Frequency Keeping Control Trial Technical Review Report

Frequency Keeping Control Trial

Technical Review Report

June 2015

Version Date Change

1.0 29/05/15 Draft for system operator review

Date

Prepared By: Mike Phethean

Darren Pat

Nabil Adam

John Bartley

Reviewed By: Dan Twigg 05/06/15

Andrew Gard 05/06/15

IMPORTANT

Disclaimer

The information in this document is provided in good-faith and represents the opinion of Transpower

New Zealand Limited, as the System Operator, at the date of publication. Transpower New Zealand

Limited does not make any representations, warranties or undertakings either express or implied, about

the accuracy or the completeness of the information provided. The act of making the information

available does not constitute any representation, warranty or undertaking, either express or implied.

This document does not, and is not intended to; create any legal obligation or duty on Transpower New

Zealand Limited. To the extent permitted by law, no liability (whether in negligence or other tort, by

contract, under statute or in equity) is accepted by Transpower New Zealand Limited by reason of, or in

connection with, any statement made in this document or by any actual or purported reliance on it by

any party. Transpower New Zealand Limited reserves all rights, in its absolute discretion, to alter any of

the information provided in this document.

Copyright

The concepts and information contained in this document are the property of Transpower New Zealand

Limited. Reproduction of this document in whole or in part without the written permission of Transpower

New Zealand.

Contact Details

Address: Transpower New Zealand Ltd

96 The Terrace

PO Box 1021

Wellington

New Zealand

Telephone: +64 4 495 7000

Fax: +64 4 498 2671

Email: [email protected]

Website: http://www.systemoperator.co.nz

mailto:[email protected]

SYSTEM OPERATOR REPORT: FREQUENCY KEEPING CONTROL TRIAL REPORT

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Contents Abbreviations ......................................................................................................................................... 5 Preface .................................................................................................................................................... 6 1. Executive Summary .................................................................................................................. 7 2. Introduction ................................................................................................................................ 8

Frequency Keeping Control ..................................................................................................... 8 2.1

The purpose of the FKC Trial .................................................................................................. 8 2.2

The purpose of this report ....................................................................................................... 8 2.3

The structure of this report ...................................................................................................... 9 2.4

3. Background .............................................................................................................................. 10 Normal frequency Requirements ........................................................................................... 10 3.1

Controls which vary HVDC transfer in response to frequency .............................................. 10 3.2

System dispatch .................................................................................................................... 11 3.3

Multiple frequency keeping .................................................................................................... 11 3.4

Round power control ............................................................................................................. 12 3.5

HVDC under frequency management ................................................................................... 12 3.6

Modulation risk ...................................................................................................................... 13 3.7

Reserve and frequency management programme ................................................................ 14 3.8

Security Tools Implementation for New HVDC Controls Project........................................... 14 3.9

4. Pre-FKC Trial findings ............................................................................................................. 16 Interaction of MFK and generator governors ......................................................................... 16 4.1

New purpose of MFK with FKC enabled ............................................................................... 16 4.2

Change to method of dispatch .............................................................................................. 17 4.3

Round Power under frequency risk management ................................................................. 17 4.4

Maximum HVDC transfer and FKC ....................................................................................... 18 4.5

FKC Trial start conditions ...................................................................................................... 18 4.6

Temporary manual operational procedures .......................................................................... 18 4.7

FKC Trial exit conditions ........................................................................................................ 19 4.8

Summary of possible modes of operation ............................................................................. 19 4.9

5. Benefits of FKC operation ...................................................................................................... 20 Reduced frequency keeping costs ........................................................................................ 20 5.1

Tighter control of normal frequency ....................................................................................... 21 5.2

Enables National Market for Instantaneous Reserves .......................................................... 21 5.3

Higher market capacity during energy shortfalls ................................................................... 22 5.4

6. FKC Trial technical issues with market impact .................................................................... 25 Increase in generator governor action ................................................................................... 25 6.1

Market cost of Modulation Risk ............................................................................................. 26 6.2

Appropriate quantities of frequency keeping ......................................................................... 27 6.3

Effectiveness of the MFK compliance calculation ................................................................. 29 6.4

Active power and reserve compliance with dispatch ............................................................. 30 6.5

7. FKC Trial Operational Issues ................................................................................................. 33 Automatic option no longer available for System dispatch .................................................... 33 7.1

Operational complexity of starting and stopping FKC operation ........................................... 33 7.2

Impact of HVDC Reclose Blocks on FKC operation ............................................................. 34 7.3

FKC exit conditions reassessed ............................................................................................ 34 7.4

8. Technical issues from the FKC trial ...................................................................................... 36 Frequency excursions during the trial ................................................................................... 36 8.1

Positive time error trend ........................................................................................................ 36 8.2

Time error separation between the North and South Islands................................................ 38 8.3

Causes of normal frequency band variations ........................................................................ 40 8.4

Back up frequency keeping ................................................................................................... 42 8.5

FKC performance during fast winter load pick ups ............................................................... 43 8.6

What is an appropriate normal frequency standard? ............................................................ 43 8.7


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9. Future developments with FKC operation ............................................................................ 44 Reduction in the modulation risk ........................................................................................... 44 9.1

Quantity of Frequency Keeping purchased ........................................................................... 45 9.2

Automatic Governor Control .................................................................................................. 45 9.3

System operator dispatch strategy ........................................................................................ 46 9.4

10. Conclusion & recommendations ........................................................................................... 47 Recommendations for the Authority ...................................................................................... 47 10.1

Recommendations for the SO ............................................................................................... 48 10.2

Appendix A – Frequency analysis ..................................................................................................... 49 Appendix B – Generator off-dispatch data ....................................................................................... 56

North Island – South Island Comparison ........................................................................................... 63 Calculation diagram ........................................................................................................................... 66

Appendix C – frequency excursion details ....................................................................................... 67 Appendix D – Positive time error trend ............................................................................................. 73 Appendix E - Using HVDC frequency offset from HMI to minimise time error divergence ......... 79


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ABBREVIATIONS

AGC – Automatic Governor Control

Authority - Electricity Authority

CAN – Customer Advice Notice

CE – Contingent Event

DCRS – DC Risk subtractor

ECE – Extended Contingent Event

EIPC – Electricity Industry Participation Code

FKC – Frequency Keeping Control

FIR – Fast Instantaneous Reserve

FSC – Frequency Stabiliser Control

GEN – Grid Emergency Notice

HMI – Human machine interface

ICCP – inter control centre protocol

IPS – Island power supply

MFK – Multiple Frequency Keeping

MOI – Market operator interface

MR – Modulation risk

MW - Megawatts

NCC – National Co-ordination Centre

NI – North Island

NRM – National reserves market

PI – Plant information

PMU – Phased Measurement Unit

PPOs – Principal Performance Obligations

PSD – Pre-solve deviation

RCBs – Reclose blocks

RFM – Reserve and Frequency Management

RIER – Regulation instruction error ratio

RMT – Reserve Management Tool

RP – Round power

RTD - Real Time Dispatch

SCADA – System Control and Data Acquisition

SI – South Island

SIR – Sustained Instantaneous Reserve

SO – system operator

SPD – Scheduling Pricing and Dispatch

SRS – Spinning Reserve Sharing

STLF – Short term load forecast


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PREFACE

This report provides a detailed account of the market, operational and technical

observations collected by the system operator during the recent FKC trial. Whilst some

background on the controls and market tools associated with the trial is provided, the

report is written primarily for readers already relatively familiar with these aspects of the

New Zealand electrical system.

The report makes recommendations, intended for consideration by the system operator

and the Electricity Authority, in respect of possible developments to enhance future

power system operations with FKC enabled. The recommendations are drawn from the

technical observations recorded during the trial and from feedback from market

participants. As these future developments are of wider interest this report is made

available to market participants.


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1. EXECUTIVE SUMMARY

A trial of an advanced operating mode of the HVDC link started in mid-October 2014 and

ran through to 31 March 2015. During this Frequency Keeping Control mode (FKC) trial

period operations were predominantly with reduced MFK frequency keeping bands.

During the trial tests were also conducted of different dispatch arrangements to ascertain

performance of FKC under a wide range of operating conditions. These included 0MW

MFK (no frequency keeper), and FKC with backup SFK (a single national frequency

keeper). These tests gave the system operator (SO) more confidence with FKC

operations. They also showed what could be achieved with further development of the

arrangements for frequency keeping to exploit this new technical capability of the HVDC.

Retaining FKC with reduced MFK frequency keeping bands following the trial will result in

a continuation of the immediate savings in total frequency keeping costs. If these

savings are sustained for the next year there will be a reduction of up to $25 million in

the cost of frequency keeping. The benefits are not just monetary; FKC provides

improvements to power system quality and security. It has been demonstrated there is

tighter overall management of frequency within the normal +-0.2Hz band with FKC

enabled. Similarly, FKC operation reduces the amount of generation required for

frequency keeping, releasing capacity that can, for instance, assist management of island

and national energy shortfall situations.

This report also details market, operational and technical issues identified with FKC

operation. Generally there has been an increase in generator governor action. This

action has effects on generator plant and operating regimes and also impacts energy and

reserve dispatch compliance. Operationally, FKC can be challenging with the current

market system tools. This was apparent during live line work on the HVDC conductors.

Technical issues relating to the interaction of managing system frequency and

maintaining time error were observed during the trial.

Importantly, the SO has found no adverse impact on its ability to meet the combination

of objectives for delivering a secure power system with the required power quality (the

PPOs) during FKC operations throughout the FKC trial period.

Whilst none of the identified issues prevent continued FKC operation this report includes

recommendations to mitigate their effects. The recommendations also suggest further

areas of study, testing and development for the both the system operator and the

Electricity Authority (Authority).

The SO will continue to work with the Authority and industry on development of

frequency keeping arrangements as part of the wider Reserves and Frequency

Management (RFM) development programme.


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2. INTRODUCTION

FREQUENCY KEEPING CONTROL 2.1

The controls upgrade delivered as part of Transpower’s HVDC Pole 3 project included a

control system with an operating mode known as Frequency Keeping Control (FKC). FKC

varies the transfer on the HVDC to maintain the same system frequency in both islands.

It is an enabler for a potential national Frequency Keeping service to replace the use of

island based Frequency Keeping.

Introduction of this operating mode led to changes in power system operations and

methods of regulating system frequency.

System testing with FKC enabled (during and post HVDC commissioning) resolved some

initial issues discovered while operating with FKC, though uncertainties still existed. 1

The uncertainties were focused on:

the ability of the proposed method for FKC operation to maintain stable operation

at times of very light system load

the statistical significance of trends observed during the system testing. System

variations can mask trends even on data collected over a full day of operation

whether system testing had revealed all the technical and operational issues that

may exist when operating with FKC enabled.

FKC was placed into operation for a trial period from the 16th October 2014 through to

the 31st March 2015 to evaluate these issues further.

THE PURPOSE OF THE FKC TRIAL 2.2

The purpose of the FKC trial was to operate with FKC enabled for a longer duration so as

to:

collect additional data through a wider range of system conditions, allowing a full

assessment of FKC modulation risk and frequency keeping bands to be completed

allow the SO and the electricity industry an opportunity to gain operational

experience with FKC enabled.

THE PURPOSE OF THIS REPORT 2.3

This report:

provides an introduction to the key system aspects which influence or are

influenced by FKC

provides a summary of the findings from the pre-trial testing with FKC enabled

details the methods of operation with FKC enabled

provides a high level analysis of some market benefits of operating with FKC

enabled

identifies issues operating with FKC enabled and, where possible, make

recommendations to mitigate these issues

1 The FKC control had undergone initial testing, see pre-trial details in section 4


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recommends how continued operation with FKC enabled can be enhanced

discusses future changes which may occur with FKC enabled operations.

THE STRUCTURE OF THIS REPORT 2.4

This report is divided into a number of sections as follows:

Section Section

No.

