frequency control and inertia in the future nordic power system · frequency control and inertia in...
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Frequency control and Inertia in
the future Nordic power system
Kjetil Uhlen
NTNU
1
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Outline
• Background – motivation
• Some frequency control issues
• Modelling and analysis
– Slow frequency variations (FCR and FRR)
– Turbine and Governor responses (FCR)
– Inertia
• Synthetic inertia -Laboratory demo.
• Possibilities with Advanced control?
• Concluding remarks
2
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Outline
• Background – motivation
• Some frequency control issues
• Modelling and analysis
– Slow frequency variations (FCR and FRR)
– Turbine and Governor responses (FCR)
– Inertia
• Synthetic inertia -Laboratory demo.
• Possibilities with Advanced control?
• Concluding remarks
3
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Frequency is a global measure on
(scheduled) power balance in an ac grid
50
Loads Gene-
ration
[Hz]
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Trend:
Frequency deviations in the Nordic synchronous zone
5
Minutes outside the frequency band 49,9 – 50,1 Hz
Source: Statnett
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Frequency «fluctuations» with period
60-90 sec.
6
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Frequency «fluctuations» with period
60-90 sec.
7
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The future challenge:
- More variability, more extremes..
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More Wind power and variable RES:
-Possible shut-down of Nuclear plants
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More interconnectors:
Norwegian hydro as the European energy
battery – potential and challenges
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Main challenges
• Increased number of interconnections
• Higher demand for balancing services
• Higher ramp rates
• Uncertainty about available reserves (FCR and
FRR)
• Lack of inertia in periods with high import and high
wind
• Uncertainty about the actual response and
capability of hydro plants
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Outline
• Background – motivation
• Some frequency control issues
• Modelling and analysis
– Slow frequency variations (FCR and FRR)
– Turbine and Governor responses (FCR)
– Inertia
• Synthetic inertia -Laboratory demo.
• Possibilities with Advanced control?
• Concluding remarks
12
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Tasks and time-scales in operation
(in keeping the balance)
Increasingly market
based -Long term markets
and contracts
-Day-ahead markets
- Primary
frequency
control
- Inertia
- Intra-day markets
- Real-time balancing
markets (tertiary contr
- AGC (secondary
control)
Degree of
automation
sec. min. hour day year
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ENTSO-E definitions
Network Code on Load-Frequency Control and Reserves (28 June 2013):
Frequency Containment Reserves (FCR) shall aim at containing the System Frequency deviation after an
incident within a pre-defined range.
Frequency Restoration Reserves (FRR) means the Active Power Reserves activated to restore System
Frequency to the Nominal Frequency and for Synchronous Area consisting of more than one LFC Area power balance to the scheduled
value.
Replacement Reserves (RR) means the reserves used to restore/support the required level of FRR
to be prepared for additional system imbalances. This category includes operating reserves with activation time from “Time to Restore Frequency” up to hours;
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System frequency response
System frequency response = [MW/Hz]DP
Df
50.0
RDf
50.1
0.0
49.9
Frequency [Hz]
Reserves activated [MW]
Time
0 1 min. 15 min. 1 hour
Df
DP
Primary (FCR) Secondary (FRR) Tertiary (RR)
“R” =
Frequency «nadir»
Inertia – Rate of change of frequency
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Frequency transient in Nordic system(caused by trip of large power plant)
Δf = 0.5 Hz
Δt = 30 sec
Δt = 8 sec
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Expanded view..
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Outline
• Background – motivation
• Some frequency control issues
• Modelling and analysis
– Slow frequency variations (FCR and FRR)
– Turbine and Governor responses (FCR)
– Inertia
• Synthetic inertia -Laboratory demo.
• Possibilities with Advanced control?
• Concluding remarks
18
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Simplified model of the Nordic power system ( 23 gen.)
