IMPACT OF SYNTHETIC INERTIA FROM WIND POWER
ON THE PROTECTION/CONTROL SCHEMES OF FUTURE
POWER SYSTEMS: SIMULATION STUDY
F. Gonzalez-Longatt†
†
Faculty of Computering and Engineering, Coventry University
AS410 Armstrong-Siddeley Building, Priory Street, CV1 5FB- Coventry, +44 779 5634298, fglongatt@ieee.org
Keywords: Frequency controller, frequency stability, power
system, protection scheme, wind turbine generator.
Abstract
Future power systems face several challenges; one of them is
the use of high power converters that decouple new energy
sources from the AC power grid. This decreases the total
system inertia affecting its ability to overcome system
frequency's disturbances. The wind power industry has
created a controller to enable inertial response on wind
turbines generators: Artificial, Emulated, Simulated, or
Synthetic Inertial. This paper deals with issues related to the
synthetic inertia of wind turbines based on full-converters and
their effect on the frequency protection/control schemes
during the recovery period after system frequency
disturbances happen. The main contribution of this paper is to
demonstrate (based on simulations) the recovery period of
under-frequency transients on future power systems which
integrate wind turbines with synthetic inertia capability not
completely avoid worse scenarios in terms of underfrequency load shedding. The extra power delivered from a
wind turbine during frequency disturbances can substantially
reduce the rate of change of frequency providing time for the
active governors to respond. However, synthetic inertia might
not completely avoid under-frequency load shedding.
1 Introduction
Future power systems face several challenges: (i) the high
penetration level of renewable energy from highly variable
generators connected over power converters, (ii) several
technologies for energy storage with very different time
constants, some of them using power converters as an
interface to the grid, (iii) A pan-European transmission
network facilitating the integration of large-scale renewable
energy sources and the balancing and transportation of
electricity based on underwater multi-terminal high voltage
direct current (MTDC) transmission. All of them have an
element in common, high power converters that decouple the
new energy sources from the pre-existent AC power systems.
During
a
system
frequency
disturbance
the
generation/demand power balance is lost, the system
frequency will change at a rate initially determined by the
total system inertia. However, future power systems will
increase the installed power capacity (MVA) but the effective
system inertial response will stay the same nowadays, this is
because the new generation units based on power converters
creates a decoupling effect of the real inertia and the ac grid.
The result is deeper frequency excursions of system
disturbances. A considerable reduction in the ability to
overcome system frequency's disturbances is expected, the
inertia response may be decreased. The inertial response of
the system might be negatively affected with devastating
consequences for system security and reliability.
There are several good papers [1], [2], [3], and technical
reports [4], [5], [6] dealing with theory [7], [8], [9], modelling
[10] and simulation [2], [11] of inertial response of wind
turbine generators (WTG) and some of them provide general
ideas about possible impacts on power systems and there
effects on transient under-frequency response [12], [13], [14].
Even some controls strategies have been proposed to mitigate
the impact of reduced inertia [15]. However, there is lack of
knowledge about the impact of inertial response of wind
turbines on deterministic frequency protection/control
schemes in future power systems.
This aim of this paper is presents the real impact of synthetic
inertia on wind turbines based on full-converters and there
effect on the frequency protection/control schemes during the
recovery period after system frequency disturbances happen.
The paper is organized as follows. Section 2 describes the
frequency response on power system after a frequency
disturbance. Section 3 presents the concept of synthetic
inertia and show two approaches used on WT controller to
create inertial responses. Section 4 address aspects related to
protection/control schemes on power system and some
potential challenges for futures networks. Section 5 the results
of simulations that define the impact of synthetic inertia on
the protection/control schemes over a test system. Finally, the
advantages of this novel application are discussed in Section
5.
2 Frequency Response
The frequency of a power system depends on real power
balance: generation-demand. In the normal operation of a
power system, the frequency is regulated within strict limits
by adjusting the electrical supply to meet the demand.