Purpose

Background 3.0 An introduction to the components of the electricity

market and the technical controls relevant to this report.

Pre-FKC trial findings 4.0 A summary of findings of the tests and investigations

carried out before the FKC trial began.

Benefits of FKC

operation

5.0 A description of benefits which have come from FKC

operation.

FKC technical issues

with market impact

6.0 A description of issues for market participants and for the

market tools from FKC being enabled.

FKC Trial operational

issues

7.0 A description of issues for system coordinators in

operating with FKC being enabled.

Technical issues from

the FKC Trial

8.0 A description of the engineering issues from FKC being

enabled.

Future development

with FKC operation

9.0 A description of possible developments associated with

FKC which may occur in the near future. The

developments may be market based, technical or

operational.

Recommendations

and conclusions

10.0 Recommendations made in sections 6 – 9 of this report

are denoted by a box. A summary of all recommendations

is in section 10.


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3. BACKGROUND

NORMAL FREQUENCY REQUIREMENTS 3.1

The EIPC requires normal system frequency be maintained in a band from 49.8 Hz to

50.2 Hz.

Under the EIPC part 7.2 the principal performance obligations of the system operator

are:-

b(i) … to act as a reasonable and prudent system operator with the objective of

maintaining frequency in the normal band…

(v) to act as a reasonable and prudent system operator with the objective of ensuring

that frequency time error is not greater than 5 seconds of New Zealand standard time;

also mandates that frequency time error is maintained between +/- 5 seconds.

To maintain the frequency within the normal band (within +/- 0.2Hz of the nominal

50Hz) the system operator purchases frequency keeping services.

CONTROLS WHICH VARY HVDC TRANSFER IN RESPONSE TO 3.2

FREQUENCY

The controls upgrade delivered by Transpower’s HVDC Pole 3 project included two modes

of frequency control:

1) Frequency Stabiliser Control (FSC) and Spinning Reserve Sharing (SRS) – that

operated together and were as part of the HVDC frequency control used pre

upgrade.

2) Frequency Keeping Control (FKC) – A new separate enhanced operating mode

that includes some of the functionality of FSC/SRS developed for managing

national frequency.

These control modes both measure frequency at Haywards and Benmore and use the

difference to calculate changes in the HVDC transfer.

The combined operation of FSC/SRS varies HVDC power transfer to assist in supporting

frequency when there is a difference in frequency between the two islands. FSC/SRS is

designed to change HVDC power transfer for about 30 seconds before the power transfer

returns to its dispatch value.

SRS has a slow but permanent reaction to frequency changes in either one or both

islands. SRS gradually increases the amount it changes the HVDC power transfer, as the

frequency stabiliser dies away, until either the frequency in both islands is restored to

within the range of 49.8 Hz to 50.2 Hz or the output of the controller reaches its limit.

FKC continuously varies the HVDC power transfer to maintain the same frequency in the

North and South islands. An implication of FKC’s continuous action is more variation in

the HVDC transfer than FSC/SRS.


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SYSTEM DISPATCH 3.3

One of the core duties of NCC system co-ordinators is to dispatch active power to

generators to balance the load on the power system.

Two key performance measures of this active power and load balancing are system

frequency and time error.

A high system frequency (greater than 50 Hz) indicates more generation is dispatched

than load. A low system frequency (less than 50 Hz) indicates less generation is

dispatched than load. Time error is a cumulative summation of the deviation of

frequency from 50 Hz.

System co-ordinators formulate dispatch instructions by taking into account:

system frequency and time error

current load

future industrial and residential load movements

the quantity of active power the frequency keeper has varied to maintain system

frequency and time error

generator compliance with previous dispatch instructions.

MULTIPLE FREQUENCY KEEPING 3.4

The Multiple Frequency Keeping (MFK) control system was implemented in the North

Island in 2013 and in the South Island in 2014. The purpose of MFK is to reduce

frequency keeping costs by allowing multiple parties to simultaneously contribute to

managing frequency and time error.

MFK control is based on the Automatic Governor Control (AGC) control philosophy. A

central controller calculates the variation in the power supply required to maintain

frequency and time error within the mandated targets. A central controller ensures

providers contribute equally and stably to frequency keeping.

Generators tender capacity offers into the market to provide the MFK service. The

market system selects the most economical generators to provide MFK services. These

generators then provide the required quantity of frequency keeping.

3.4.1

The MFK controller communicates the variation in power supply to the local generation

station control module. The station control module then sends a signal to the generator

governors. This communication path differs to an AGC system which sends the signal

directly from the MFK controller to the generator governor.

The MFK communication paths cause a significant time delay in reactions to changes in

system frequency and time error (compared to an AGC system). This time delay

introduces latency into the reaction of MFK to frequency variations.

3.4.2

The speed at which MFK can vary the power supply is limited to 0.4 MW / min for every 1

MW of MFK capacity purchased. This means that if 10 MW of capacity is dispatched to a

MFK generator, its power supply can be varied at a maximum of 4 MW / min.


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In an AGC system the governor can normally vary the power supply at a higher rate than

MFK.

3.4.3

To ensure the MFK controller provides a stable response to frequency, low gain factors

are applied to the error signal. More focus is given to the cumulative size of the error.

The latency of MFK to frequency changes and relatively slow speed of variation in power

supply require a highly damped control response.

ROUND POWER CONTROL 3.5

Round power (RP) control allows the HVDC to transit from north to south transfer and

vice versa almost seamlessly.

Prior to introduction of RP the HVDC could not be dispatched below 35 MW for transfer in

either direction as the HVDC convertor poles have a minimum transfer level of

approximately 35 MW.

RP allows the HVDC to be dispatched below this minimum by starting the second HVDC

convertor pole in the opposite direction to the HVDC convertor pole already in service.

The overall power transferred is then the transfer of one convertor pole minus the

transfer on the other convertor pole.

Another feature of RP is that it will automatically start a HVDC convertor pole to cover

the loss of transfer if the first HVDC convertor pole trips.

3.5.1

When in RP control there are three technical requirements relevant to modelling system

frequency risks:

the subsea cable must have residual current discharged for five minutes before

the convertor pole can be started in the opposite direction. This prevents a

convertor pole being immediately available to transfer power in the opposite

direction

when the poles are transferring in opposite directions and one HVDC convertor

pole trips the other convertor pole does not trip but stays connected at the

minimum transfer of 35 MW. The loss of supply to the island receiving the HVDC

transfer is therefore the dispatch plus 35 MW.

HVDC UNDER FREQUENCY MANAGEMENT 3.6

3.6.1

The system operator considers two event types as under frequency system risks:

Contingent Events (CE). Events where the impact, probability of occurrence and

estimated cost and benefits are considered to justify implementing policies to be

included into the scheduling and dispatch processes pre-event.

Extended Contingent Events (ECE). Events for which the impact, probability of

occurrence and estimated cost and benefits are not considered to justify the

controls required to totally avoid demand shedding and maintain the quality limits


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defined for contingent events. For under frequency events demand shedding

includes Automatic Under Frequency Load Shedding (AUFLS).

3.6.2

The system operator has two HVDC under frequency risks:

1. HVDC CE risk. – The loss of one HVDC component. The HVDC component that is

usually the largest (critical) risk is the loss of a single HVDC convertor pole.

2. HVDC ECE risk – The loss of both HVDC convertor poles.

The HVDC is dispatched in terms of the power sent, as this is the value entered into the

HVDC controls. However the risk is to the island receiving the HVDC transfer if part or

all of the HVDC trips.

3.6.3

The DC risk subtractor (DCRS) is the maximum transfer value the HVDC can sustain for

15 minutes following the loss of the most critical HVDC component E.g. Pole, HVDC filter,

statcom etc.

For example, if the HVDC is fully available the loss of Pole 3 is the most critical

component. The remaining Pole 2 can send up to 560 MW for 15 minutes. In the

receiving island this will equate to 528 MW of received HVDC transfer. The risk subtractor

is therefore 528 MW.

3.6.4

The HVDC risk formulae are:

HVDC CE risk = HVDC received – DCRS

HVDC ECE risk = HVDC received.

MODULATION RISK 3.7

The system operator is required to provide sufficient under frequency reserve to cover

the loss of the HVDC.

When FKC is enabled it was noted the average difference between actual HVDC transfer

and the dispatched HVDC had increased compared to when only FSC/SRS control was in

operation.

This increase was to be expected as FKC fully matches the system frequencies between

the two islands whereas FSC/SRS only partially matches the frequencies.

This presented a risk to the way the system operator managed under frequency reserve

purchases. With FKC in operation, the actual magnitude of the loss of supply to the

system had a greater probability of being higher than the dispatched quantity.

To allow for the increase the system operator added a fixed quantity to the HVDC

reserve risk. This fixed quantity is called the Modulation Risk (MR). 2

The HVDC risk formula therefore becomes:

2 The loss of supply is now the dispatched HVDC transfer and the increase that FKC requires to control

frequency.


14

HVDC CE risk = HVDC received – DCRS + MR

HVDC ECE risk = HVDC received + MR

Management of the MR value during the FKC trial was via manual processes using the

Market Operator Interface (MOI) HVDC display. This risk was modelled in both forward

looking schedules and the real time dispatch schedule.

RESERVE AND FREQUENCY MANAGEMENT PROGRAMME 3.8

The Reserves and Frequency Management (RFM) programme is a joint programme of

work between the SO and the Electricity Authority (Authority) to improve frequency

keeping and instantaneous reserve market arrangements given recent enhancements

available from the HVDC control system.

FKC is one of the key enhancements and its successful operation is critical to a number

of RFM projects.

The HVDC control enhancements enable the transfer of frequency keeping and reserves

between islands. This has culminated in a number of proposed capital projects.

The programme currently contains nine projects3 to contribute to this objective:

South Island MFK

RMT TSAT Implementation and RMT Re-Development

Inter-island Instantaneous Reserve Sharing: Implementation FIR & SIR

Normal Frequency Management Strategy

Quantity of Frequency Keeping Procured by Island under Frequency Keeping

Control

Security Tools Implementation for New HVDC Controls (Security Tools Project)

National Market for Instantaneous Reserve

National Market for Frequency Keeping

Under Frequency Management (Efficient Procurement of Extended Reserves

Implementation and Review of Instantaneous Reserves Markets).

SECURITY TOOLS IMPLEMENTATION FOR NEW HVDC CONTROLS 3.9

PROJECT

The project from the RFM programme having the greatest effect on the operation of the

system with FKC enabled is the Security Tools Project.

The Security Tools Project is delivering:

market system tools to automate current manual processes associated with RP

and FKC operation

new and modified market system and SCADA displays to facilitate greater

situational awareness for NCC system co-ordinators

training and process documentation for system co-ordinators.

3 Further information on these work streams can be found at:

http://www.systemoperator.co.nz/activites/current-projects/reserves-and-frequency-management-rfm-

programme.

http://www.systemoperator.co.nz/activites/current-projects/reserves-and-frequency-management-rfm-programme

http://www.systemoperator.co.nz/activites/current-projects/reserves-and-frequency-management-rfm-programme


15

The market system tool changes are being driven by the need to efficiently operate the

FKC and RP functionality. The current manual processes are error prone and create

undesirable distraction from general operation of the electricity system. The project

design incorporates some of the findings from the pre-trial FKC testing.

The market system tool changes include improvements to the dispatch process include

the following new functionality:

dispatch algorithm inputs update. The algorithm in future will include, a

proportion of the difference between the HVDC transfer and the HVDC dispatch

set point and a time error factor

enhanced charts including generator governor response and HVDC off dispatch

trending (improving situational awareness)

This project is referenced further in this report as it provides some mitigations to issues

identified in both sections 7 and 8.


