CROSS-CULTURAL VALUES DIFFERENCES VERSUS CROSS- OUNTRY RNS N T
Cross System Differences In LOM Events
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Transcript of Cross System Differences In LOM Events
Cross-system Differences in Anti-Islanding Protection Techniques Final Year Project, Electrical & Electronic Engineering BEng Honors Institute of Energy, Power and Intelligent Control
R. Robinson, Dr R. Best, and Dr T.Littler (Moderator) 6-1-2016
| i
Abstract
Islanding is an ever more prevalent issue in the power and energy sector.
The socio-political trend towards renewable and distributed energy schemes
makes this issue even more significance in the future, particularly to weak
systems already prone to nuisance tripping of protection equipment. The
following paper investigates two common methods of anti-islanding protection,
ROCOF and Vector Shift. Using SimPower Systems both approaches are
algorithmically applied to a hypothetical transmission network. Ultimately the
project focuses on how each method varies when calculated at different areas in
the hypothetical network drawing upon classical power systems theory
| ii
Specification
The principle objective of this project is to characterise cross-system
differences in anti-islanding protection methods during the same system-wide
disturbance.Focusing on two common passive techniques of anti-islanding
protection, ROCOF and Vector Shift, particular attention is drawn to how
calculated values of these algorithmic approaches vary when observed in
different locations of a hypothetical power system relative to disturbance
location, embedded generation plant and physical electrical distance.
A SimPower Systems model representing the hypothetical power system is
presented capable of disturbance application and data acquisition. ROCOF and
Vector shift protection methods employ microcontroller-based relays that
switch based on thresholds, therefore a set of easily computer-translatable
calculations for estimating ROCOF and Vector Shift values exists.
Findings are compared with current practice and the project developed to
provide detailed recommendations for threshold settings of the aforementioned
protection methods. The following objectives of the project are identified as
follows:
1. Gain an understanding for the need for anti-islanding protection and the
common methods used
2. Construct a two-are power system model to which disturbances can be
applied
3. Implement Vector Shift and ROCOF algorithms
4. Characterise cross-system differences in each of the two methods
| iii
Acknowledgements
Thanks are given to Dr. Robert Best for the opportunity to engage in the
EPIC institute and specialize in the power, energy and protection field during
my time at QUB. Dr Best’s support as personal tutor and project supervisor have
been a career shaping catalyst.
Declaration of originality
I declare that this report is my original work except where stated.
...........................................................................
Ruairdh Robinson
| iv
Contents Abstract – 200 words, expand the text below, PRIORITY ........................................................ i
Specification .............................................................................................................................. ii
Acknowledgements .................................................................................................................. iii
Declaration of originality ......................................................................................................... iii
Abbreviations ............................................................................................................................ vi
Index Terms .............................................................................................................................. vi
1. Introduction ...................................................................................................................... vii
2. Islanding & Protection Methods ..................................................................................... viii
2.1. Islanding in Power Systems .................................................................................... viii
2.2. Rate of Change of Frequency Based Protection......................................................... ix
2.3. Vector Shift Based Protection .................................................................................... xi
3. Model Development ....................................................................................................... xiii
3.1. Model Overview ...................................................................................................... xiii
3.2. Steady-state Network Development ............................................................................ xiv
3.2.1. Generator & Excitation System in SimPower Systems ....................................... xvii
3.2.2. Transmission Line Parameters.............................................................................. xxi
3.2.3. Steady-State Operation in SimPower Systems .................................................... xxii
3.3. Frequency measurement using zero crossings ........................................................... xxvi
3.4. Implementing a Disturbance ..................................................................................... xxvii
3.5. ROCOF measurement approach ............................................................................. xxviii
3.6. Vector Shift measurement approach .......................................................................... xxix
3.7. Data Acquisition ........................................................................................................ xxxi
4. Cross-system Differences in the Two-Area Network ................................................... xxxii
4.1. ROCOF: Area Comparison ..................................................................................... xxxiii
4.2. Vector Shift: Area Comparison ................................................................................ xxxv
4.3. ROCOF & Vector Shift: Notable Conclusions ........................................................ xxxvi
| v
5. Conclusion ................................................................................................................ xxxviii
References (see below) ............................................................................................................ xli
Appendices ............................................................................................................................. xlii
| vi
Abbreviations
LOM – Loss of Mains
ROCOF – Rate of Change of Frequency
PV - Photovoltaic
Index Terms
ROCOF event
Vector Shift event
Bulk generation plant
Transmission network
[Public] Utility network
Distributed generation plant/Distributed generator
Embedded generation
System wide disturbance
Power Island
| vii
1. Introduction
‘Islanding’ refers to a scenario where distributed generation plant
deliver power to utility loads in place of the main source of generation. This
occurs when, in the event of a system wide disturbance, a distributed generator
does not act to isolate itself from the utility network thus continues to supply all
loads downstream of itself.
