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

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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

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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

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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

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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

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5. Conclusion ................................................................................................................ xxxviii

References (see below) ............................................................................................................ xli

Appendices ............................................................................................................................. xlii

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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

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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.

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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.

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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.

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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]

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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

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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

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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

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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.

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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

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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

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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

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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.

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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

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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

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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

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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)

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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

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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.

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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

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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.

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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

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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

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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

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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)

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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;

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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