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4. PRE-FKC TRIAL FINDINGS

The findings from the system tests carried out on FKC during HVDC commissioning, prior

to the FKC trial, are documented in the report “FKC Trial – Pre Trial Approval Technical

Report.”4

A number of key points from this report are highlighted in the sections below. These key

findings were used to define the parameters for the FKC trial.

INTERACTION OF MFK AND GENERATOR GOVERNORS 4.1

System tests carried out with FKC enabled showed an opposing interaction between MFK

and generators with active governor control.

Most generator governors have two control elements which apportion response to correct

a frequency error:

1. proportional control – this increases or decreases power output depending on the

magnitude of the frequency deviation from the target frequency of 50 Hz.

2. integral control – this increases or decreases power output depending on the sum

over time of the frequency deviations from the target frequency of 50 Hz.

The integral control element provides damping to the governor response to ensure its

response is stable.

The difference between MFK and the governor control is that MFK corrects time error.

MFK control effectively adjusts its target frequency away from 50 Hz. Governor control

currently cannot adjust its target frequency.

Different target frequencies can cause MFK to respond in the opposite direction to the

generator governors. This causes the HVDC to be unnecessarily off dispatch as MFK in

the North Island is opposed by generator governor response in the South Island.

NEW PURPOSE OF MFK WITH FKC ENABLED 4.2

The MFK control has the same proportional and integral control elements as a generator

governor. Due to the latency in MFK (see section 3.4.1) governor control acts more

quickly to correct frequency changes. The generator governors therefore produce most

of the variation in active power required to correct frequency.

The latency in MFK varying active power output could on occasions cause an overreaction

to a frequency change. To manage this over reaction the proportional element of the

MFK control was effectively removed and MFK effectively became a mechanism to correct

time error.

A feature of MFK control is that in addition to the time error controls making an

automatic adjustment to the target frequency, a manual adjustment to the target

4 The report can be found at:

https://www.systemoperator.co.nz/sites/default/files/bulk-upload/documents/FKC%20Trial%20Report.pdf




17

frequency can also be made by the system co-ordinators. This manual adjustment is

used as a somewhat forceful control to ensure MFK acts to correct time error.

In short, MFK with FKC enabled was no longer being used to correct frequency; MFK was

solely correcting time error.

4.2.1

The change in use of MFK meant less frequency keeping capacity was required from MFK

generators. A number of different quantities were tested and it was concluded that

across both North and South Islands a capacity of 30 MW was required.

CHANGE TO METHOD OF DISPATCH 4.3

Prior to FKC operation for approximately fifty percent of the time new dispatch quantities

were calculated and dispatched using a SO automated dispatch tool.

Enabling FKC changed the way the power system behaved and ‘felt’ from a system co-

ordinator’s dispatch perspective. The variables taken into account by the system co-

ordinator in calculating the new dispatch quantity had changed. Two new variables were

now used:

HVDC off dispatch. The difference between the actual HVDC transfer and it’s

dispatched transfer

responsive generators off dispatch. The sum of the differences between actual

generator active power and generator dispatched active power.

These variables replaced the previous variable of “the quantity of active power the

frequency keeper has varied to maintain system frequency and time error.’

The existing market systems automated dispatch tool was not designed for these new

input variables. Therefore when FKC control is in operation system co-ordinators are

required to always calculate the new dispatch quantity manually.

ROUND POWER UNDER FREQUENCY RISK MANAGEMENT 4.4

When RP is in operation the additional risk issues identified in section 3.5.1 are

managed, where necessary, by use of manual processes. These processes are:

applied only to real time dispatch and do not appear in the schedules published to

the market

a simplified representation of RP.

While operating in RP mode the HVDC controls automatically select the appropriate pole

configuration for a given transfer, regardless of the dispatch set point.

It is not practical for system co-ordinators to manually update the market system

modelling of the pole configurations during the various states of RP operation.

System co-ordinators follow a simplified modelling process to ensure adequate reserves

are dispatched when the HVDC is dispatched by the market system through zero.

When HVDC transfer is ordered below 100 MW in either direction, system co-ordinators

are alerted via an alarm to adjust the market system HVDC to ‘round power mode’.

‘Round power mode’ sets the DCRS to zero to reflect the HVDC’s possible inability to

‘self-cover’ in the event of the loss of one of the HVDC convertor poles. The Security


18

Tools Project will model round power more comprehensively, reducing onerous manual

processes.

MAXIMUM HVDC TRANSFER AND FKC 4.5

FKC cannot increase HVDC transfer beyond the HVDC power limits. These limits are

dynamic but have a maximum of 1200 MW for HVDC north transfer and 850 MW for

HVDC south transfer. In addition, the limits change depending on the HVDC and AC

equipment offered and Wellington load.

Before the trial began, it was agreed FKC would be disabled when HVDC transfer reached

a value close to the HVDC power limit. Alarms were set-up to alert system co-ordinators.

The HVDC transfer level at which FKC is disabled also takes into account the modulation

risk and the reserve sharing in RMT as neither of these values are accounted for in the

current market system. The table below details when the alarm annunciates:

Table 1 Alarm Annunciation

Alarm Type Transfer at which alarm annunciates (X = HVDC Power Limit)

Warning X – MR – Reserve Sharing – 40 = X -130

Action X - MR – Reserve Sharing = X – 90

The warning alarm informs system co-ordinators HVDC transfer is close to where FKC will

need to be disabled. The action alarm annunciates FKC must be disabled.

System co-ordinators cannot practicably disable FKC frequently as it requires an onerous

manual process to be completed. Therefore, on receipt of the limit alarm, a system co-

ordinator will assess the non-response schedules to identify when FKC is next scheduled

under the limit for an extended period of time; the identified time will provide confidence

FKC can be re-enabled and will be the target time notified to participants when FKC

operations will be reinstated.

FKC TRIAL START CONDITIONS 4.6

Following acceptance of Pre-Trial Approval Technical Report, the FKC Trial commenced

with the following conditions:

MR = 40 MW

North Island MFK band = 20 MW

South Island MFK band = 10 MW

MFK operating in single frequency source mode

suitable temporary manual operational procedures developed and implemented.

TEMPORARY MANUAL OPERATIONAL PROCEDURES 4.7

Temporary manual operational procedures were implemented to manage the trial prior to

any SO tool changes being made. The manual processes managed the change to

dispatch, MR and RP modelling issues discussed in section 3.7 and 4.4.


19

Tool changes are being made as part of the Security Tools Project, expected to be

delivered September 2015.

FKC TRIAL EXIT CONDITIONS 4.8

During the trial period a set of trial exit conditions were established. The trial was to be

stopped and FKC disabled when or for:

time error in either island exceeded 3.5s

loss of communications occurred between MFK controller and generator local

control systems (inter control centre protocol or ICCP)

high HVDC transfer north or south (HVDC power limit less margin) occurred

security constraint violations and/or contingency violations

bipole outage or trip occurred

monopole outage or trip occurred

RP was unavailable

system security issue identified or major system event occurred.

SUMMARY OF POSSIBLE MODES OF OPERATION 4.9

To assist the reader Figure 1 below shows the various modes of operation for HVDC

frequency controls. Some of the modes will be described in later sections. (The MR is set

to 30 MW the current value.)

Figure 1- Summary of HVDC Frequency Control operational conditions

InputsHVDC Frequency

ControlFrequency Keeper Type Market Tool Settings

Au

to

Dis

patc

h

Po

ssib

le

NI F

K

SI F

K

MR

MF

KS

FK

MF

KS

FK

Is Pole 2 and Pole 3

Available?

Is Round Power

enabled?

YesIs the DC near the power limits?

Yes Run in FKC Mode

No

Run in FSC Mode

Normal

Grid Emergency SI

Grid Emergency NI

North Island

South Island

Y

N

N

N

N

N

Y

20

0

30

50

0

50

50

10

30

0

0

25

25

25

30

30

30

30

30

0

0

No No

Yes


20

5. BENEFITS OF FKC OPERATION

REDUCED FREQUENCY KEEPING COSTS 5.1

FKC operations during the trial allowed reductions in the quantity of frequency keeping

purchased, from 75 MW to 30 MW. Although the trial commenced on October 16th 2014

FKC was only periodically available in November and December due to equipment and

plant outages associated with the HVDC.

The first full month of continuous FKC trial operation with reduced frequency keeping

quantities purchased was January 2015.

Figure 2, shows how frequency keeping costs have reduced during the period of

sustained, FKC trial operations. The graph shows the last 24 months of frequency

keeping costs. The last three months (in green) represent the first three continuous

months of a lower quantity of frequency keeping being purchased. If the trend continues

approximate market savings of approximately $25 million per annum may be realised.

An important caution is that frequency keeping duties have effectively been transferred

to generators with governors active in the normal band. Reduced frequency keeping

payments have not accounted for any additional cost incurred by the generators for this

apparent transfer of duty. See section 6.1 for a more detailed analysis of this issue.

Figure 2 Frequency Keeping Costs

0

1

2

3

4

5

6

7

Mo

nth

ly F

req

ue

ncy

Ke

ep

ing

Co

sts

($ M

illio

ns)

Time (months)

Frequency Keeping Costs

FSC enabled

FKC enabled partially

FKC enabled


21

TIGHTER CONTROL OF NORMAL FREQUENCY 5.2

The analysis in Appendix A shows that with FKC enabled overall frequency deviation

across New Zealand decreased. In the North Island there has been a significant

decrease in frequency deviation. In the South Island there has been a slight increase in

frequency deviation.

North Island frequency historically tended to have more deviations from 50 Hz than

South Island frequency, for the following reasons:

South Island generation is mostly hydro, where governors are normally quick to

respond to fluctuations in frequency

North Island generation has a lot of thermal, gas and geothermal units which

often have dead bands across the normal frequency keeping range

in the North Island, an industrial load site creates large variations in frequency

through its unpredictable load usage.

Once the two islands are tied together through FKC the experience is clear that

frequency deviation reduces for the North Island but increases slightly for the South

Island. Overall frequency deviations across New Zealand have decreased.

ENABLES NATIONAL MARKET FOR INSTANTANEOUS RESERVES 5.3

As part of the RFM programme a National Instantaneous Reserves Market (NIRM) is

planned for implementation in 2017.

Currently under frequency reserves are purchased on an island basis. A conservative

increase (60 MW) of HVDC transfer is assumed to come from the HVDC frequency

controls for the calculation of FIR. No increase in HVDC transfer is assumed in the

calculation of SIR.

The ability of FKC control to match the two island frequencies means SIR will now be

transferred via the HVDC from one island to the other island when an under frequency

event occurs. The SRS control on the previous HVDC control system would allow an

amount of SIR to be transferred but the levels were smaller and inconsistent.

The FKC control therefore enables reserves for AC system risks to be purchased in either

island. This could lead to a significant reduction in the overall quantity of reserve

purchased as presented below in Table 2.5

5 Table 2 assumes the largest North Island risk to be one of the three large gas fired power stations. These

stations are assumed to run at minimum output overnight. RMT currently uses a simplified representation of

the HVDC response. This response would be more accurately modelled after a national reserves market is

implemented which would lead to a reduction in the FIR required.

Currently SIR is purchased for the AC risk in each island. A national reserves market will also allow the sharing of SIR for AC risks across both islands.


22

Table 2 Reserve Quantities Purchased with FKC Enabled

Daytime

(current)

Overnight

(current)

Daytime

(future)

Overnight

(future)

NI AC risk (MW) 380 240 380 240

NI AC FIR (MW) 240 140 140 70

NI AC SIR (MW) 380 240 200 140

SI AC risk (MW) 125 125 125 125

SI AC FIR (MW) 30 45 110 100

SI AC SIR (MW) 125 125 180 100

FIR Reduction (MW

/ %)

20 MW / 7% 15 MW / 8%

SIR Reduction (MW

/ %)

125 MW / 24% 125 MW / 34%

The NIRM could reduce the purchase cost of reserves not only by reducing quantities of

reserves but also by allowing South Island reserves to be sold in the North Island and

vice versa. Given the surplus of generation reserves in the South Island this is expected

to reduce the cost of purchasing under frequency reserves.6

As an interim measure the Inter-Island Reserve Sharing project, also part of the RFM

programme, will share SIR between the two islands when FKC is enabled, in a similar

manner to how FIR7 is already shared. This minor change to the market system is

scheduled to be completed in September 2015.