Islanded operation within a power network presents power quality issues, risk
to plant and safety hazards. As such anti-islanding protection measures are a
legislative requirement in the UK under the Engineering Recommendation
G59/3, which stipulates that all utility network embedded generation plant
employ passive, independent protection relays capable of detecting when
connection to the main source of generation is lost (known as a ‘Loss of Mains’
event). Grid parameters are measured and checked against defined threshold
settings. Two commonly employed methods of protection are based on Rate of
change of Frequency (ROCOF) and Vector Shift calculations, however current
practice is prone to wide spread nuisance tripping[1].
Using SimPower Systems this paper therefore seeks to characterize how
ROCOF and Vector Shift values varying when calculated at different parts of
the power network, and ultimately characterise visible trends in the collected
data.
| viii
2. Islanding & Protection Methods
2.1. Islanding in Power Systems
In order to understand the islanding problem consider figure 2.1 below. A fault
occurring on line A has caused a breaker to isolate this section of line. A
distributed generator is located downstream of this fault continues feed into the
remaining utility network and supply utility loads.
Figure 2.1 The Power Island
Islanding presents multiple risks and hazards. Once the island has formed the
utility network and island will be out of synchronization, re-synchronization
miss-match can cause risk to substation and generator equipment as well as
personnel/operatives. Furthermore sections of the utility network can remain
unintentionally live since they may being fed by the islanded generator
presenting risk to utility network personal when attempting to clear faults (faults
which consequently may have instigated the island). Islanding can also imply
un-grounded operation presenting risk to utility consumer equipment.
| ix
Another prevalent concern is cascade tripping: when a Loss of Mains event
triggers a large frequency deviation, tripping multiple distributed generation
schemes and potentially causing further island formation.
2.2. Rate of Change of Frequency Based Protection
The ROCOF calculation method works on the principle that at the moment of
island formation power imbalances exist in the network as the loads
downstream of the island no longer demand power of the main source of bulk
generation but rather from the islanded generation plant. In such circumstances
synchronous generators on the network will change speed in response to the
change in load demand, which consequently causes a sudden deviation in
nominal frequency and system inertia. This is expressed below in equation 2.1.
𝑑𝑓
𝑑𝑡=
𝑓(𝑃𝐺 − 𝑃𝐿)
2𝐻𝑆𝑛 (𝐻𝑡𝑧/𝑠) (2.1)
Where f = nominal frequency (Hz)
𝑃𝐺 = Generator output (MW)
𝑃𝐿 = Load demand (MW)
H = system inertia (s)
𝑆𝑛 = rate capacity of generation plant (MW)
It can also be seen from (2.1) that ROCOF is proportional to system inertia. As
synchronous generators attempt to restore network power balance inertia stored
in the rotating masses of the respective generators is injected/absorbed into the
network, this known as the ‘inertial phase’ dampening frequency deviation.
Referring to (2.2), the generator swing equation, and (2.3) it is clear how
differences in mechanical an electrical torque effects generator swing, and
swing and generator rotor speed 𝜔𝑟 relates to inertia. It is obvious that the
square of rotor speed will gave a significant consequence on system inertia.
| x
𝐽𝑑𝜔𝑟
𝑑𝑡= 𝑇𝑚 − 𝑇𝑒 = ∆𝑇 (2.2)
𝐻 =1
2⁄ 𝐽𝜔𝑟02
𝑆𝑛 (𝑠) (2.3)
Where
J = inertia constant [kg m2] 12⁄ 𝐽𝜔𝑟0
2 = kinetic energy at sync speed
𝜔𝑟 = rotor speed [rad/s] Sn = generator nominal power [MVA]
Tm = Mechanical torque [Nm]
Te = Electrical torque [N]
∆𝑇= change in torque
However the electricity market has seen a trend towards renewable source of
energy such as wind and solar photovoltaic (PV), which have little or no inertial
dampening effect: solar PV schemes are inertia-less by nature whilst wind
schemes tend to have their rotating shafts electrically decoupled via a back-to-
back converter. Thus replacing traditional generation with inertia-less schemes
creates a system were frequency is more sensitive to abrupt changes in load and
generation meaning large values. This can result in high ROCOF values as a
consequence cascade-tripping of other distributed generation. [2, 3]
| xi
2.3. Vector Shift Based Protection
Like the ROCOF method Vector shift calculations work on the principle that in
the instance of island formation a power imbalance exists. However the vector
shift method is based on detection of voltage phase-angle deviations. Consider
circuit figure 2.3. Pre-island formation switch A is closed, load is being drawn
from the utility network and distributed generator, ILine = Ig + ILoad. It can also
be said that Ztotal = ZLine + ZLoad
because of the changing
reactance X/XG. At the instance
of island formation switch A in
the circuit is open, load is
switched out, ILine = Ig and Ztotal
= ZLine, Referring to figure 2.2
the relationship between
impedance and current causes
vector jILoadX to change in magnitude consequently shifting vector VLiine to by
∆𝜃.