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HYGOV Initial Case
(blue)
Case N (red) Best Fit Case
(to
11.06.2011)
(green)
0,06 0,08 0,08
0,06 0,1 0,1
0,4 0,6 1,35
5 3 2,6
Model tuning…
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Simulation result:
0 100 200 300 400 500 600 700
49.95
50
50.05
50.1
50.15
Fre
quency (
Hz)
Time (sec)
Applying random load variations
Looking at impact of governor tuning
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Hydraulic system and turbine models
“Classical model”
Simple linearized model
1
2
1
1
wm
w
T sT g
T s
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Hydraulic system and turbine models
“IEEE model with surge tank”
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Comparison of the turbine
models
10-4
10-3
10-2
10-1
100
-70
-60
-50
-40
-30
-20
-10
0
10Magnitude response
He
ad
/Ga
te [
dB
]
10-4
10-3
10-2
10-1
100
-200
-180
-160
-140
-120
-100
-80Phase response
Frequency [Hz]
He
ad
/Ga
te [
De
gre
es]
Classical model
IEEE model
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Comparison of the turbine models
0 50 100 150 200 250 300 350 40049.8
49.85
49.9
49.95
50
50.05
Time [sec]
Fre
quen
cy [H
z]
Dynamic response to loss of production
Classical
IEEE
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Comparison of the turbine models
(eigenvalues)
Number Eigenvalue Damping ratio
[1/s], [Hz])
Classical; 1 -0.446730 j0.029693 0.9978
Classical; 2 -0.025646 j0.006039 0.9734
IEEE; 1 -0.330060 j0.030415 0.9958
IEEE; 2 -0.002089 j0.010325 0.1983
IEEE; 3 -0.002898 j0.010318 0.2704
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“Classical” hydro governor model
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PID-type governor
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Comparison of governors
10-3
10-2
10-1
100
101
102
-200
-150
-100
-50
0
50
100Magnitude response
Ga
te/S
pe
ed
[d
B]
10-3
10-2
10-1
100
101
102
-300
-250
-200
-150
-100
-50
0
50Phase response
Frequency [Hz]
Ga
te/S
pe
ed
[D
eg
ree
s]
Kundur
PID
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Norwegian University of Science and Technology
Impact of low inertia and syntetic
inertia in the Nordic power system
Silje Mork Hamre
Kjetil Uhlen
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Norwegian University of Science and Technology 31
Event and scenarios:
Event simulated:
Sudden outage of nuclear plant in Sweden. Loss of approx. 1100
MW
3 scenarios:
1. Reference scenario 05.03.2015
Measured verses simulated response in frequency
2. Low load summer scenario with unchanged governor settings
Compared to reference scenario
3. Low load, high wind and high import future scenario:
With and without synthetic inertia from wind plants
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Norwegian University of Science and Technology
1. Reference scenario (model tuning)
0 20 40 60 80 100 12049.6
49.65
49.7
49.75
49.8
49.85
49.9
49.95
50
50.05
50.1
Time [sec]
Fre
quency [
Hz]
Scenario 1 - Reference case form 05.03.2015
Measured response
Nordic44 resonse
R = 1100/0.13 =8500 MW/Hz
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Norwegian University of Science and Technology
2. Low load scenario versus reference
0 20 40 60 80 100 120 140
49
49.2
49.4
49.6
49.8
50
Time [s]
Fre
quency [
Hz]
Scenario 1 vs. Scenario 2
Scenario 1 - Nordic44 response
Scenario 2 - Low load summer day - 23.06.2013
Unchanged droop settings
R = 1100/0.43=2600 MW/Hz
Need to avoid UFLS..
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Norwegian University of Science and Technology
3. High import and high wind
with and without synthetic inertia
0 20 40 60 80 100 120 140 16048.8
49
49.2
49.4
49.6
49.8
50
50.2
Time [sec]
Fre
quency [
Hz]
Scenario 3 - 2020 - High import - 20 % wind
Scenario 3 - 2020 - High import - 20% wind withsynthetic inertia, K
w i=10
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Norwegian University of Science and Technology
3. Response from wind plants
0 20 40 60 80 100 120 140 1602400
2450
2500
2550
2600
2650
2700
Time [sec]
Pele
c W
T in S
E3 [
MW
]
Response from wind turbine SE3
Scenario 3 - 2020 - High import - 20 % wind
Scenario 3 - 2020 - High import - 20% wind withsynthetic inertia, K
w i=10
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Outline
• Background – motivation
• Some frequency control issues
• Modelling and analysis
– Slow frequency variations (FCR and FRR)
– Turbine and Governor responses (FCR)
– Inertia
• Synthetic inertia -Laboratory demo.
• Possibilities with Advanced control?