Both the NIRM and the Inter-Island Reserve Sharing project therefore require FKC to be

enabled to function. Without FKC expected benefits cannot be realised.

HIGHER MARKET CAPACITY DURING ENERGY SHORTFALLS 5.4

5.4.1

A single island energy shortfall occurs when:

there is high system demand

there are insufficient energy and reserve offers to supply the energy and reserve

requirements in either the North or South Island.

A shortfall will cause high prices and may have a significant effect on consumers of

electricity and those exposed contractually to electricity market spot prices.

A shortfall will usually mean HVDC transfer is limited to the amount of reserve available

to cover the HVDC transfer. The FKC MR will cause the HVDC transfer to limit at a lower

value than if FKC was not in operation.

6 http://www.ea.govt.nz/dmsdocument/3574 7 Up to 60 MW of increased HVDC transfer is assumed when modelling FIR.


23

Under grid emergency the SO may purchase all system frequency keeping requirements

from the island without the shortfall, thereby increasing capacity in the island with the

shortfall.

Inter-island reserve sharing8, only available when FKC is enabled, will increase the

quantity of SIR available to cover AC risks in the island with a shortfall.

When there is a capacity shortfall in the North Island the larger AC risk setting plant

often have outputs significantly constrained to below full offered capability as there is

insufficient SIR to cover the under frequency risk of the full offered capability. Inter-

island reserve sharing will therefore allow increases of scheduled output of larger AC

risks during capacity shortfalls as more SIR is available.

An example for the North Island of what this means and how it increases capacity is

given below in Table 3.

Table 3 NI Capacity change with FKC enabled

Change in capacity due to

being FKC enabled (MW)

MR = 30 MW, limits HVDC transfer -30

Frequency keeping now 20 MW was 50 MW +30

Total under normal circumstances 0

Frequency keeping now 0 MW +20

Total under a grid emergency +20

Change due to inter island reserve sharing (assuming

two large risks and 60 MW SIR sharing)*

+120

Total under a grid emergency and inter island reserve

sharing

+140

* Assumes the SIR is the limiting risk which is typical and that two of the three large

(greater than 300 MW in capacity) generators are available.

Table 3 shows that with FKC control enabled there is more capacity available for single

island shortfalls.

8 Due for implementation by the end of 2015.


24

5.4.2

If there is a capacity shortfall in both islands then frequency keeping is purchased

normally. An example of a capacity shortfall across both islands is given below in Table

4.

Table 4 Capacity change with FKC enabled

Change in capacity due to

being FKC enabled (MW)

MR = 30 MW, limits DC transfer -30

Frequency keeping now 30 MW was 75 MW +45

Total under normal circumstances +15

Change due to inter island reserve sharing (assuming

two large risks and 60 MW SIR sharing)*

+120

Total under a grid emergency and inter island reserve

sharing

+135

* Assumes the SIR is the limiting risk which is typical and that two of the three CCGT’s

are available.

Table 4 shows that with FKC control enabled there is more capacity available when the

capacity shortfall is in both islands.


25

6. FKC TRIAL TECHNICAL ISSUES WITH MARKET

IMPACT

INCREASE IN GENERATOR GOVERNOR ACTION 6.1

Introduction of MFK increased the quantity of response expected from generator

governors to manage normal frequency. The use of FKC has further increased the

quantity of response expected from generator governors (see section 4.1 and Appendix

B).

Section 4.1 discusses the effect FKC has on frequency behaviour in the normal band

which the governor response is related to. FKC essentially shares the governor reaction

to frequency deviation across both islands.

Without FKC we know that despite having more system inertia the North Island has

larger deviations in frequency in the normal band than the South Island (see Appendix

A). With FKC enabled these North Island larger deviations are shared across the whole

system. This in turn leads to South Island governors being more off dispatch with FKC

enabled than with FKC disabled. The opposite is true for the North Island. Details are in

Appendix B.

Market participants have commented that increased generator governor action is

regarded as undesirable for various reasons including the following:

revenue may be affected as owners may be paid slightly more or less than their

cleared offer. It may also leave a generator exposed on a contract position

higher generation may come with a higher fuel cost

the governor action may cause the generator to move into an operating range

where mechanical vibrations can be higher

the constant fluctuation of output power from the governor can cause additional

wear on the generators with some generators more susceptible to this than others

generators may have to consider an inadvertent breach of relevant resource

consents, especially with minimum flows

a generator may increase its Historical Annual Maximum Injection quantity. This

will increase its transmission charges.

Market participants have also raised concern there is no market mechanism to directly

reflect the costs of increased governor action.

6.1.1

To avoid increased governor costs generators have the ability to implement a dead band

into their governor controls. The dead band usually prevents any governor response to

frequency movement in the normal band. There is currently no EIPC requirement on

whether or not generators should have dead bands.

A high proportion of North Island generators already have such dead bands

implemented. When the HVDC frequency controls are not in operation the consequent

lack of generation response leads to poor frequency control in the North Island within the

normal frequency band.

Market participants have commented they may fit a dead band to more of the remaining

generators governor controls. If this occurred it might lead to a material drop in the


26

quality of frequency control in the normal frequency range. In turn this might require

the purchase of extra under and over frequency reserves and a return to a frequency

keeping service with a significantly larger band.

One participant has suggested the proportion of frequency keeping purchased from each

island could be set to align more with the governor response provided by each island’s

generators. The participant suggested this alignment could be used as an interim

measure to compensate for generator governor action.

Recommendation 1 – The consequences of increased governor response should be

considered in a market context given the operational reliance now placed by SO on that

action during FKC operations.

MARKET COST OF MODULATION RISK 6.2

Market participants have raised concerns about two possible costs from the FKC MR:

a decrease in capacity leading to higher costs in times of capacity shortfall

an increase in market costs associated with HVDC reserve requirements.

6.2.1

The complexities of this subject have led to some confusion and therefore a perception

that capacity has decreased with FKC operation.

Section 5.4 details that there is actually a significant increase in capacity during energy

shortfalls when in FKC operation. Hence, no increased costs can arise during energy

shortfalls during FKC operations.

6.2.2

6.2.2.1 Increase in reserve quantities

The MR increases the size of the HVDC under frequency reserve risk. This means there

are more occasions when the HVDC becomes the binding market risk. A binding risk is

the risk requiring the largest quantity of reserves to be purchased.

The extra quantities of reserves result in an increase in cost to those participants who

are obliged to pay for the HVDC.

6.2.2.2 Increase in price separation between the two islands

When the HVDC risk becomes the binding risk in the market system the market

optimisation engine, Scheduling Pricing and Dispatch (SPD), co-optimises the cost of

additional energy and risk. Practically this means:

Price of additional HVDC transfer = Price of energy in sending island + Price of reserve in

the receiving island.


27

The price of reserve therefore increases the price difference between the two islands.

This affects participants in the sending island as they get less for their generation and it

may affect their market trading positions.

The MR lowers the point at which price separation occurs and therefore increases cost to

market participants.

6.2.3

A number of ideas have been generated by both the SO and participants to alleviate

additional costs from the MR. These ideas are:

1) Redesign SPD so it co-optimises the use of FKC, balancing additional market costs

with savings made from reduced frequency keeping and reserves.

2) Turn off FKC when the HVDC reaches a certain level of transfer.

3) Buy a fourth cable for the HVDC to increase the single convertor pole overload

capability from currently 560 MW to 1000 MW.

No study of the technical or economic feasibility of ideas 1 and 2 has been commenced.

Recommendation 2: Study the feasibility of a market solution which could determine

when it is economically efficient to enable FKC.

APPROPRIATE QUANTITIES OF FREQUENCY KEEPING 6.3

6.3.1

As described in section 4.2 when FKC control is in operation MFK is effectively only

managing time error control. This has shown a lower quantity of frequency keeping was

required during FKC enabled operations.

From the commissioning FKC tests an initial frequency keeping figure of 30 MW was

selected for FKC operations. Time was allocated during the FKC trial for more extensive

tests with different quantities of MFK dispatched. Extensive tests were required as the

data being monitored during these tests could vary randomly from day to day. To draw

an accurate conclusion from the test sufficient data was required to eliminate these

random variations.

During the trial period tests were carried out with no MFK control (i.e. 0 MW) for three

weeks to measure the effects of the absence of MFK on the system. In all the tests the

frequency PPOs were always maintained.

The tests demonstrated a number of points:

overall frequency deviations with FKC enabled and 0 MW of MFK dispatched were

lower than when FSC/SRS was enabled and 75 MW of MFK dispatched (the normal

mode of operation before FKC operations were commenced). The deviations with

0 MW of MFK dispatched and FKC enabled were worse than with 30 MW of MFK

dispatched and FKC enabled. See Appendix A for details

time error deviation increased with FKC enabled and 0 MW of MFK dispatched.

Time error was still easily within the EIPC PPO limits. See Appendix A for details


28

the HVDC was off dispatch more with 0 MW of MFK dispatched than with 30 MW

of MFK dispatched

generator units with governor action were more off dispatch with 0 MW of MFK

dispatched than with 30 MW of MFK dispatched. See Appendix B for details.

The graph below shows how much the HVDC was off dispatch during the tests with 0 MW

of MFK dispatched. Weeks 2, 4 and 5 are the weeks with 0 MW of MFK dispatched. The

graphs show the HVDC was more off dispatch with 0 MW of MFK dispatched than with 30

MW of MFK dispatched. Week 5 shows that as system co-ordinators became more

familiar with dispatching in this scenario results improved.

Figure 3 - HVDC off dispatch quantities

As detailed in section 4.2 MFK is primarily used to correct time error. The test with

0 MW of MFK dispatched showed dispatch can be used to correct time error. The

problem with this approach is the increased number of manual calculated dispatches

required encroaches on the time system co-ordinators spend on other system and

market issues.

Figure 3 shows how dispatches generally increased across a week of operation. Overall

dispatches increased by 6%.

The SO is implementing the Security Tools Project which may enable elements of the

dispatch process to include more automation when FKC is enabled. More automated

dispatch will reduce the time system co-ordinators spend on calculating new dispatch

quantities. Some system tests will be required to confirm the effectiveness of the

changes in the market system tools. There is further discussion on automating manual

dispatch actions in section 7.1.

Additional market and operational issues need also to be addressed before further future

changes to frequency keeping quantities are considered. These are in section 9.2.

0

20

40

60

80

100

120

140

160

180

1 2 3 4 5 6

Min

ute

s th

e H

VD

C w

as o

ff d

isp

atch

Week

HVDC off dispatch Comparison

>50 MW

>60 MW


29

Figure 4 - Increase in dispatches with MFK = 0 MW

6.3.2

With FKC control enabled there is technically no limitation on which island frequency

keeping services are purchased from.

The current market system arrangements procure frequency keeping services to fulfill a

fixed quantity required per island. The quantities of frequency keeping per island were

set at the beginning of the trial based on a ratio of the frequency keeping normally

procured when FKC control is inactive, as follows:

Table 5

Island MFK purchased when FKC is

inactive

MFK purchased when

FKC is active

North 50 20

South 25 10

If frequency keeping continues to be purchased it may be more economically efficient to

purchase from a nationwide market. A nationwide market may allow the cheapest

providers to be selected. Such a change would require a significant change to the SO’s

market system tools. Further developments on establishing a national frequency

keeping services market are part of the RFM programme.