Figure 2.3
Figure 2.2
| xii
Vector-shift protection relays are based on the principle described. Referring to
figure 2.3, a protection relay will monitor the voltage profile, in this paper using
the zero-crossings method and compare cycles to identify voltage phase-angle
shifts [4].
Figure 2.4 Vector Surge
| xiii
3. Model Development
Objective 2 of the project stipulates: ‘Construct a two-area power system model
to which disturbances can be applied.’ Matlab SimPower Systems software
package was used to realise objective 2, drawing upon power systems, electric
machines and signal processing theory.
The ultimate aim of the project is to characterise cross-system differences in
anti-islanding protection methods during the same system wide disturbance
therefore the top level of a typical power system, the transmission network, has
been constructed.
Discrete time domain has been chosen to aid in the transformation of ROCOF
and vector shift algorithms, total simulation run time is 80 seconds, this is ample
in establishing steady-state and implementing the disturbance.
3.1. Model Overview
Shown in figure 3.1 the model consists of bulk thermal generation plant
Machine 1 and Machine 2, rated at 600MVA and 900MVA respectively and
supplying a 967MW load across line distance of 100kM. Line voltage is rated
at 440kV and nominal system frequency is 60Hz
The total load is split between two blocks, Load 1 and 2. Load 2 implements the
disturbance: a time delayed contactor isolates Load 2 from the main network
during nominal operation, switching out a portion of load demand thus
emulating an island event.
ROCOF and Vector Shift calculations are based on frequency measurement.
Frequency is estimated using the zero crossings method the single-phase voltage
‘a’. ROCOF is calculated in Area 1 and Area 2, either side of the transmission
| xiv
line, creating electrical distance and therefore comparable differences in both
calculation sets. Vector shift is calculated in area 1 and area 2, close to the area
of disturbance, the expected area of largest deviation. Refer to appendix a for a
larger view of the model.
Figure 3.1 Two-area Network
3.2. Steady-state Network Development
A power system is said to be in steady-state when total power generated
is equal to load power and coupled generating plant are in synchronous, i.e.
generating plant have matched frequency, transmission angle and voltage.
| xv
These conditions must be maintained in order to ensure system stability and
consistent power delivery. In industry this is achieved by careful load flow
analysis and generator control.
Nominal operation of the two-area network model presented in figure
3.1 is of constant load, therefore considered generator control methods,
complementing accurately chosen design parameters, resulted in steady-
steady operation.
Synchronous generators are kept in stable operation by their
governing and Auto Voltage Regulator (AVR) control systems. The
governor control active power output, essential in maintaining system
frequency. Frequency is related to machine output power, neglecting loses
by equation (3.1).
𝑃𝑜𝑢𝑡𝑝𝑢𝑡 = 𝑇𝜔𝑚 (W) (3.1)
T = torque applied to the generator shaft via the prime mover
ωm = generator rotor speed (rad/s)
And
. 𝜔𝑚 =2𝜋𝑁
60 (𝑟𝑎𝑑𝑠/𝑠) (3.2)
N = rotor speed (rpm)
𝑁 =120𝑓
𝑃𝑜𝑙𝑒𝑠 (𝑟𝑝𝑚) (3.3)
During changing load conditions the synchronous generator will speed up
or slowdown in order to try and balance real power output with real power
delivered, it can be observed from 3.3 that this will then cause frequency to
fluctuate. The governor acts to maintain system speed and consequently
frequency by altering real power output through altering the torque applied
| xvi
to the shaft, keeping rotor speed and thus frequency at a relatively constant
value.
Transmission angle 𝛿 is also dependent on real power output in accordance
with (3.4).
𝛿 = sin−1 (∆𝑉𝑞
𝑉𝐺) (3.4).
VG = generator voltage
And ∆𝑉𝑞 is the change in generator voltage in the q axis due to changing
load conditions.
