excitation Limiters

• Location of limit determines test procedure
• Steady-state (operator control) and dynamics
  (signal injection)
• For high limits recommend two steps
• off-line signal injection (relay test) for
  startpoint
• on-line setpoint adjustment for dynamics
• Field current limiters are normally stable and
  dynamics can be modelled using simple
  approximations

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Operation of Field Current Limiter
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Testing Under-Excitation Limiters

• Location of limit determines test procedure
• Steady-state (operator control) and dynamics
  (signal injection)
• For low limits recommend two steps
• off-line signal injection (relay test) for
  startpoint
• on-line setpoint adjustment for dynamics
• UELs are often poorly-behaved. Caution should
  always be exercised when engaging a UEL limit as
  the response may be unstable. This is especially
  true for summing limiters where PSS units are
  installed.

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Unit Operation Against UEL Limit
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UEL Dynamic Response Test
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PF/VAR Regulators

• Response needs to be measured
• Guidelines should be in place for
• speed of response
• deadband
• voltage supervision
• Identify where it is implemented
• Perform AVR step response with/without control
  in-service

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AVR Step Response Performed with PF/VAR
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Types of Stability on AC Power System

• Angular Stability associated with changes in the
  angular positions of generators relative to each
  other. Frequency and voltage in normal range.
• Voltage Stability associated with changes in the
  voltage profile of the system. Frequency and
  angular positions in normal range.
• Frequency Stability associated with islanded
  operation of units and changes in the system
  frequency. Voltage in normal range.

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Definitions Applied to Angular Stability

• Steady-State Stability ability of the power
  system to maintain synchronism at all points for
  incremental slow-moving changes in power outputs
  of units or power transfer over transmission
  facilities
• Transient Stability ability of the power system
  to maintain synchronism during and immediately
  following a major disturbance such as a
  transmission line fault or the loss of a large
  generating unit
• Small Signal (Oscillatory Stability) ability of
  the power system to maintain synchronism during
  small changes in operating conditions which
  produce small changes in generator angle, speed
  and power

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Relationship Between Rotor Motion and
Spring-Block Analogy
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Functional Description of Stabilizer

• Measure speed (or related quantity)
• Remove steady-state component
• Compensate for phase lags and gains of exciter
• Inject into AVR input
• Create torque change through excitation change

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Power System Stabilizers

• Speed-based
• Frequency-based
• Power-based
• Accelerating-power based
• Over 100 in-service in Ontario, most based on the
  accelerating-power design

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Differential Angle Stabilizer

• phase measurement between generator internal
  voltage and a remote system voltage
• sensitive to system impedance variations
• measurement time lags
• high phase advance requirement

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Speed-Based Stabilizers

• direct shaft speed measurement using passive
  magnetic probes and tach circuit
• reasonable phase compensation requirements
• shaft runout (hydro)
• torsionals (thermal)

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Stabilizer Gain Phase Lead
Limits
Torsional Filter
High-Pass Filter
Vstmax
1
s T5
1
1 s T1
1 s T3
Ks1
Output
2
Speed
1 s T5
1 s T6
1 s T2
1 A1 s A2 s
1 s T4
Vstmin
Single-Input Power System Stabilizer (IEEE PSS1A)
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Frequency-Based Stabilizers

• frequency derived from generator terminals or
  compensated internal frequency
• sensitivity to rotor oscillations increases for
  weak ac systems
• more sensitive to inter-area modes / not
  sensitive to inter-machine modes
• system transients cause spurious output signals
• sensitive to other power system noise which is
  not present in actual speed
• still requires torsional filtering

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Power-Based Stabilizers

• electrical power (inverted) leads speed by 90
  degrees
• phase lead requirements met without increasing
  high-frequency gain
• most not equipped to adjust phase lead and
  therefore not very flexible
• sensitive to mechanical power variations

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Accelerating-Power Based Stabilizers

• combines speed with measured electrical power to
  produce a signal proportional to the
  integral-of-accelerating power
• combines advantages of speed and power-based
  systems while eliminating or mitigating the
  side-effects
• no torsional filtering required
• allows aggressive phase lead selections and high
  gain to match system requirements
• still need to assess effect of mechanical power
  variations but effect is greatly reduced