• Concluding remarks
36
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Providing inertial response from
VSC-HVDC connected wind farms
Laboratory scale implementation and demonstration
Hanne Støylen - Atle Rygg Årdal – Kjetil Uhlen
Norwegian University of Science and Technology
Department of Electrical Engineering
Department of Engineering Cybernetics
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Frequency transient in Nordic countries(caused by trip of large power plant)
Δf = 0.5 Hz
Δt = 30 sec
Δt = 8 sec
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1. Drop in onshore grid frequency fgrid
2. VSCgrid reduces Vdc in proportion to dfgrid/dt3. VSCowf reduces fowf in proportion to ΔVdc
4. Turbines provide inertial response to offshore AC-grid
Main challenges: Dynamic response, choice of parameter values, signal processing delays
=~ ~=
VSC-HVDC connected wind farmsCommunicationless control system
fgridVdcfowf
fturb
fgrid
t
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=~ ~=
Laboratory implementation overview
fgridVdcfowf
fturb
Wind farm equivalent
IGIM
VSCWF VSCgrid
Weak grid equivalent
SG IM
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Laboratory implementation overview
• Rating of units: ≈ 50 kVA
• Converter control: Custom built FPGA + LabVIEW
Synchronous generator
Wind turbine emulator
DC cable emulator
2 x VSC
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Benchmark scenario
• Sudden connection of large load ≈ 0.25 p.u.
Wind farm equivalent
IGIM
VSCWF VSCgrid
Weak grid equivalent
SG IM
• Synchronous generator seeks to restore power balance
– BUT: Governor response is slow and inertia is low
• Impact of wind farm frequency support is investigated ->
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Results(1): Choice of parameter values
• Significant improvement in frequency low-point (nadir), also shifted in time
• System becomes oscillatory for larger inertia support gains
• NB: Time-delay of ≈ 400 ms. before support reaches weak grid
– Frequency measurement processing
– VSCgrid control response time
– VSCWF control response time
– DC grid dynamics
Weak grid frequency Δfgrid [Hz]
Increasing inertia support
Wind farm equivalent
IGIM
VSCWF VSCgrid
Weak grid equivalent
SG IM
Increasing inertia support
Weak grid frequency Δfgrid [Hz]
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Conclusions
• Successful laboratory-scale implementation of inertial
support from VSC-connected offshore wind farm
• Challenging control system design due to:
– Two stages of frequency conversion
– Multiple dynamic responses and possible interactions
– Requirement of fast and accurate measurements
• Present work: Extending laboratory model to include
turbine frequency converter
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Outline
• Background – motivation
• Some frequency control issues
• Modelling and analysis
– Slow frequency variations (FCR and FRR)
– Turbine and Governor responses (FCR)
– Inertia
• Synthetic inertia -Laboratory demo.
• Possibilities with Advanced control?
• Concluding remarks
45
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MPC for Frequency Control
• Model predictive control (MPC) for FRR control
• Applies model of system to predict future behavior.
• Optimizes governor setpoints at each time step with respect to
an objective function.
• Use larger model for «real world» and simplified model in MPC.
• MPC decides total change in governors setpoints as well as
participation factors for each generator.
• MPC takes into account limitations on
• Generation capacity.
• Generation rate of change.
• Power transfer capacity on transmission lines.
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Anne Mai Ersdal, Lars Imsland and Kjetil Uhlen
«Model Predictive Load-Frequency, Control»
IEEE TRANSACTIONS ON POWER SYSTEMS (available IEEE Explore)
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Outline
• Background – motivation
• Some frequency control issues
• Modelling and analysis
– Slow frequency variations (FCR and FRR)
– Turbine and Governor responses (FCR)
– Inertia
• Synthetic inertia -Laboratory demo.
• Possibilities with Advanced control?
• Concluding remarks
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Concluding remarks
• Renewed interest in frequency control
• Uncertainties about the performance of hydro
turbine/governors
• New requirements for frequency control
performance are coming..
– Inertia, FCR, FRR,..
– New market design..
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Thank you!
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ENTSO-E definitions
Network Code on Load-Frequency Control and Reserves (28 June 2013):
Frequency Containment Process (FCP) means a process that aims at stabilizing the System Frequency by
compensating imbalances by means of appropriate reserves;
1. The control target of FCP is to stabilize the System Frequency by activation of FCR.
2. The overall characteristic for FCR activation in a Synchronous Area shall reflect a monotonically decrease of the FCR activation as a function of the Frequency Deviation. (frequency droop)
FCP Primary control