∆𝑉𝑞 = 𝑋𝑃 − 𝑅𝑄
𝑉𝐿 (3.5).
VL= line voltage
X = line reactance
R = lIne resisance
In general for high voltage power systems 𝑋 ≫ 𝑅 thus transmission angle
is mostly influenced by real power injection. Reactive power injection
influences system voltage. Referring to (3.6) and observing the above
resistance/reactance relation, system voltage is proportional to reactive
power injection.
∆V = 𝑅𝑃 − 𝑋𝑄
𝑉𝐿 (3.6)
∆V = sytem voltage deviation
VL= line voltage
X = line reactance
R = lIne resisance
| xvii
Auto Voltage Regulators control reactive power output of the synchronous
generator and act to stabilise system voltage. Referring to (3.7) this is
achieved by altering excitation current to the field windings of the generator
stator.
𝑄 = 𝐸𝑓 ∙ 𝑉 ∙ 𝐼𝑓 ∙ 𝑋 ∙ 𝑐𝑜𝑠𝛿−𝑉2
𝑋𝑠 (𝑀𝑉𝐴) (3.7)
Ef = generator field frequency
V = line voltage
I = field current
X = system reactance
3.2.1. Generator & Excitation System in SimPower Systems
SimPower Systems provides an extensive library of IEEE standard
electrical blocks with default set parameters and extensive help files which
make block interpolation and model development easy. The two-area
transmission network presented in this project consists of two
governor/AVR controlled round-rotor synchronous generators,
implemented using the ‘Turbine
and Regulators’ and ‘Synchronous
Machine PU Standard’ blocks
respectively. Referring to figure
3.1 ‘Synchronous Machine PU
Standard’ block models a 3-phase
synchronous motor or generator
(user defined by sign of apparent
power parameter in the dialogue
Figure 3.1
| xviii
box). ‘Pm’ is the mechanical power, or torque, applied to the machine shaft,
essentially functioning as the prime mover, the action of which is
determined by the governor, ‘Vf1’ is the field or excitation voltage applied
to the stator field, the acting AVR. Output ‘m’ of the synchronous machine
block is the feedback section, feeding electrical characteristics of the plant
to the ‘Machine # Turbine and Regulators’ block, which is illustrated in
figure 3.1. Steady state operation of the two-area network required careful
consideration of block parameters, drawing upon the theory outline in
previous sections of this report.
As stated the model consists of two synchronous machine blocks
representing bulk thermal generation plant, Machine 1 rated at 600MVA
and machine 2 9000MVA, totalling 1050MW and supping a load of
967MW. These conditions along with nominal operating voltage (22kV)
and frequency (60Hz) were defined in the parameters dialogue box. Both
bulk generation plant were set to set to be of round rotor type, with 1 set of
pole pair each. Control approach can also be defined in the configuration
dialogue box, illustrated below in figure 3.2. SimPower Systems allows
definition of two forms of speed control, and consequently frequency
control: ‘Mechanical Power’ and ‘Speed w’. The latter option imposes a
fixed machine speed and ignores the characteristics of the system, however
this project utilises the ‘Mechanical Power’ option allowing the interfacing
of a governor system with the synchronous machine block. Selecting this
option allows generator speed to be determined by a feedback system that
considers system inertia and the difference between mechanical torque
applied by a prime mover and resultant shaft electromechanical torque.
| xix
Figure 3.2
Generator Control is implemented using the SimPower Systems blocks
‘Steam Turbine Governor’ (STG) and ‘Excitation’ system, illustrated below in
figure 3.2.1.3. A ‘MUX’ block is used to split input ‘m’, the measured generator
electrical characteristics. The STG block implements a passive steam turbine
with prime mover, the SimPower Systems block consists of a speed relay,
proportional speed regulator and servomotor controlled gate. ‘Pref’ is the
reference real power output and is automatically computed by SimPower
Systems. ‘Wref’ is a constant and sets the reference rotor speed at 1 p.u.
Nominal rotor speed, set in the parameters dialogue box of the STG block, is
set at 3600rpm for a single pole pair synchronous generator operating at 60Htz.
Therefore the governor is set to maintain the ideal operating speed of 1 p.u. of
nominal speed. Input ‘Wm’ is the actual measured rotor speed, whilst rotor
angle deviation is read from input ‘d-theta’. The governor works by measuring
current generator speed and the reference value and altering the steam applied
the turbine and thus the mechanical torque applied to the generator via the
| xx
prime-mover, achieving steady state operation of the two-are network required
balancing of the response of the STG.