Responsibility of frequency control is managed in United
Kingdom by National Grid PLC, thought the procurement and
despatch of frequency response services, under normal
operation conditions the frequency is maintained at
50Hzr0.2Hz [16].
If the balance between generation-demand is not reached, the
system frequency will change at a rate which is dependent
upon the initial power mismatch and the total system inertia.
Large frequency disturbances, particularly trips of large
generation plants, cause generation-demand unbalance that
must be corrected by frequency control loops. These
controllers are provided in order improve the system
frequency response (SFR). The frequency controllers cover
multiple time-frames: (i) inertial response also know as fast
primary response, (ii) governor response also known as slow
primary response, and (iii) automatic generation control
(AGC). These controllers define the dynamic changes
associated to System Frequency Response (SFR).
During a system frequency disturbance, the inertial response
dominates initial frequency changes then the combination of
system inertia and governors response dictate the extreme
value of frequency (maximum or minimum). Later, the
governor response and load response dominate the frequency
mismatch between the system frequency and statutory value
until AGC takes over. Tertiary frequency control is additional
and slower compared to previous two controllers. The task of
tertiary control depends on the organizational structure of a
given power system and the role that power plant plays in the
structure [17]. Primary response is provided locally at device
level, Secondary response is mainly area-wide inside an
administrative area, and tertiary response is a global concept
for interconnected systems.
Frequency response provided by WTG's is different to
traditional generation systems. Modern variable speed WTG
does not naturally contribute to system inertial and does not
contribute to the governor response without incurring
significant operational cost penalties.
3 Synthetic Inertia
The total system inertia of a traditional power system
comprises of the combined inertia of most of the spinning
generation and load connected to the power system. The
contribution of the system inertia to a single load or generator
depend on changes in the system frequency and causes
change in its rotational speed hence, a change its kinetic
energy.
The power associated with this change in kinetic energy is fed
or taken from the power system and is known as the inertial
response. During a system frequency event the total system
inertia response of all electrical machines connected to the
system is the main factor that determines the initial rate of
frequency change (ROCOF).
Modern WTGs use power electronics converters to enable
variable speed operation in order to capture wind energy over
a wide range of speeds. However, these converters isolate the
rotational speed from the system frequency so WTG based on
back-to-back AC/DC/AC converters offer no natural
response to system frequency [3], [10].
Author has included the adjective "natural" on the previous
sentence because some manufacturers have started to
integrate controllers on modern WTG’s in order to provide
inertial response (and governor response on some cases) for
large, short-duration frequency deviations.
The Wind turbine industry has created several names for this
control system that enable inertial responses on a WTG:
Artificial, Emulated, Simulated, or Synthetic Inertial.
Examples of synthetic inertia controlled commercially
available for WTG are: General Electric WindINERTIA™
[18], [19], ENERCON“ Inertia Emulation [20].
The objective of the synthetic inertia control is extracting the
stored inertial energy from the moving part on WTGs. The
idea is to produce incremental energy similar to that provided
by a synchronous generator with real inertia. This is a local
and automatic controller at wind turbine level which has a
response in the same time-frame as primary controllers
(<30s). Synthetic inertia controllers are based on two different
approaches: (a) Releasing "hidden" inertia and (b) Reserve
capacity in pitch.
2.1 Releasing the "Hidden" Inertia
Releasing the "hidden" inertia concept allows a controller to
the take the kinetic energy from a wind turbine (WT) rotating
mass. Significant energy is stored on a WTG, electrical
generator operating at high speed has a large amount kinetic
energy stored in rotor of generator, but majority of that
kinetic energy is in rotor bales. A WT using permanent
magnet synchronous generator (PMSG) on a direct-drive
concept has less kinetic energy stored due to the lower
rotational speed. Table 1 shows typical values of 3MW
modern variable speed WTG.
Drive train Concept
Double fed 3-stage
gear
Low Speed Full
converter (LSFC)
Direct drive
Medium Speed full
Converter (MSFC)
2-stage gear
High Speed Full
Converter (HSFC)
3-stage gear
Rated Speed
[rpm]
Generator rotor
inertia [Kg/m2]
1200
250
14
40,500
Permanent
magnet 14-pole
400
510
Permanent
Magnet 6-pole
1600
115
Generator Type
Wound rotor
asynchronous 6pole
Permanent
magnet, multi
pole
Table 1: Typical data for a 3MW WTG.