EFFECTIVENESS OF THE MFK COMPLIANCE CALCULATION 6.4

Since the introduction of MFK in the North Island in 2013, the SO has reported frequency

keeping performance using the Regulation Instruction Error Ratio (RIER).

0

50

100

150

200

250

300

350

400

450

fri sat sun mon tue wed thur

Nu

mb

er

of

dis

pat

che

s p

er

day

Day of the week

Comparison of number of dispatches depending on MFK dispatch

FKC on, 0 MFK

FKC on, 30 MFK


30

The RIER is specified as one of the frequency keeping principal performance obligations

(PPO’s) in the Ancillary Service Procurement Contracts the SO has with each frequency

keeping provider. The lower the RIER figure the better the frequency keeping provider is

judged to have performed.

The underlying calculation is a weighted standard deviation of the three minute average

difference between actual power output versus the energy dispatch set-point plus the

MFK regulation instruction. The calculation is made for each frequency keeping unit or

station.

Figure 5 - Monthly RIER values during the trial

The RIER does not take into account the unit governor response to system frequency.

When FKC is enabled the RIER results for many frequency keeping providers vary widely

between months and are significantly worse than when FKC is not enabled.

The poor RIER results are particularly pronounced in the South Island. It is believed this

is due to the greater deviations from MFK regulation caused by the frequency response

of generating units during FKC operation.

As a result, the SO no longer has confidence the RIER metric provides a meaningful

indication of the quality of the frequency keeping service provided. RIER performance

reporting has been suspended.

Recommendation 3 – When the future design for frequency keeping services has been

completed establish a new frequency keeping provider service performance metric.

ACTIVE POWER AND RESERVE COMPLIANCE WITH DISPATCH 6.5

The transfer of frequency keeping duty to generator governor action caused initially by

MFK and then increased with FKC operations can cause a generator’s output to not be

aligned with its dispatch instruction.

Concerns have been expressed by market participants this might impact on both legal

compliance and system security.

0

20

40

60

80

100

120

140

Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15

RIE

R (

%)

Months

MFK Monthly Regulating Instruction Error Ratios

Gen 1

Gen 2

Gen 3


31

6.5.1

There are three clauses of the EIPC 13.73, 13.82 and 8.17 which are relevant.

13.73 … Each dispatch instruction must instruct a generator to carry out one of the

following in relation to a generating plant, generating unit, block dispatch group or

station dispatch group:

(a) provide, increase or decrease active power:

(c) provide an amount and quantity of reserve power to regulate frequency continuously:

13.82 Each generator or ancillary service agent must comply with a dispatch instruction

properly given by the system operator in accordance with clauses 13.73 or 13.74 except

if,-

e) the generator deviates from a dispatch instruction for active power in order to comply

with clause 8.17:

8.17 Each generator (while synchronised) and the HVDC owner must at all times ensure

that its assets … make the maximum possible injection contribution to maintain

frequency within the normal band.

Clause 13.73 defines dispatch instruction to include energy and reserves. Clause 13.82

and 8.17 explain that a generator’s power output may not be aligned with its dispatch if

it is responding to frequency.

A governor control system will react to frequency and change the active power output of

the generator. This reaction is aligned with the EIPC code clauses above. This reaction

affects some governors more when FKC is enabled, due to the previously described

transfer of frequency keeping duties (see section 6.1).

For practical reasons the SO has relaxed its automatic monitoring of active power

compliance with dispatch instructions. The compliance monitoring thresholds in the

market system were changed from 15 MW to 30 MW. The ten minute monitoring period

remains the same.

The SO provided guidance to market participants on 23rd September 2014 on how it

intended to manage generator dispatch compliance during the FKC trial.9 Refer to link

below:

https://www.systemoperator.co.nz/sites/default/files/interfaces/can/CAN%20Guidance%

20regarding%20compliance%20during%20FKC%20Testing%201557159690.pdf

6.5.2

The SO purchases under frequency reserves to manage losses of supply to the system.

Some of these reserves are provided by generators.

In calculating reserves the SO assumes generators are at their dispatched power output.

If in reality a generator’s output is higher than dispatch the expected reserve response

will be slightly slower. If a generator’s output is higher than dispatch then the reserve

9 The SO increased the quantity a generator could be off dispatch before it made enquiries. This was to

recognise the effect of increased governor action for some generators.

https://www.systemoperator.co.nz/sites/default/files/interfaces/can/CAN%20Guidance%20regarding%20compliance%20during%20FKC%20Testing%201557159690.pdf

https://www.systemoperator.co.nz/sites/default/files/interfaces/can/CAN%20Guidance%20regarding%20compliance%20during%20FKC%20Testing%201557159690.pdf


32

response could also become limited to a new lower maximum quantity as there is less

spare capacity on the generator.

Any material decrease in the expected reserve response of generators would impact on

the SO’s ability to meet its frequency PPOs. Further study is recommended to quantify

the magnitude of this issue.

Recommendation 4 – Investigate whether the increase in generator governors being

off dispatch has a material effect on the quantity of reserve available for under frequency

events.

If a generator’s output is lower than dispatch there is a consequential reduction in the

capacity for the generator to respond to an over frequency. The SO’s calculation of over

frequency reserves however relies on real time data not dispatched quantities in its

calculations. It can therefore recalculate quantities as generators react to frequency.


33

7. FKC TRIAL OPERATIONAL ISSUES

AUTOMATIC OPTION NO LONGER AVAILABLE FOR SYSTEM 7.1

DISPATCH

As discussed in section 4.3 the automated formulation of dispatch instructions is no

longer available operational to system co-ordinators. This leads to extra work for system

co-ordinators who must issue dispatches manually during FKC- enabled operations.

Situational awareness is eroded by this narrowly focussed view when manually issuing

dispatch instructions.

This issue may be addressed by the Security Tools Project. This project will provide

more inputs to the market system allowing automatic calculation of dispatch quantities.

The effect of these new inputs on the dispatch quantity is not proportional and some

tuning will be required. Until the market system is tested with these new inputs, it is

uncertain whether the tuning will successfully enable automatic dispatch.

Recommendation 5: Once the Security Tools Project is completed, the system operator

should test if, with FKC enabled, automatic dispatch can be re-enabled.

OPERATIONAL COMPLEXITY OF STARTING AND STOPPING FKC 7.2

OPERATION

The FKC activation and deactivation processes were developed within the existing market

system design.

The process to enable and disable FKC is complicated and onerous. Experience during

and since the trial has shown the process to provide ongoing opportunities for error.

The process requires phone calls to the grid operators, manual actions across multiple

tools and communication to the industry (informing them of the change in FKC status).

In the market system manually-undertaken changes are made to the HVDC under

frequency risk, frequency keeping bands and the amount of SIR reserve that is procured.

This process has 15 manual steps and takes 3 system co-ordinators up to 20 minutes to

complete. With the current market system design, this is a substantial operational

overhead devoted to this task. Managing a concurrent system event would be more

difficult to manage.

The completion of the Security Tools Project will bring some reduction in the time to

complete the processes. The project will make transitions to and from FKC operations

easier and less prone to manual errors.

The improvements from this project are still not expected to sufficiently reduce the time

taken to complete the stopping and starting of FKC process. The lengthy process is a risk

to prudent operation of the electricity system.


34

Recommendation 6 – Investigate a change to the business process and market system

tools associated with the activation and deactivation of FKC with a view to identifying

automation opportunities.

IMPACT OF HVDC RECLOSE BLOCKS ON FKC OPERATION 7.3

When live line work is undertaken on a circuit, any system which, following an electrical

fault, automatically reenergises the circuit is blocked from operating. This is implemented

for safety reasons in case the fault is caused by those working on the circuit. This block

is called a Reclose Block (RCB).

When RP is disabled FKC would have to be disabled whenever the HVDC transfer

approached the HVDC convertor pole minimum of 35 MW. The current complexity of the

manual processes to disable and enable FKC means FKC is disabled whenever RP is

disabled.

For safety reasons RCBs for live line work on the HVDC conductors require HVDC

automatic restarting, including RP, to be disabled during the period any RCB is required

to be in effect.

Currently, for the duration of the HVDC RCBs (typically one week) FKC is disabled. As

disabling FKC has a material market, impact notification of HVDC work requiring RCBs is

advised to participants one week from the start of work.

7.3.1

As discussed in section 7.2 the Security Tools Project will automate some of the manual

processes associated with enabling and disabling FKC. Following implementation the SO

will need to assess whether the project’s changes are sufficient to allow FKC to stay

enabled, even when RP is disabled.

Recommendation 7 – Following the Security Tools Project, investigate whether FKC can

remain enabled when RP is unavailable.

FKC EXIT CONDITIONS REASSESSED 7.4

The FKC trial exit conditions (refer section 4.8), for FKC operations to be terminated,

were reassessed following completion of the trial and once system co-ordinators had

growing operational experience and greater confidence in FKC operation.

The following exit conditions were deemed to be no longer required:

time error in either island exceeds 3.5s

security constraint violations and/or contingency violations.

The other exit conditions were deemed valid and FKC will continue to be disabled when

they are extant:

loss of communications between MFK controller and generator local control

systems (inter control centre protocol or ICCP)

high HVDC transfer north or south (HVDC power limit, less margin)


35

bipole outage or trip

monopole outage or trip

RP unavailable

system security issue identified or major system event occurs.


36

8. TECHNICAL ISSUES FROM THE FKC TRIAL

FREQUENCY EXCURSIONS DURING THE TRIAL 8.1

There were a number of high and low frequency system excursions during the trial

period. The response of the HVDC controls and system frequency were stable and

showed no issues with FKC operation. Further detail on the excursions is in Appendix D.

POSITIVE TIME ERROR TREND 8.2

When FKC is enabled, time error appears to naturally trend in a positive direction. To

maintain time error to within the EIPC required limits of +/- 5 seconds system co-

ordinators use a combination of MFK and dispatch to:

adjust the target frequency in MFK controls. This is to reduce positive or negative

time error over time as the MFK controller drives to a frequency slightly higher or

lower than the standard frequency of 50 Hz for both islands

manually dispatch to correct time error. System co-ordinators can use PSDs for

the next real-time dispatch solution to reduce time error in both islands. (The

Security Tools Project will facilitate automatic calculation of PSDs using the time

error as one of its inputs.)

Figure 6 (below) shows the effect FKC operation has on time error. When the HVDC

frequency control mode was changed from FSC/SRS to FKC an immediate change was

noted. This saw time error changed from oscillating about zero to being a more refined

signal with ascending and descending trends. Time error can be seen ramping all the

way up to two seconds before being returned to zero. Many of the time error decreasing

periods in Figure 6 are due to system co-ordinator corrective action.

Figure 7 (below) shows an example of typical time error trending across a day. It also

shows the sudden increase in time error in a positive direction.

A discussion of some of the potential causes of the positive time error trend is included in

Appendix D – Positive time error trend.


37

Figure 6 FKC effect on time error with time error trending positive

Figure 7 Time error trend example 20th October 2014


38

8.2.1

During the trial it was observed that time error would generally increase in a positive

direction.

A number of potential causes of positive time error were investigated during the FKC

trial. There are several relevant matters:

the time resolution of the historical data was insufficient to identify if a generator

was a cause of the problem or responding to the problem

the FKC control system has no time error input

the FKC control system does not control absolute frequency. It only controls

frequency separation between the North and South Island.

The latter two points support the reasonable assumption that FKC is not likely to be the

cause of the time error trend as it has no input related to time error. (Such an input

could cause a cumulative integration error.)

Despite a lengthy investigation into positive time error increase no cause of the issue has

yet been identified.

Further details of the investigation are in Appendix D – Positive time error trend.

8.2.2

During the trial time error was managed successfully using either manual dispatch or

adjusting the MFK frequency target. It has therefore been determined to continue to

manage time error this same way when FKC is enabled.