Figure 3.3 Steam Turbine Governor Mask
Gate opening times, that is the gate which controls steam flow turbine and
consequently torque at the prime mover, were altered to provide a faster
responsive action from the STG and this achieve steady-state operation of the
two-area network model.. The SimPower Systems nominal values are set at
range 2pu/s (-0.1, 0.1), this was later to 4pu/s (-0.2, 0.2). Nominal droop
characteristics remain at the SimPower Systems default, with both synchronous
machine blocks having equal droop settings as is ideal.
The effective AVR, the ‘Excitation’ block is also shown in Figure 3.3.
Default parameters were sufficient in providing steady-state operation of the
transmission network however the following text serves to explain how the
AVR as outlined in the Background section of this report, is implemented in
SimPower Systems. Input ‘Vref’ is the reference terminal voltage specified as
1 p.u. of nominal voltage (22kV). ‘Vq’ and ‘Vp’ the stator q/p axis voltages, the
‘Excitation’ uses these inputs to compute generator terminal voltage and uses a
digital voltage regulator and exciter to apply corrective excitation voltage to the
| xxi
generator stator fields. An additional function has been added to record
generator terminal voltage; using a ‘Real-Im to Complex’ block, signals Vq and
Vp are combined and expressed as a complex value and sent to the Matlab
workspace, data acquisition methods are comprehensively discussed in the
chapters to follow. Finally input ‘Vstab’ of the ‘Excitation’ block is an
additional voltage stabiliser and is not used in this model.
3.2.2. Transmission Line Parameters
The transmission line has been implemented using SimPower Systems
‘Three-phase RLC’ block, illustrated below in figure 3.4. This block
introduces a user definable resistive, inductive and capacitive elements to
the three-phase circuit. The block has been set to contain a resistive and
inductive element only and configured to 26Ω and 19mH respectively
implementing an equivalent transmission line length of 100kM.
Figure 3.4 Series RLC Branch
| xxii
3.2.3. Steady-State Operation in SimPower Systems
Generator stability and power sharing have been achieved through careful
setting of model parameters and excitation systems. The following are excel
generate graphs proving system stability.
*Note a simulation transient exists at t = <10S and so should be negated.
The model is set to run in discrete operation with a sample rate of 50ms. The
following test results were capture over a simulation time of 100s. Line
voltages. Figure 3.5 illustrates the p.u voltages of measured at each generator
terminal, it is assumed in this demonstration that 𝑉𝑡 ≈ 𝑉𝑙𝑖𝑛𝑒 since the KVL
detects. It can be observed that 𝑉𝑡 = 1 p.u indicating stable system voltage.
Figure 3.5 Machine Terminal Voltage
As mention in the background section of the report, synchronous generators
must be synchronised in terms of rotor speed, this is observed in figure 3.6, the
waveform profile is as expected of stable operation and synchronous speed is
maintained at approximately t = 20s.
0.5
0.6
0.7
0.8
0.9
1
1.1
1.2
0 10 20 30 40 50 60 70 80 90 100
Vo
ltag
e (p
u)
Machine Terminal Volage
VT_1 (pu) VT_2 (pu)
| xxiii
Figure 3.6 Machine Terminal Voltage
System frequency detection was conducted using the zero crossings method,
and system measured charter tics show a stable 60Hz system frequency with no
major deviations +/- 0.1Hz, this is illustrated in figure 3.7.
Figure 3.7 Nominal Frequency
0.995
1
1.005
1.01
1.015
1.02
1.025
0 20 40 60 80 100
Wm
(p
u)
Time (seconds)
Machine 1 & 2 Rotor Speed
Wm 1
Wm 2
| xxiv
Finally as stated in chapter 2 power generated must equal power delivered,
illustrated by figure 3.8, it can be seen that the 1050 capacity meets the 957 MW
demand.
Figure 3.8. Line Power
The final test of steady-state operation is real and reactive power sharing,
which it can see in figures 3.9 and 3.10. Thus it can be concluded that the two-
area network construct is operating in steady state.