Releasing the "hidden" inertia control loop increases electric
power output during the initial stages of a significant
downward frequency event. The active power (inertial power,
'P) of the control is achieved by:
df sys
(1)
'P 2 H u f sys u
dt
where H express the synthetic inertia (sec) and fsys system
frequency (p.u). Implementation of releasing hidden inertia
controllers is depicted on Figure 1. The WT can quickly store
and release a large amount of kinetic energy in the rotating
masses because of the power electronic converter, due to a
large amount of inertia and wide rotational speed. However,
discharge of energy to the grid is only for a short period
available (<30s) and recovery of WT power is supplied by the
grid (unless the wind speed increases favorably!!!).
DIgSILENT
Slowing the wind turbine reduces aerodynamic lift and
security limitations must be considered to avoid a stall.
Inertial power must respect WTG components rating like
mechanical loading as well as converter and generator
electrical rating [9]. For large under-frequency events, the
inertial control feature temporarily increases the power output
of the wind turbine by about 5% to 10% of its rated power,
for several seconds. ENERCON“ emulated inertia increases
the power output about 4% to 10% of rated power for 10s [8].
Controller Releasing Hidden Inertia:
max df/dt
fs
Grid
Frequency
[p.u]
Derivator
K
min df/dt
max
df/dt
Filter
Kfilter,Tfilter2,Tfilter2
min
filtere..
Filter
D_P
Delta_P
K
K2H
2H
Additional
power command
df/dt
Under-frequency load shedding (UFLS) is the most widely
used protection against frequency collapse. Typically, load is
shed based on a local frequency measurement in several steps
of 5-20 % (of the total feeder load) each. Automatic load
shedding is implemented using underfrequency relays.
Typical threshold values are 48-48.5 Hz for a 50 Hz system.
The main draw back of these schemes is their delayed
response since they must wait for the frequency to decline
before taking action. A great proportion of inertia is expected
to be decoupled to the system frequency in future power
systems. As consequence a larger frequency drop is expected
in future networks, as consequence deterministic frequency
protection/control schemes must be re-thought. Synthetic
Inertial response from wind turbines can increase system
security and aid large scale systems to overcome system
frequency disturbances, however, control interactions can
create disastrous situations.
Figure 1: Releasing Hidden Inertia Controller.
5 Simulation and Results
2.2 Reserve Capacity in Pitch
Traditional variable speed WTs are designed to always
operate at the maximum power point tracking (MPPT) so they
have no power reserve to support frequency control in there
steady state. Reserve capacity in pitch concept coerces a wind
standby power by maintaining reserve capacity in pitch [9],
[21]. A de-loading controller enable the WT to operate over
de-loading curves instead of MPPT and saves the available
power as reserve by using a pitch controller (pitching) or
increasing the rotational speed from the MPPT value (overspeeding).
Frequency support using this controller is already discussed in
details in several publications [2], [9], [18], [22], even
EirGrid, the transmission system operator of the Republic of
Ireland, already estipulate a scheme with this controller [23].
One negative consequence of this controller is WTs have to
be operated at a considerably lower power output that
otherwise possible for a given wind speed, as a consequence,
less power generation is achieved and the wind is not fully
utilized. A monetary compensation scheme for the wind farm
owners can be created to resolve this situation. An additional
grid frequency control loop in the pitch angle controller is
required and it must be carefully designed in order to meet
mechanical loads on the pitch drive. This approach involves
some well-know consequences and requirements, as
consequence, it is not considered in this paper.
4 Protection/Control Schemes
When a severe frequency disturbance occurs, e.g. loss of a
station (all generating units), loss of a major load centre, or
loss of AC or DC interconnection, emergency control
measures may be required to maintain frequency stability.