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Power System Stabilizer TestingTuning

• Models rarely reflect reality (AVR/Generator)
• Models lack bandwidth to capture exciter mode
• PSS Step response/frequency response
• Measurement of the system phase compensation
  requirements
• Step response tests to measure damping
  improvement at local mode frequencies
• Load-ramping tests to ensure that the PSS does
  not produce undesirable modulation of the units
  terminal voltage under normal or emergency
  operating conditions

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Preliminary Tests Verification

• Verify values at all manufacturer supplied
  measurement points
• Inject signals using test source to verify the
  transfer functions of various signal paths
• Install additional transducers as required
• Install any components required to inject test
  signal into the AVR summing junction

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Measured Quantities

• RMS Terminal Voltage
• Field Voltage
• Active Power
• Shaft Speed or Frequency
• PSS Output
• Internal PSS Signals

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Example Test Setup for Measurement of PSS
Performance
Fig.7.10-07/97-Berube
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Measurement of Closed-Loop Voltage Regulator
Transfer Function
Fig.7.9-07/97-Berube
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PUBLICATIONS/PRESENTATIONS G.R. Bérubé, L.M.
Hajagos, Utility Experience with Gas Turbine
Testing and Modeling, prepared for presentation
at the IEEE PES Panel on Power Plant Modeling,
January 2001. G.R. Bérubé, L.M. Hajagos, R.E.
Beaulieu, Practical Utility Experience with
Application of Power System Stabilizers,
presented at the IEEE PES Panel on Power System
Stabilizers, July, 1999 G.R. Bérubé, L.M.
Hajagos, Modelling Based on Field Tests of
Turbine/Governor Systems, presented at the IEEE
Symposium on Frequency Control Requirements,
Trends and Challenges in the New Utility
Environment, February, 1999 L.M. Hajagos, B.
Danai, Laboratory Measurements and Models of
Modern Loads and Their Effect on Voltage
Stability Studies, IEEE Transactions on Power
Systems, Vol 13, No 2, May 1998. G.R. Bérubé,
L.M. Hajagos, Testing and Modelling of Generator
Controls on the Ontario Hydro System, presented
at the WSCC Workshop on Synchronous Unit Dynamic
Testing and Computer Model Validation (January
30, 1997) and the NERC System Dynamics Data
Working Group Symposium (April 30, 1997) G.R.
Bérubé, L.M. Hajagos, Utility Experience with
Digital Excitation Systems, IEEE PES Winter
Meeting 1997, New York, NY, PE 581-PWRS-003-1997.
G.R. Bérubé, L.M. Hajagos, R.E. Beaulieu, A
Utility Perspective on Underexcitation Limiters,
IEEE Transactions on Energy Conversion, Vol 10,
No 3, September 1995. G.J. Rogers, R.E.
Beaulieu, L.M. Hajagos Performance of Station
Service Induction Motors Following Full Load
Rejection of a Nuclear Generating Unit, IEEE
Transactions on Power Systems, Vol 10, No 3,
August 1995. K.S. Shah, G.R. Bérubé, R.E.
Beaulieu, Testing and Modelling of the Union
Electric Generator Excitation Systems, presented
at the 1995 Missouri Valley Electrical
Association meeting in Kansas City, MO, April,
1995. G.R.Bérubé, L.M. Hajagos, R.E. Beaulieu, A
Utility Perspective on Underexcitation Limiters,
IEEE PES Excitation System Subcommittee Panel
Presentation, June 1994. J.R.R. Service, L.M.
Hajagos, Practical Aspects of On-Load Generator
Testing, EPRI TR-102351, Project 2328-02, Final
Report, May 1993. G.R. Bérubé, T.A. Gough, Power
System Disturbance Recorder, Canadian Electrical
Association, Transmission, Station Planning and
Operations Subsection, March 1989. G. Roger
Bérubé Les M. Hajagos Senior Engineer Senior
Engineer Kestrel Power Engineering Kestrel Power
Engineering Ph [phone] Ph (905)
272-2191 E-mail roger_at_kestrelpower.com E-mail
les_at_kestrelpower.com