| xxv
Figure 3.9. Machine 1 (P1) and 2 (P2) Real Power Output
Figure 3.9 Line Reactive Power
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
0 10 20 30 40 50 60 70 80 90 100
P (
pu
)
Time (s)
Machine Real Power Ouput
P1 (pu) P2 (pu)
40
45
50
55
60
65
70
75
80
0 10 20 30 40 50 60 70 80 90 100
Q (
MV
A)
TIme (seconds)
Reactive Power (per phase) - Line
| xxvi
3.3. Frequency measurement using zero crossings
Frequency measurement is achieved using the zero crossings method,
emulating industrial relay operating principles. The Simulink model is shown
in figure 4.0, appendix b. The algorithm calculates frequency based on
single-phase voltage waveform period measurement via a counter which
increments when it receives an impulse from the pulse generator. The count
is the reference time for 1-cycle and is reset at the beginning of each new
cycle via the reset trigger. Sinusoidal single-phase voltage is converted to a
square wave via a relay, the counter is configured to reset at the rising edged
of the signal i.e. a cycle’s first positive zero crossing. The counter outputs
continuously however it is necessary only to capture the peak value i.e. the
total period. A sample and hold block is used. Configure to have a latched
input i.e. it will forward the value at the last observed time step when forward
initiated. A sample starts when the trigger detects a rising-edge and held until
it is initiated to start a new signal, therefore the square-wave transformed
voltage is used to sample every voltage cycle.
Figure 4.0. Frequency Measurement
The voltage wave form period is then sent to a simple divider were frequency
is calculated on the simple relation shown in 3.1.
| xxvii
𝑓 = 1
𝑇 𝐻𝑧 (3.1)
Where T = period
3.4. Implementing a Disturbance
A disturbance of 20% of the nominal load has been chosen as this has
been found to be sufficient in producing presentable results. Nominal load is
then set to 757 MW and disturbance load at 210MW. The disturbance is
modelled using a time delayed contactor which isolates Load 2 from the main
network during nominal operation, switching out a portion of load demand thus
emulating an island event. The time delay is set to open the contactor at T =
50s. Figure [4.1] illustrates the effect on line power, the 20% disturbance is
easily seen, dropping from nominal ≈ 1000 MW to ≈ 800 MW. The effect that
this has on the two-area network modelled are discussed in chapter 4.
It should be noted that after the network experiences the disturbance steady-
state is lost and stability is not reach within simulation time, however this is of
no consequence to the scope of this project since the main objective is to observe
the instance of island formation that is the instance the disturbance load is switch
out of the network
| xxviii
Figure [4.1]
3.5. ROCOF measurement approach
Figure [4.2], appendix c below shows the ROCOF algorithm used in the
model. The algorithm works on a similar principle to that employed in
industrial protection relay equipment. Block ‘A’ is a ‘From’ block which
forwards the measured frequency to delay block ‘Zd’, configure to delay the
signal by 6-cycles. Considering this model is in the discrete time domain the
delay duration is specified in sample period lengths rather than time. The
sampling interval of this model is 1/20,000 s, cycle period has been observed
as 16.72ms, therefore one cycle in this model workspace takes 333 sample
lengths, hence the delay length ‘Zd’ has been set to 2000 sample lengths, 6
times 333 sample lengths.
Instantaneous area frequency f (t) and delayed frequency f (t – Tdelay) are sent
to an operator which subtracts the current frequency and delayed frequency
to discern deviation in frequency ∆f. Frequency deviation ∆f is then
| xxix
forwarded to a divisor which divides ∆f by the time it took those 6-cycles
to complete, thus computing the value of ROCOF 𝑑𝑓
𝑑𝑡 in accordance with
equation [inert]
Figure [4.2]
3.6. Vector Shift measurement approach
As described in chapter 2.3 the vector shift principle is based on detection of
voltage phase-angle deviations. The following algorithm realises this
principle by relating 1-cycle to its immediate previous cycle and measures
the difference in terms of degrees thus giving phase angle difference ∆𝜃.
Vector shift estimation was realised by utilising the zero-crossing method of
frequency measurement. Variable ‘B’ is fed from the algorithm shown in
figure 4.3, appendix e, which ascertains through single-phase voltage
measurement the signal period in the same way discussed in section 2. The
final count value within 1-cycle, i.e. the period, is then related in electrical
degrees; referring to figure 4.3, appendix d one electrical cycle corresponds
to 360o with a period of 16.75ms (333 sample lengths) for a 60Hz signal thus
| xxx
1ms = 0.9261. Signal B is sent to a multiplier of constant value 0.9261 to
perform this transformation.
Figure [4.3]
Signal B is also fed into delay block ‘Z333’ to perform the 1-cycle delay, delay
duration 333 sample lengths corresponding to 16ms. The delayed signal is
again sent to a multiplier of constant value relating it in electrical degrees.
Once the aforementioned operations are performed, the instantaneous
electrical phase angle and electrical phase angle 1-cylce previous are
obtained. These signals are then taken away from each other to obtain the
deviation in phase angle ∆𝜃, expressed mathematically in 3.2.