These control measures may include: tripping of generators,
fast generation reduction, HVDC power transfer control, load
shedding, controlled opening of interconnection to
neighbouring systems to prevent spreading of frequency
problems and controlled islanding of local system into
separate areas with matching generation and load.
This section presents simulations and results over a Test
System representative of a future network. All models where
developed by the author using information publically
available and personal assumptions where they are necessary.
DigSILENT“ PowerFactoryTM [24] is used for time-domain
simulations and DIgSILENT Simulation Language (DSL) is
used for dynamic modelling. All simulations are performed
using a personal computer based on Intel“, CoreTM i7 CPU
2.0GHz, 8 GB RAM with Windows 7 Home Edition 64-bit
operating system.
5.1 Test System
The test network used for simulation in this study it is given
in Figure 2. This system consists of 8-generator, 8-bus, 7load, and 22-transmission lines. It is a hypothetical
simplification of a large 400 kV transmission system, it has
been divided in seven areas: Top-Right, Top-left, Upper-Tail,
Tail-Right, Lowest-Tail, Middle and Core+Tail. The
generator G4(a) represents the aggregation of a large number
of generators and it is selected as a reference. The system has
a total generation of 100.736 GW and a total load of
96.75GW.
Figure 2 shows the load flows for case base, there is a power
flow of about 15 GW from the Top to Tail, particularly from
Upper-Tail and Tail-Right and Core-Tail. Tail is an area rich
on generation and Core-Tail is a load-rich area. Dynamic
models for governor and automatic voltage controller (AVR)
are provided to this test model.
Figure 3 and 4, show the general steam turbine used as
governor for all synchronous power plants and a version on
IEEE Type I excitation system [25] is used as AVR. For the
system demand of 100 GW, equivalent system inertia of 7.2
MWs/MVA is assumed by the author for the synchronous
power plants (no wind). Demand is considered 100%
dynamic with a time constant of 0.1s and frequency
dependence of active power is included.
L1a
~
G
Upper Top
-4.62
2.95
10.54
4.75
-2.73
10.54
9.50
-5.45
36.52
~
G
1a-2 I
400.00
1.00
18.52
Top-Left
G2
400.00
1.00
15.81
11.15
2.26
-4.62
2.95
10.54
10.44
-4.14
21.62
1a-1 I
395.40
0.99
10.24
-9.88
5.08
21.62
1a-1 II
4.75
-2.73
10.54
TOP
1
10.44
-4.14
21.62
1a-2 II
1a
2
22.80
-0.13
76.00
-9.88
5.08
21.62
1-4
Top-Rigth
4.95
1.01
L1
14.80
-11.16
36.09
1-3
3-4
-14.01
12.46
36.09
4
9.94
-5.37
21.74
-9.37
6.32
21.74
3
400.00
1.00
5.61
7.20
6.77
32.94
20.20
-5.41
69.71
G
~
G
~
14.13
2.87
G4(b)
G4(a)
17.34
-8.61
37.26
400.00
1.00
0.00
8.64
4.60
32.61
Tail-Right
10.95
2.22
7.06
-3.94
15.55
G
~
L4
G3
L3
8.65
-4.74
18.98
-15.66
11.38
37.26
3-7
Upper-Tail
4-7
5-7
-8.21
5.46
18.98
Lowest-Tail
5
7
400.00
1.00
-8.90
9.51
8.76
43.08
17.34
3.52
0.38
-0.23
0.85
9.04
-4.94
19.83
L5
-0.38
0.23
0.85
Branches
Active Power [GW]
Reactive Power [Gvar]
Loading [%]
6
400.00
1.00
-9.12
17.11
11.24
68.23
26.05
5.29
Middle
G7
L7
TAIL
Core+Tail
yout
1 F<
RelFrq*
Trip_Step1
1 Logic
RelLslogic
2 F<
RelFrq*
Trip_Step2
2 Logic
RelLslogic
yout
3 F<
RelFrq*
Trip_Step3
3 Logic
RelLslogic
yout
4 F<
RelFrq*
Trip_Step4
4 Logic
RelLslogic
yout
5 F<
RelFrq*
5 Logic
RelLslogic
yout
Trip_Step5
6 Logic
RelLslogic
yout
U< Logic
RelLslogic
yout
F
0
Measurement
RelFmeas*
G
~
1
G6
L6
U
Project: DPSP 2012
Graphic: Benchmark Model
Francisco M. Gonzalez-Longatt
02/01/2012
fglongatt@ieee.org
PowerFactory 14.0.525
16.14
3.28
G
~
-8.57
5.72
19.83
Benchmark System
fglongatt.org.