TIME ERROR SEPARATION BETWEEN THE NORTH AND SOUTH 8.3

ISLANDS

Whilst FKC aims to tie the two island frequencies together, the two island frequencies are

not truly synchronous. The error between the frequencies accumulates into a divergence

between the two island time errors.

Time error difference between the two islands can be corrected by system co-ordinators.

A frequency off-set is applied in the HVDC controls to either the North or South Island of

+/-10 mHz to rapidly converge the two island time errors.

The rate at which time error diverged between the two islands was observed to be very

consistent across extended periods of time.

Figure 8 and Figure 9 show the time error difference trend across different time periods.

In Figure 8 a clear difference and trend is observed when FKC is enabled, compared to

FKC disabled. In Figure 9 two gradients of time error are observed, one very steep

gradient from 16/12/2014 and one gentler gradient from 27/12/2014.

During the 16/12/2014 to 27/12/2014 period the correction of time error divergence was

very onerous for system co-ordinators and was noted to require a significant amount of

attention compared to a dispatch on a normal day. This problem led to system co-

ordinators trialling a fixed 1 mHz offset instead of periodically inputting a 10 mHz offset

to counter the time error divergence gradient. This was effective until the gradient

changed later the following day. This is discussed further in Appendix E - Using HVDC

frequency offset from HMI to minimise time error divergence.


39

It is not clear what affects the gradient of the time error divergence. However, it has

been shown to be consistent over extended periods of time.

Figure 8 Time error difference plot 16/10/2014 – 11/11/2014 (South Island - North Island time error)

Figure 9 Time error difference plot 16/12/2014 - 12/01/2015 (South Island - North Island time error)

8.3.1

It would appear possible to eliminate time error separation between North and South

Island frequencies by inputting the correct frequency offset. This will require the ability


40

to enter values of less than 1 mHz into the HVDC controls, as even with a 1 mHz offset a

slow separation occurs.

A modification is being made to the HVDC controls to allow frequency offsets of less than

1 mHz to be made. A PI based application is being developed to calculate the required

frequency offset.

CAUSES OF NORMAL FREQUENCY BAND VARIATIONS 8.4

8.4.1

A major cause of frequency variation in the North Island and therefore in both islands

when FKC control is in service is a constantly varying large load. This is demonstrated in

Figure 9 and Figure 11 below.

Figure 10 below show the strong correlation between the HVDC being off dispatch for

frequency control and the average power taken by the varying load. Figure 11 shows

the strong correlation between North Island frequency and the average power taken by

the varying load.

Figure 10 - Graph of HVDC frequency response with a North Island Load

6

8

10

12

14

16

18

0

5

10

15

20

25

30

35

40

27-Dec 1-Jan 6-Jan 11-Jan 16-Jan 21-Jan 26-Jan 31-Jan 5-Feb

Dai

ly a

vera

ge H

VD

C is

off

dis

pat

ch (

MW

)

Ave

rage

dai

ly lo

ad (

MW

)

Time

Effect on the HVDC frequency response

Load

HVDC


41

Figure 11 - Graph of frequency deviation with North Island Load

The SO understands the variations in this load will reduce significantly towards the end

of 2015. If this expected reduction occurs the extent to which the HVDC is off dispatch

and the generation is off dispatch should materially reduce.

8.4.2

When examining the changes in modulation deviation from day to day another cause of

frequency deviations became apparent. More deviation appeared to arise when slow

ramping generators were altering their power output to achieve their dispatch set point.

An example is shown in Figure 12 (below). The shortfall in output by the slow ramping

generator is compensated for by the HVDC increase. The HVDC increase represents the

action of South Island generator governors. When the generator reaches dispatch the

HVDC also returns to dispatch.

Currently the EIPC requires generators need only comply with ramp rates over a period

of an hour. System dispatch assumes generators will follow their ramp rate over a five

minute period. When generators do not follow their ramp rate over the five minutes

assumed in dispatch there is a resultant imbalance in power supply. This imbalance

causes a deviation in frequency.

The SO uses the PI tool for analysis of historical generation data. Because PI does not

store dispatch instructions it was not possible to easily understand how much slow

generation ramping is causing the HVDC to be off dispatch.

Further investigation is therefore required to understand this effect, as follows:

arrange for the relevant dispatch points to be included in the PI database

0.015

0.017

0.019

0.021

0.023

0.025

0.027

0.029

0.031

0.033

0

5

10

15

20

25

30

35

40

27-Dec 1-Jan 6-Jan 11-Jan 16-Jan 21-Jan 26-Jan 31-Jan 5-Feb

Ave

rage

Dai

ly a

bso

lute

fre

qu

en

cy d

evi

atio

n (

Hz)

Ave

rage

Dai

ly L

oad

(M

W)

Time

Effect on system frequency

Load

frequency


42

calculate the correlation, if any, between generation shortfall and HVDC off

dispatch. (This is representative of generator governor action to correct

frequency.)

Recommendation 8 – Update the SO’s PI tool to receive generator dispatch data.

Undertake a study to consider how slow ramping generation affects the HVDC being off

dispatch with FKC enabled.

Figure 12 How a generator cause HVDC to be dispatched off

BACK UP FREQUENCY KEEPING 8.5

The system operator procures Back-up Single Frequency Keeping (SFK) ancillary services

to maintain PPOs should MFK fail. Single frequency keeping (SFK) performance with FKC

Although South Island SFK was tested with FKC in service it was felt desirable to test

both the North and South Island SFK to check there were no operational issues. The

tests were carried out with lower frequency keeping bands as per Table 6 below:

Table 6

Original FKC tests

August 2014

North Island SFK

test March 2015

South Island SFK

test April 2015

Frequency Keeping

band (MW) 75 50 25

With SFK operating and FKC enabled the PPOs were maintained with in their limits.

However, unexpectedly these tests showed SFK providers are not as familiar with the

SFK process as expected. There were several teething troubles with both the operational

and market utilisation of SFK. These issues impacted the data gathered from the tests.

-80

-60

-40

-20

0

20

40

60

80

100

0 5 10 15 20 25 30

Dif

fere

nce

be

twe

en

Act

ual

ou

tpu

t an

d d

isp

atch

(M

W)

Time (minutes)

How a Generator causes HVDC to be off dispatch

Thermal Generator HVDC


43

The data does not therefore sufficiently represent SFK operation for use in comparison

with MFK.

It is recommended the SO repeat the SFK tests on a six monthly basis to allow providers

to retain knowledge of SFK operation.

Recommendation 9 – The SO establishes a testing regime for a full day of SFK

operation every six months, (when market conditions are suitable.)

FKC PERFORMANCE DURING FAST WINTER LOAD PICK UPS 8.6

With completion of the FKC trial on 31st March 2015, the impact of fast winter load pick-

ups combined with slow ramping thermal plant has yet to be determined.

Notwithstanding this lack of experience, there is no evidence from the FKC trial to

suggest that there should be any winter issues. However, a review of the 30 MW FKC

MR will be conducted during winter loads to ensure this quantity of MR is still prudent.

WHAT IS AN APPROPRIATE NORMAL FREQUENCY STANDARD? 8.7

The EIPC requires only that frequency stays in the normal band of 49.8 Hz to 50.2 Hz.

As discussed in Appendix A the amount frequency deviates from 50 Hz varies with the

amount and type of frequency control available. The technical implications of the

frequency deviations are:

in calculating the purchases of under and over frequency reserves the SO

assumes a starting value of 50 Hz. As frequency will deviate from 50 Hz the SO

therefore needs to and does add a safety margin to calculating its requirements

for purchasing reserves. The higher the probability of frequency deviations the

larger the safety margin.

a steady frequency is also a requirement for generation units to easily connect to

the grid.

Whilst the technical implications of frequency deviations are clear, the economic impact

of these implications is not. An economic study of how frequency deviations in the

normal band change costs for market participants is desirable.

Recommendation 10 – Carry out economic studies to calculate the costs implications

of greater frequency deviations.


44

9. FUTURE DEVELOPMENTS WITH FKC OPERATION

The following ideas indicate where future changes in FKC operations may occur. They do

not represent concluded thinking by the SO.

REDUCTION IN THE MODULATION RISK 9.1

The MR was reduced from 40 MW to 30 MW at the end of the FKC trial.

This number was achieved by taking into account the following factors:

how long the HVDC with FKC in service was above dispatch by a certain value

the comparative performance of the HVDC with FSC in service.

With FSC in service the HVDC varies from its dispatch value. This variation has not been

accounted for in the reserve calculation to date. With FKC enabled the HVDC variation

from its dispatch value increases. This variation was, during initial FKC operations,

greater and sustained for a longer period than previously when FSC was in service.

Through modifications to the MFK settings and changes to the dispatch process the SO

has reduced the value of the FKC MR from 75 MW prior to the trial to 30 MW with FKC

enabled.

There are a number of future developments which may be able to reduce modulation risk

further:

exit of a large highly variable North Island load towards the end of 2015

further improvements in dispatch compliance of ramping generation (see section

8.4.2).

Conversely, some of the reasons no additional reserve was required to cover the risk of

the HVDC being off dispatch, with FSC in service, may no longer be valid in the near

future:

the five second overload of a convertor pole to 840 MW is not now being

modelled.10 This overload may be modelled in RMT in the next year

the reduction in purchased reserves with the various initiatives within the RFM

programme (e.g. national reserves market).

The SO will undertake a review of the under frequency reserves required to cover all

HVDC risks of loss of supply. The review will include an examination of the modulation

risk for frequency controls and all levels of convertor pole overloads.

Recommendation 11 – Undertake a review of under frequency reserves requirements

to cover the HVDC risks of loss of supply.

10 Following the loss of Pole 3, Pole 2 will overload up to 840 MW for 5 seconds before reducing to a maximum

of 560 MW.


45

QUANTITY OF FREQUENCY KEEPING PURCHASED 9.2

The technical success of tests with MFK dispatched to 0 MW enables consideration of a

future scenario where there is no frequency keeping service required.

Such change cannot be made immediately as there are several operational, tool and

market issues to resolve.

9.2.1

The MFK 0 MW tests have identified the following issues needing to be resolved before a

move to procuring no or materially lower frequency keeping services:

update of the dispatch inputs to allow automatic correction for time error

providing system co-ordinators with the ability to easily and quickly revert to

back-up frequency keeping when FKC is unavailable. The current process

involves too many steps requiring too much time. This implies some major

automation changes to system co-ordinator tool sets.

9.2.2

An important market issue to address is the FKC-induced increase in South Island

generator governor action.

9.2.3

Continued use of MFK as an operational method of correcting time error, whilst practical,

comes with a cost. Even with the reduced cost from FKC-enabled operations, frequency

keeping (i.e. MFK) costs are projected to be approximately $13 million per annum.11

Using dispatch to correct time error and purchasing less or no MFK might enable this cost

to be reduced.

Recommendation 12 - Once the consequences of increased governor response have

been considered in a market context (Recommendation 1), consider the quantity of MFK

required for operation with FKC.

AUTOMATIC GOVERNOR CONTROL 9.3

As detailed in section 4.2, the slow response time of MFK has made MFK ineffectual in

controlling frequency when FKC control is enabled. Some participants have suggested

that, instead of relying on governor action, a quicker responding frequency keeper could

be used. SFK would be one option; Automatic Generation Control (AGC) would be

another.

AGC has been implemented in a large number of power systems throughout the world.

MFK is a variation of AGC, the key difference being that with AGC the control signal is

11 This projection assumes the cost of frequency keeping over the year is the same proportionally as the cost

over the January to March 2015 period when FKC was fully enabled. The cost of frequency keeping for these first 3 months of the year was $3.3 million.


46

sent directly into the governor control system. With MFK the signal is sent via the power

controller which introduces a significant time delay.

AGC was an option considered when MFK was selected. It was rejected due to

implementation cost, block dispatch in its current form is not compatible with AGC and

reluctance by participants to allow direct control of generator governors. An AGC system

would require the MFK system to be upgraded to decrease the signalling and processing

time delays of the central controller.