∆𝜃 = 0.9261(𝑇 − 𝑇𝑛−1) (𝑑𝑒𝑔𝑟𝑒𝑒𝑠) (3.2)
| xxxi
3.7. Data Acquisition
The data acquisition subsystem, illustrated in figure 4.4 a larger view in
appendix e, serves three functions; to receive captured data, send forward data
to other areas of the model and the work space.
Figure 4.4
The following are block inputs;
| xxxii
Capturing;
Time
Forwarding;
Frequency system 1
Frequency system 2
ROCOF area 1
ROCOF area 1
Vector shift area 1
Vector shift area 2
Machine 1 and 2 real power (pu)
Machine 1 and 2 terminal voltage
Machine 1 and 2 rotor speeds
Machine 1 and 2 rotor deviation
Machine 1 and 2 rotor angles
Machine 1 and 2 rotor angle deviations
Line P
Line Q
The ‘ToWorkspace’ block forwards data to the Matlab workspace in the form
of a 2 dimensional array. Simulation time in the continuous time domain is kept
via a ‘clock’ and in two decimations, keeping time in intervals of 1/10th of a
second for ROCOF and vector shift analysis and 1s for all others. Sample time
is defined in the ‘ToWorkspace’ block.
4. Cross-system Differences in the Two-Area Network
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Chapter 3.4 outlined how the island event was implemented in SimPower
Systems, being modelled as loss of load. In this chapter focus is analysis of the
network under disturbance conditions, specifically loss of 20% of nominal load.
Results are collated and graphically illustrated to aid discussion, for the same
purpose figure 4.5 illustrates a simplified representation of the two area
network, for the full SimPower Systems model see appendix a. Area 1 and its
association test points, V-Shift TP 1 and ROCOF TP 1, and Area 2 with
associated test points of the same abbreviation, are clearly marked out to provide
clarity to the reader in the following sub-chapters.
Figure [4.5]
4.1. ROCOF: Area Comparison
Figure [4.6] below illustrated the ROCOF magnitude as measured at area 1, test
point 1 represented by the orange line, and in area 2, test point 2 represented by
the blue line. The disturbance is applied at T = 50s. It can be observed that
initially ROCOF at area 2 surpasses area 1, however this the peak value of area
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2 at this instance in time is < 0.4 Hz/s, within threshold limits of the typical
ROCOF relay. At T = 50.07s the difference in ROCOF magnitude is quite
notable. ROCOF as measured in area 1 is equal to 0.52 Hz/s, while area 2 has
experienced a ROCOF of 0.26 Hz/s. This is significant because at the same time
instance the rate of change of frequency in area 1 is sufficient to trip a typical
ROCOF relay threshold, whilst area 2 falls below the typical threshold. This
illustrates well a scenario were nuisance tripping can occur in area 1 as
distributed generators in this location isolate themselves unnecessarily, or
conversely create further power island formation in area 2 as distributed
generators in this location fail to isolate themselves. What causes such a
difference then?
Previously in the chapter 2.2 is was said that at the instance of island formation
changing load conditions cause synchronous generators on that network to
injected/absorbed inertia in an attempt to restored the power balance, i.e. the
inertial phase. It was also shown in equation 3.4 how system inertia is related
to frequency deviation. Referring to the simplified system, area 2 of the two-
area network contains the larger generator M2, rated at 900MVA against M1 =
600MVA, therefore M2 has a larger rotating mass and thus inertia. Since
ROCOF test point 2 is located close Machine has a greater dampening effect on
frequency deviation in comparison to Machine 1.
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Figure [4.7]
4.2. Vector Shift: Area Comparison
Figure [4.8] below illustrated the vector shift as measured at area 1, v-shift test
point 1 represented by the orange line, and in area 2, v-shift test point 2
represented by the blue line, again the disturbance is applied at T = 50s. At T =
50.01s area 1 experiences a vector shift of 0o whereas area 2 experiences a large
vector shift of 180o. Vector shift at area 2 is certainly sufficiently large to cause
serious problems in a power system, negating the fact that it would defiantly
trip a protection relay. It is assumed that this is the result of simulation transient
error, further investigation outside the scope of this project would confirm so,
and however this text focuses on the proportional difference between the two
areas in an attempt to provide a hypothetical reason as to why these cross-system
differences exist.
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Continuing with vector shift analysis figure [4.8] shows the first notable vector
shift in area 1 occurs at T = 50.2s, measured at -4.32o. Again area 2 is
unrealistically large, at 179o however the ratio between the two areas is notable.