11.40
9.40
49.27
6-7
5-6
G5
Under U and Under F: Under U and Under Freq Trip at 6 Steps
Under Frequency Protection
400.00
1.00
-4.01
G
~
Load Flow Balanced
Nodes
Line-Line Voltage, Magnitude [kV]
Voltage, Magnitude [p.u.]
Voltage, Angle [deg]
-6.76
4.43
15.55
outside statutory limits: range 49.8 Hz to 50.2Hz for more
than 5 cycles, (ii) the level of normal loss of power infeed is
set-up to 1.35 GW, frequency response to avoid a deviation in
the system frequency by more than 0.2Hz, (iii) the system
frequency could rise to 52 Hz or fall to 47 Hz in exceptional
circumstances. If system frequency is over 52.0 Hz, overfrequency relays will trip generators, (iv) frequency control
devices (or a speed governor) are set up to operate with an
overall speed Droop of 4% (GB SQSS establishes between 3
and 5%). In this paper, UFLS is set to start at 49.8Hz and the
plan consists of six load shedding steps of unequal size with
the total amount of load shed of 0.25 p.u [26]. A delay for
each load shedding step is 0.1 s (5 cycles). Figure 5 shows
specific under-frequency relay model developed and used in
this paper.
DIgSILENT
DIgSILENT
G1
Date: 2/13/2012
Annex:
6 F<
RelFrq*
Trip_Step6
DIgSILENT
Figure 2: Test System: Case Base.
gov_GTGOV: General Turbine Governor
Under_U
U<
RelUlim
psco
0
Under Voltage Protection
psetp
1
Valve Vmax
Droop
-
w
2
Pole/Zero
Gain
at (1+sTb)/(1+sTa)
T3,T2
{1/(1+sT)}
T1
pturb
K
At
0
-
dw
wref
-
1/K
R
0
Vmin
3
1
Friction
wlss
K
Dt
Turb
Pturb
Figure 5: Under-frequency Relay Model including 6-step
load shedding.
pt
1
2
Power Base
sgnn
4
cosn
5
5.3 Wind Turbine Model
DIgSILENT
Figure 3: Model of General Turbine Governor.
avr_IEET1: Modified 1968 IEEE Type 1 Excitation System
IEEE Std 421.5-1992
IEEE Recommended Practice for
Excitation System Models for Power
System Stability Studies
voel
0
vuel
1
3
4
Te and and gain Ke
associated with the
voltage regulator
Voltage Regulator
Vrmax
usetp
2
u
upss
-
Verr
-
{K/(1+sT)}
Ka,Ta
Vr
1/sT
Te
-
efd
uerrs
Figure 6 depict the general structure of a variable-speed wind
turbine with a direct-drive permanent magnet synchronous
generator (PMSG) and Figure 6 shows the model for the wind
turbines created using DSL. Figure 7 show the models used
for a back-to-back converter, details of each model are taken
from: [27], [28], [29]. The parameters used for these models
are escalated to simulate an equivalent 5 MW wind turbine.
Limiter_int
EFdmax,EFdmin
Vf
Vrmin
K
Ke
Se
sK/(1+sT)
Kf,Tf
Se(Efd)
E1,Se1,EFdmax,Sefdmax
Saturation
Figure 4: Model of General AVR.
Figure 6: General structure of a variable-speed wind
turbine with a direct-drive synchronous generator with
full-scale frequency converter.