AGC might have the advantage of allowing more competition than SFK as a small

generator would be able to compete in an AGC market that might otherwise be excluded

from a SFK market. (This is why MFK was introduced as a replacement for SFK.)

Using AGC would be a longer term solution. First investigation steps would probably be

further SFK testing to examine whether a frequency keeper acting with FKC enabled

could take significant duty off generator governors.

Consideration of a developed AGC implementation would be for the Authority to lead.

SYSTEM OPERATOR DISPATCH STRATEGY 9.4

The SO is in the process of defining a strategy and vision for the future of the dispatch

function. This strategy will encapsulate the tools and processes used in the dispatch

function with an aim to drive efficiency and automation; moving from providing

situational awareness to developing situational intelligence. The strategy will drive the

removal or re-allocation of non-value adding tasks currently carried out in the co-

ordination centre, ensuring not only primary but also back-up processes and tools are

optimised for single person dispatch.


47

10. CONCLUSION & RECOMMENDATIONS

The FKC trial ran from 16th October 2014 through to 31st March 2015. With FKC in

operation the SO was able to meet the EIPC PPOs for frequency and time error.

During the FKC trial the following benefits were noted:

frequency keeping costs reduced with frequency keeping duty transferred to

generators with governors active in the normal band

tighter control of normal frequency with overall frequency deviation across NZ

decreasing with, however, a decrease in the North Island and an increase in the

South Island

increases of capacity during energy shortfalls.

During the FKC trial the following market-relevant matters were noted:

increases in generator governor action for South Island generators

the modulation risk caused an increase in market costs

the RIER compliance measure is no longer effective

generator compliance with dispatch and reserves is impacted by FKC operation.

During the FKC trial the following operational and technical issues were noted:

automated sending of dispatch instructions is no longer possible

an increase in sending of dispatches with 0 MW of MFK

starting and stopping FKC is a complex and manual process for system co-

ordinators

there are new and significant processes associated with HVDC live line

maintenance (RCBs)

time error tended to increase positively

time error separation with FKC between the North and South Islands.

The further actions the SO considers to be necessary following the FKC trial are divided

into recommendations for the Authority and recommendations for the SO. The ability of

both the SO and the Authority to progress the recommendations will be dependent on

budget and work programme priorities.

RECOMMENDATIONS FOR THE AUTHORITY 10.1

Recommendation 1 –The consequences of increased governor response should

be considered in a market context given the operational reliance now placed by

SO on that action during FKC operations.

Recommendation 2: Study the feasibility of a market solution which could

decide when it is economically efficient to enable FKC.

Recommendation 6 – Investigate a change to the business process and market

system tools associated with the activation and deactivation of FKC.

Recommendation 10 – Carry out economic studies to calculate the costs

implications of greater frequency deviations.


48

Recommendation 12: Once the consequences of increased governor response

have been considered in a market context (Recommendation 1), consider the

quantity of MFK required for operation with FKC.

The SO has already discussed recommendations 1 and 10 with the Authority. The

Authority has initiated work to investigate these issues, its Normal Frequency

Management Strategy investigation.

RECOMMENDATIONS FOR THE SO 10.2

Recommendation 3 – After the future design for frequency keeping has been

completed undertake a study into using a new performance metric.

Recommendation 4 – Investigate whether the increase in generator governors

being off dispatch has a material effect on the quantity of reserve available for

under frequency events.

Recommendation 5: Once the Security Tools Project is completed, the SO

should carry out tests to see if, with FKC enabled, automatic dispatch can be re-

enabled.

Recommendation 7 – Following the Security Tools Project, investigate whether

FKC can remain enabled when RP is unavailable.

Recommendation 8 – Update the PI tool to receive generator dispatch data.

Carry out a study to consider how slow ramping generation affects the HVDC

being off dispatch with FKC enabled.

Recommendation 9 – The SO puts in place a testing regime for a full day of SFK

operation every six months, (when market conditions are suitable.)

Recommendation 11 – Undertake a review of under frequency reserves

requirements to cover the HVDC risks of loss of supply.


49

APPENDIX A – FREQUENCY ANALYSIS

Frequency data from the trial period was collected for analysis. For comparison, data

was also collected from the time when FKC was not enabled. Table 7 details when the

data was collected.

Table 7

Frequency Data type Time data was sourced

FSC/SRS and MFK January and September 2014

FKC and MFK =30 January 2015

FKC and MFK = 0 22nd Dec 2014 to 24th Dec 2014

10th Feb 2015 to 17th Feb 2015

24th Feb 2015 to 10th March 2015

The frequency data for the above time periods is plotted in Figure 13 to Figure 16.

Figure 16 Zero MFK test period frequency data


50

Figure 13 North and South Island Frequency January 2014 with FKC off

Figure 14 North and South Island Frequency September 2014 with FKC off


51

Figure 15 North and South Island Frequency January 2015 with FKC on

Figure 16 Zero MFK test period frequency data

Statistical data for frequency across the analysed time period is presented below inTable

8 and Table 9. This is represented graphically as a normal distribution curve in Figure 17

and Figure 18.


52

Table 8 NI Frequency Statistical Information

Max Min Average Median Average (absolute deviation)

Median (absolute deviation)

Standard Deviation

NI Pre-FKC Jan-14 50.29 49.71 50 50 0.049 0.039 0.063

NI Pre-FKC Sep-14 50.25 49.72 50 50 0.050 0.040 0.064

NI FKC Jan-15 50.22 49.77 50 50 0.026 0.020 0.034

NI 0 MFK Tests 50.21 49.76 50 50 0.032 0.025 0.041

Table 9 SI Frequency Statistical Information

Max Min Average Median Average (absolute deviation)

Median (absolute deviation)

Standard Deviation

SI Pre-FKC Jan-14 50.34 49.77 50 50 0.020 0.015 0.028

SI Pre-FKC Sep-14 50.41 49.78 50 50 0.026 0.020 0.035

SI FKC Jan-15 50.33 49.78 50 50 0.022 0.017 0.028

SI 0 MFK Tests 50.17 49.79 50 50 0.027 0.022 0.035

The data in Table 8 and Table 9 shows that without FKC North Island frequency deviation

is greater than South Island frequency deviation. However, with FKC on the deviations

of North and South Island are very similar.

It is evident from the standard deviations and Figure 15 that even with FKC on North

Island frequency still has more variation than South Island. This is expected as the

frequencies are linked through the FKC control system, which will have some lag and a

small dead band, so the frequencies are not exactly synchronized and a small aspect of

the FKC-off trend will remain.

Another point in the initial hypothesis was that the variation in South Island frequency

may worsen with the activation of FKC. Looking at the standard deviation, the values for

South Island are 0.028, 0.035, and 0.028 in January 2014, September 2014, and

January 2015 respectively. System load impacts frequency deviation and the load profile

for September is very different than the load profile for January, while January 2014 and

January 2015 have similar load profiles. Taking this into account, the data suggests FKC

has not had a significant effect on the normal frequency deviation of the South Island.

Comparing January 2014 and September 2014 data, we see South Island frequency

deviation is significantly affected by load. The North Island, however, does not appear to

have been affected. A likely reason for this is that industrial loads, being the main

contributors for North Island frequency deviation, operate almost all year round so the

effect of the rest of the load is not significantly observed.

The 0 MFK test periods data shows the quality of frequency keeping is not significantly

compromised with removal of MFK. The North Island data shows that although it

worsens from the FKC and MFK combination, it is still well below the variation observed

with FKC deactivated. South Island data shows a more severe drop increase in variation

without the contribution of MFK, however it is far off the variation observed without FKC.

It is important to note the above analysis does not fully take account of the difference in

load between the two periods. September has a much higher load than January and the


53

impact of this is unclear. The section on “Weighted average frequency deviation”

(below) provides insights on the effect of load with a weighted average frequency

deviation analysis.

Figure 17 NI Frequency band normal distribution comparison FKC on/off and 0 MFK test period

Figure 18 SI Frequency and normal distribution FKC on/off and 0 MFK test period


54

With FKC enabled North Island frequency deviation has improved and South Island

frequency deviation has deteriorated. To establish whether FKC provides an overall

benefit to frequency deviation across New Zealand a weighted average was used. The

weighted average was based on load.

The three formulae below describe the weighted average frequency deviation analysis.

∆𝑓𝑆𝐼_𝑤𝑒𝑖𝑔ℎ𝑡𝑒𝑑_𝑎𝑣𝑒𝑟𝑎𝑔𝑒 =∑

(∆𝑓𝑆𝐼 × 𝐿𝑜𝑎𝑑𝑆𝐼)𝐿𝑜𝑎𝑑𝑁𝑍

𝑃𝐼_𝑑𝑎𝑡𝑎_𝑝𝑜𝑖𝑛𝑡𝑠

∆𝑓𝑁𝐼_𝑤𝑒𝑖𝑔ℎ𝑡𝑒𝑑_𝑎𝑣𝑒𝑟𝑎𝑔𝑒 =∑

(∆𝑓𝑁𝐼 × 𝐿𝑜𝑎𝑑𝑁𝐼)𝐿𝑜𝑎𝑑𝑁𝑍

𝑃𝐼_𝑑𝑎𝑡𝑎_𝑝𝑜𝑖𝑛𝑡𝑠

∆𝑓𝐴𝑣𝑒𝑟𝑎𝑔𝑒 = ∆𝑓𝑆𝐼𝑤𝑒𝑖𝑔ℎ𝑡𝑒𝑑𝑎𝑣𝑒𝑟𝑎𝑔𝑒+ ∆𝑓𝑁𝐼𝑤𝑒𝑖𝑔ℎ𝑡𝑒𝑑𝑎𝑣𝑒𝑟𝑎𝑔𝑒

Where ∆𝑓 is the absolute value of frequency deviation from 50 Hz.

Table 10 shows the weighted average frequency deviation calculated for the time periods

presented earlier in section 5.2.

Table 10 Weighted Average Frequency Deviation

North Island South Island New Zealand

FKC off Jan-14

Weighted Average

Frequency Deviation (Hz)

0.030 0.008 0.038

FKC off Sep-14

Weighted Average


0.032 0.01 0.041

FKC on Jan-15

Weighted Average


0.015 0.008 0.024

0 MFK test periods

Weighted Average


0.019 0.010 0.030

The table shows that with FKC enabled the overall New Zealand frequency deviation has

improved. With 0 MFK the overall frequency deviation increases but is still significantly

better than when FKC is disabled.

As discussed in 8.1, time error was observed to have a randomly occurring positive bias

when FKC was in operation. This section compares the behaviour of time error with MFK

at its normal MW allocation of 30 MW, and MFK during the 0 MW tests.

Table 11 shows the time error statistical data comparing periods during the 0 MFK tests

and normal operation of FKC and MFK. Here we can see a clear trend between the

0 MFK tests and a greater time error – both negative and positive.

This follows logically from the frequency deviation analysis which shows with MFK not

operating there is a greater frequency deviation than with MFK operational. A higher

frequency deviation will integrate into a higher time error.