In both observed instances in time area 2 would trip the typical the vector shift
relay, typical threshold 4.8, however area 1 would not. Cross-system differences
in vector shift calculations can be attributed to the physical point of
measurement. In chapter 2.3 that vector shift is proportional to system
impedance. Test point 2 is located very close the fault and will experience a
more dramatic impedance difference, test point 2 is before the transmission line
and thus this has less consequence.
4.3. ROCOF & Vector Shift: Notable Conclusions
Chapters 4.1 and 4.2 characterise cross-system differences in both
vector shift and ROCOF calculations, this chapter attempts to compare notable
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differences between the two common methods of protection. This is important
since, as stated in chapter two, current practice dictates that [reference need]
either method may be used in place of the other as a means of anti-islanding
protection.
Chapters 4.1 and 4.2 concluded that at the same time instance the
ROCOF calculate in area 1 is sufficient to trip a typical ROCOF relay threshold,
whilst area 2 falls below the typical threshold setting. Conversely vector-shift
measured at the same instances in time area 2 would trip the typical vector shift
relay threshold whereas vector-shift measured in area 1 would not. Considering
both protection methods are deemed to be a suitable alternative to each other
this project identifies a flaw in current practice, highlighted by the theory
presented in chapter 2 and the tests conducted in chapter 4. A suitable means of
mitigating this flaw in cross-system island detection would be to conduct
feasibility studies specific to a prospective embedded generation scheme
considering the physical location of that prospective scheme and taking into
account the potential inertia available in that location, as well as the likelihood
of location and magnitude of fault occurrence. A G59 licence requirement could
be then be issued specific to a given stipulating whether ROCOF or vector shift
should be used over one and other rather than as an alternative to each other.
Furthermore it can be observed from figures [4.9], vector shift and
ROCOF] that a value of ROCOF sufficient to trip a protection relay is measure
at T = 50.07s, while a vector-shift value sufficient to trip such a relay occurs at
T = 50.1/50.2. A notable delay exist, vector shift being quicker at detecting the
fault. This exists because frequency is average of a number of cycles whereas
as vector calculation bases its cycle comparison with the immediate previous
cycle. This is true not only of the model presented in this project but also of
industrial relays.
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5. Conclusion
Using SimPower Systems two common methods of anti-islanding
protection, ROCOF and Vector Shift have been compared relative to areas of
significance in the hypothetical transmission network. Both approaches are
algorithmically represented and applied to the network using Simpower
Systems. The project characterised how ROCOF and Vector Shift calculation
vary when calculated at different areas in the hypothetical network and
developed this discussion to include a comparison of the two methods in respect
of each other.
Proximity of test point relative to disturbance location, generator location
and size, and electrical distance have all been considered concluding that factors
that influence how the resultant of each the two methods. ROCOF calculation
was influenced significantly by the available inertia at the test point location
and it was found frequency deviation was dampened closer to the larger of the
two bulk generation sites. Vector shift calculation was influenced by the change
in impedance at the test point and Chapter 2.3 outlined how this varies relative
to the electrical circuit model of the typical power system.
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Cross-system comparisons were developed further to show that at the same
time instance the ROCOF calculate in area 1 is sufficient to trip a typical
ROCOF relay threshold, whilst area 2 falls below the typical threshold setting.
Conversely vector-shift measured at the same instances in time area 2 would
trip the typical vector shift relay threshold whereas vector-shift measured in area
1 would not. ROCOF and Vector Shift are considered equal means of
protection, one can be used in place of the other, and however the findings of
this project highlight how the two methods are in fact not since both have
different factors which influence the calculated value.
The issues outlined in Chapter 4 are known problems that the modern
power industry must address considering an ever changing network topology.
Smart gird technologies and integrated protection device communication
capabilities have the capability of evolving the modern power system to meet
the needs of its changing demand. In specific to anti-islanding protection, and
indeed other means of plant protection such as impedance measurement, the
future of power sees the use of ‘Adaptive relays’: those which can have
thresholds, settings and logic functions altered online by automated control
action. []
Expansion of the project would be to increase the complexity of the
network and the sophistication of measurement techniques. For example it was
highlighted in the text that the trend towards inertia-less, or low inertia
renewable generation imposes a new complexity which will demand
consideration. Furthermore advanced protection techniques, such as impedance
measurement would be applied and compared with conventional methods.
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References (see below)
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Appendices
Appendix a. Two Area Network
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Appendix b. Frequency Measurement
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Appendix c. ROCOF Algorithm
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Appendix d. Vector Shift Algorithm
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Appendix e. Data Acquisition