5.2. Frequency Response Assumptions
5.4 Results and Discussion
In this paper, the operational-control criteria used for system
frequency analysis is based a specific criteria defined by the
author, it is mainly a personal version of the GB Security and
Quality of Supply Standards (GB SQSS). The following
assumptions are used in this paper: (i) the level of infrequency
loss of power infeed is set-up to 1.800 GW, and frequency
response must avoid a deviation of the system frequency
The impact of a synthetic inertia is being quantitatively
analysed through time-domain simulations. This is a multimachine system as consequence, the author uses the concept
of frequency of inertia centre (fc) to analyse changes in
system frequency. A loss infeed is used as system frequency
disturbance; it consists of tripping at t = 1.0s of one
generating unit connected to Upper-Tail area at 1s (generator
DIgSILENT
Variable Speed Wind Turbine: Permanent Magnet Synchronous Generator
0
0
Rotor
0
DIgSILENT
0
PLL_R
ElmPhi*1
P
cosref_R
sinref_R
DC Voltage
StaVmea*
0
Vdc_ref
1
Vac-P Controller
ElmDsl*
3
4
Vdc
5
id_ref_R
Inverter
ElmVsc*
3
PLL_I
ElmPll*,ElmPhi*
DC/AC
Controller
7
1
cosref_I
sinref_I
300MW
500MW
700MW
1350MW
1500MW
1800MW
2300MW
2800MW
3200MW
Annex: /2
0.1
50
49.5
0
10
20
Time (s)
0
I
II
III
IV
V
-0.1
-0.2
-0.3
30
0
-0.06
-0.08
1
20
2
30
Time (s)
3
40
50
49.8
0
49.6
49.4
H= 0.1s
49.2
50
5
10
Time (s)
15
20
Figure 8: Under-frequency Relay Model including 6-step
load shedding.
The author used an exceptional loss of power infeed to trigger
a substantial frequency excursion in the Test System; this
system frequency disturbance activates the UFLS. This
exceptional loss risk deviates system frequency more than
741 mHz and persist for more than 5 cycles (see Figure 9 and
Case I Figure 10). Several UFLS schemes on demand side of
Tail area are tested, loads: L4, L5, L6, L7 (see Figure 2),
results of system frequency and ROCOF are shown on Figure
10 (load shedding Case I: 0 GW, II: 2.8260GW, III: 6.2940
GW, IV: 5.7520GW, V: 7.3660GW). A cluster of wind farms
is connected on bus 3 at the Tail-Right area and is generating
30 GW and the control loop for releasing "hidden" inertia of
49.8
49.6
49.4
H= 1.0s
49.2
50
60
I
II
III
IV
IV
-0.1
-0.2
-0.3
0.1
df/dt (Hz/s)
-0.04
0.1
0
-0.1
-0.2
-0.3
49.8
df/dt (Hz/s)
-0.02
50
49.6
49.4
0
-0.1
H= 5.0s
49.2
50.2
-0 2
0.05
H= 10.0s
50
df/dt (Hz/s)
-0.02
df/dt (Hz)
df/dt (Hz)
0
10
59.99
Date: 2/17/2012
Figure 10: System Frequency and ROCOF considering
different UFLS schemes: Base Case
Frequency (Hz)
0
0
[s]
Response
March 2012
df/dt (Hz/s)
0.02
-0.1
47.99
(c)
3
Figure 7: General structure of the model for back-to-back
converter.
-0.08
36.00
Francisco M. Gonzalez-Longatt, PhD
2
DC/AC
Converter
AC/DC
Converter
Vac-P
-0.06
24.00
59.99
6
AC/DC
Controller
-0.04
12.00
(b)
Exceptional Loss of Infeed
49
2
3
[s]
50.5
Frequency (Hz)
fsys
1
5
0
iq_ref_R
47.99
Figure 9: System Frequency response to an exceptional
loss of generation infeed (a) Frequency, Generation active
power in GW (b) with and (c) without frequency response.
Udc-Q
1
36.00
15.00
Frequency (Hz)
AC Grid Voltage
StaVmea* 1
Vdc_ref
u
iq_ref
0
Rectifier
ElmVsc*
2
0
0
id_ref
2
4
Q
Vac_Gen
1
Controller
ElmDsl*
0
Q_ref
Power Meas_Grid
StaPqmea*
AC Gen Voltage
StaVmea*
0
1Vdc-Q
1
Vac_ref
24.00
20.00
Frequency (Hz)
Power Meas_Gen
StaPqmea*
0
12.00
59.99
25.00
fglongatt
Vdc
P_ref
[s]
30.00
8.00
0.000
Back-to-Back Frame: Converter and Controllers
MPT
ElmMpt*
47.99
9.00
Figure 6: General structure of the model for a variablespeed wind turbine.
speed
36.00
10.00
1
Shaft
Speed Measurement
1
ElmSpe*
Speed Measurement
Elm*
24.00
df/dt (Hz/s)
vw
Wind Speed
12.00
11.00
hpi
Turbine
ElmTur*
pt
speed_gen
1Wind
2
0
Shaft
1 ElmSha* 1
speed_gen1
Wind Speed
ElmFile
0
(a)
49.20
0.000
12.00
Generator
ElmSym* 3
omega_tur1
Pwind
49.40
13.00
2
0
56.722 s
49.513 p.u.
14.00
ve
1
beta
16.252 s
49.560 p.u.
49.60
0.00
0.000
Mechanical System
Pitch Control
ElmSha*
6.602 s
49.259 p.u.
49.80
Frequency (Hz)
PMG
50.00
5.00
u
1
50.20
10.00
curex
0
H = 3.75s is included. Benefits of the integration of this wind
farm include the reduction of power flows between Top and
Tail areas but an increase of 164 mHz in the minimum
frequency during at exceptional loss of the power infeed.
DIgSILENT
G4(b) on Figure 2). The case base consists of just
synchronous generators (no wind) which feed system
demand. The author assumes four generators providing a
governor frequency response and three conventional
generators (G2, G5, and G7) will be operating without active
governors (e.g., nuclear power stations) or at maximum
power (e.g., valves wide open). Several levels of loss of
power infeed from 0.3 to 3.2 GW are simulated and rate of
change of frequency (ROCOF) is plotted on Figure 8. The
ROCOF and the minimum frequency (nadir) increases as the
level of loss of power infeed increase.
49.8
49.6
0
10
20
Time (s)
30
0
-0.05
-0.1
0
5
10
Time (s)
15
20
Figure 11: System Frequency and ROCOF considering
different UFLS schemes: Wind Integration.
The inertial control has a substantial impact on system
performance. The short term impact is delivery of extra power
from WT with substantially reduces the ROCOF, allowing
time for the active governors to respond (see Figure 11).
Increasing the capability of WT to release of hidden inertia
helps to delay the UFLS. However, the frequency response
provided by synthetic inertia might not completely avoid
UFLS. Reducing the amount of synthetic inertia reduces the
recovery effect but frequency support provided by wind
turbines is reduced as well. Results demonstrate UFLS helps
to reduce the negative recovery effect caused by synthetic
inertia and increase security level during extreme loss power
infeed.
4 Conclusions
This paper is presents simulations results that provide ideas
about the potential impact of synthetic inertia on wind
turbines based on full-converter on the under-frequency
protection/control schemes during the recovery period after
system frequency disturbance happen. The substantial impact
of synthetic inertia is on system inertial response: (a) the extra
power delivered from WT can substantially reduces the
ROCOF (b) it provides time for the active governors to
respond, however a coordination between controllers looks
desirable (c) increasing synthetic inertia helps to delay the
UFLS (d) synthetic inertia might not completely avoid UFLS,
(e) UFLS helps to reduce the negative recovery effect caused
by synthetic inertia. The main contribution of this paper is to
demonstrate (based on simulations) recovery period of underfrequency transient on future power systems that integrate
synthetic inertia capability not completely avoid worse
scenarios in terms of UFLS.
[9]
[10]
[11]
[12]
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[17]
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[19]
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