55

Table 11 Time error statistical data during the 0 MFK tests and FKC and MFK operating normally

Total 0 MFK Tests NI

Total 0 MFK Tests SI

FKC period Jan-2015 NI

FKC period Jan-2015 SI

FKC period Oct-2015 NI

FKC period Oct-2015 SI

Average 0.1885 0.1923 0.0129 0.1257 -0.0501 0.1201

Median 0.147 0.1723 -0.0092 0.089 -0.0767 -0.0070

Deviation 0.6636 0.646 0.3717 0.3738 0.3978 0.3701

Time Analysed (mins) 33123 33123 33121 33121 33121 33121

% Time Below -2 0.0019 0.0016 0 0 0.0002 0.0000

% Time Below -1 0.0462 0.0301 0.0023 0.0019 0.0101 0.0019

% Time Below 0 0.4372 0.356 0.5093 0.3742 0.5937 0.5124

% Time Above 0 0.5628 0.644 0.4907 0.6258 0.4063 0.4876

% Time Above 1 0.0958 0.1154 0.0073 0.016 0.0136 0.0310

% Time Above 2 0.0069 0.0088 0.0001 0.0003 0.0000 0.0002

Figure 19 Time Error pdf function comparing 0 MFK tests and normal FKC/MFK operation

0

0.2

0.4

0.6

0.8

1

1.2

-3 -2 -1 0 1 2 3

PD

F

Time Error (s)

Time Error Probability Distribution Function comparing 0 MFK and FKC/MFK normal

operation

Total 0 MFK Tests North Island

Total 0 MFK TestsSouth Island

FKC and MFK period Jan-2015North Island

FKC and MFK period Jan-2015South Island

FKC and MFK period Oct-2015North Island

FKC and MFK period Oct-2015South Island


56

APPENDIX B – GENERATOR OFF-DISPATCH DATA

During the FKC trial, different modes of frequency keeping have been in operation, with

MFK being the most dominant as stated above.

Other operating arrangements are:

MFK operating with both islands controlled independently before FKC was enabled

single frequency keeping (SFK) in each island well before the FKC trial began.

throughout the FKC trial, frequency keeping tests were run for single frequency

keeper for the whole system and MFK with 0 MW dispatched

Table 12 (below) has a breakdown of the HVDC and frequency keeping mode

combinations applied during the FKC trial period.

The main periods for this analysis are 3 and 4, as they show a comparison with and

without FKC, and 5, the 0 MFK test. Periods 1, 2, 6, and 7 did not have sufficient data

points for a meaningful comparison.

Table 12 Frequency keeping and HVDC modes of operation during the FKC trial

Period

Number

Period Description

1 SFK, FSC/SRS SFK in each island

HVDC in FSC/SRS mode

2 NI MFK, SI SFK,

FSC/SRS

North Island in MFK mode, South

Island in SFK mode


3 NI MFK, SI MFK,

FSC/SRS

North Island in MFK mode,

South Island in MFK mode,


4 NI MFK, SI MFK, FKC North Island in MFK mode,

South Island in MFK mode,

Single source used for MFK

HVDC in FKC mode

5 NI MFK, SI MFK, FKC

- 0 MFK test

Zero frequency keeping test

HVDC in FKC mode

6 NI SFK, FKC - SFK

test

Single frequency keeper in the North

Island test

HVDC in FKC mode

7 SI SFK, FKC - SFK

test

Single frequency keeper in the South

Island test

HVDC in FKC mode

Table 13 shows averages for governor off-dispatch absolute values in pu. Table 14 and

Table 15 show the governor off-dispatch data for the FKC trial period in per unit (pu),

average and standard deviation have been taken for the key operation periods. Table 16

and Table 17 show the same information in MW. Note that for the MW values, it is not a

direct translation back to the pu values as the MW rating varies with time, depending on

which units are on the system. This also makes comparison of MW off-dispatch values

between time periods and between generators slightly less meaningful than comparing

the pu values.


57

Figure 20 to Figure 26 show the governor off-dispatch deviation probability distribution

functions constructed from the calculated MW off-dispatch average and standard

deviation. The absolute value MW off-dispatch is also plotted on the same graphs.

Recognising asset owner confidentiality, the generation groups will be referred to as “SI

Group 1 – 3” for South Island generator groups and “NI Group 1 – 4” for North Island

generator groups.

The most meaningful measure presented here for governor activity comparison is the per

unit standard deviation. Looking at the data in Table 15 we see, as expected, FKC

improves the situation for the North Island and worsens it for the South Island. NI

Generator Group 1 stands out as an exception to this rule. A likely reason for this is that

the data for this group was largely unavailable for the periods where FKC was

deactivated making a meaningful comparison between periods difficult to achieve. Also,

NI Generator Group 3 shows slightly more activity without FKC. However, the values are

essentially equal so it is within an expected margin on error. The absolute value of MW

off-dispatch average in per unit also reflects this trend clearly in Table 13.

We also see in this analysis data for the 0 MFK tests which were performed throughout

the FKC trial. Three trials were executed totalling a time period of about three weeks.

The data for these periods sensibly suggest that generally the governors were off

dispatch more than with MFK in operation, especially for the South Island units. MFK,

although a slower response than FKC and governor droop control, will return the system

to 50 Hz and hence, the governors, back to their dispatch value.

The methodology of the calculation for the governor off-dispatch data is included in the

“Calculation diagram” of Appendix B – Generator off-dispatch data.

Table 13 Absolute MW off-dispatch in per unit average

Period 3 Period 4 Period 5 Period 3 or 4 worse?

SI Generator Group 1 0.47% 0.63% 0.91% Period 4



NI Generator Group 1 1.21% 1.78% 1.42% Period 4





58

Table 14 MW off-dispatch in per unit average


SI Generator Group 1 0.18% -0.27% -0.31% Period 4

SI Generator Group 2 -0.48% -0.37% -0.40% Period 3

SI Generator Group 3 -0.06% -0.05% -0.08% Period 3


NI Generator Group 2 -0.59% -0.51% -0.53% Period 3



Table 15 MW off-dispatch in per unit standard deviation


SI Generator Group

1

0.65% 0.85% 1.13% Period 4

SI Generator Group

2

0.50% 0.79% 1.15% Period 4

SI Generator Group

3

0.48% 0.61% 0.89% Period 4

NI Generator Group

1

2.90% 4.04% 3.22% Period 4

NI Generator Group

2

1.21% 0.83% 0.73% Period 3

NI Generator Group

3

0.94% 0.94% 0.90% Period 4

NI Generator Group

4

2.23% 1.40% 1.48% Period 3

Table 16 MW off-dispatch in MW average


SI Generator Group 1 1.14 -1.19 -1.59 Period 4

SI Generator Group 2 -2.72 -2.65 -2.74 Period 3

SI Generator Group 3 -0.70 -0.63 -0.95 Period 3

NI Generator Group 1 0.17 0.25 0.20 Period 4

NI Generator Group 2 -0.79 -0.90 -0.85 Period 4


59




Table 17 MW off-dispatch in MW standard deviation

Period 3 Period 4 Period 5 Period 3

or 4

worse?

SI Generator Group 1 3.69 4.14 5.77 Period 4







Figure 20 SI Generation Group 1 MW off-dispatch pdf function


60




61

Figure 23 NI Generation Group 1MW off-dispatch pdf function



62


Figure 26 NI Generation Group 4 MW off-dispatch pdf function


63

NORTH ISLAND – SOUTH ISLAND COMPARISON

Figure 27 to Figure 29 below shows a comparison of generator off dispatch data for the

generation groups for each operation period. The South Island generation groups are

shown in shades of blue and North Island generation are shown in shades of red.

Per unit values are used rather than MW to meaningfully compare different generation

groups with each other. However, in this comparison between generation groups,

factors affecting governor response such as droop and dead bands have not been

normalized across the generators which will affect how the governors react to frequency.

It should also be noted that the comparison between North and South Island generator

governors is between these few generation groups only, which are sensitive to frequency

deviations in the normal band. The comparison cannot be extended to other generators

many of which are not responsive to frequency in the normal band.

Figure 27 shows period 3 with MFK and FSC/SRS operation configuration. This shows

that during this time period the North Island generators were off dispatch comparatively

more than South Island. As has been discussed earlier, the North Island has more

frequency variation than the South Island, so it follows that the governors of the North

Island will regulate MW more than in the South Island.

Figure 28 shows period 4 with MFK and FKC operation configuration. This shows during

this time period the North Island and South Island generators were off dispatch at a

similar rate, with SI Group 3 and NI Group 4 slightly more extreme either way. The

higher alignment of the generators being off dispatch between the two islands is a

sensible outcome of the two island frequencies being aligned with FKC.

Figure 29 shows period 5 with FKC operating during the 0 MFK trials. This shows a

similar trend to period 4 of the North and South Island governors having roughly the

same activity. Compared to period 4, all generators are found to be more off dispatch

during period 5.

In summary, for these generation groups, the North Island governors are more active

than the South Island without FKC, and with FKC they are quite similar.


64

Figure 27 Period 3 – MFK + FSC/SRS – MW off dispatch (pu) pdf

Figure 28 Period 4 – MFK + FKC – MW off dispatch (pu) pdf

0

10

20

30

40

50

60

70

80

90

-0.05 -0.03 -0.01 0.01 0.03 0.05

Pro

bab

iliy

De

nsi

ty F

un

ctio

n

MW off dispatch (pu)

Period 3 MW off dispatch (pu) pdf function

PDF Function SIGeneration Group 1



PDF Function NIGeneration Group 2



0

10

20

30

40

50

60

70

80

90

-0.05 -0.03 -0.01 0.01 0.03 0.05

Pro

bab

iliy

De

nsi

ty F

un

ctio

n










65

Figure 29 Period 5 – 0 MFK test + FKC – MW off dispatch (pu) pdf

0

10

20

30

40

50

60

70

80

90

-0.05 -0.03 -0.01 0.01 0.03 0.05

Pro

bab

iliy

De

nsi

ty F

un

ctio

n










66

CALCULATION DIAGRAM

Figure 30 shows the analysis of PI data undertaken to produce the results presented in Appendix B – Generator off-dispatch data.

Figure 30 Governor off-dispatch calculation diagram


67

APPENDIX C – FREQUENCY EXCURSION DETAILS

This appendix lists frequency excursions which occurred during the FKC trial. In all cases,

where an HVDC tripping was not the cause of the excursion, the HVDC operated as

expected to arrest the frequency in the affected island, passing some of the frequency

management burden to the unaffected island.

The high and low frequency excursions have been separated into two sections.

Frequency excursions involving the HVDC result in a high frequency swing in one island

and a low frequency swing in the other. These events have been categorised as an over

or under frequency event based on whichever swing was larger.

Table 18 lists the values represented by the PI tags plotted in the frequency excursion

plots in the following sections.

Table 18 Represented quantities by PI tags in frequency excursion plots

PI Tag Represented Quantity

P:BENPMU0582.FREQ South Island frequency

P:HAYPMU0592.FREQ / P:HLYPMU0522.FREQ North Island frequency

P:HAYPMU0842.MW Pole 2 MW south

P:HAYPMU0922.MW Pole 3 MW south

Table 19 lists the over frequency excursions during the FKC trial period.

Figure 31 to Figure 34 show PMU data for frequency and HVDC power output during the

frequency excursion events graphically.

Table 19 List of excursions which occurred during the FKC trial 16/10/2014 – 31/03/2015

Date/Time Event North Island Freq (Hz)

South Island Freq (Hz)

HVDC modulation (MW)

Figure Reference

04-Nov-2014

02:06

Tiwai planned

reduction 115 MW

50.33 50.51 70 MW Figure 31

27-Feb-2015

17:44

Tiwai emergency

potline trip

50.36 50.61 110 MW Figure 32

03-Mar-2015

13:31

Haywards F3B switch

out – HVDC power

limit ramp back from

395 MW to 280 MW

49.37 51.01 Power limit

forced ramp

back of

115 MW

Figure 33

24-Mar-2015

18:35

Tiwai emergency

potline trip

50.41 50.62 120 MW Figure 34


68

Figure 31 Tiwai potline planned reduction event 04/11/2014

Figure 32 Tiwai emergency potline trip event 27/02/2015

-200

-180

-160

-140

-120

-100

-80

-60

-40

-20

0

49.8

49.9

50

50.1

50.2

50.3

50.4

50.5

50.6

04-Nov-14 02:05:17 04-Nov-14 02:06:43 04-Nov-14 02:08:10

Fre

qu

en

cy (

Hz)

Time

Tiwai Potline Planned Reduction Event 4/11/2014

P:BENPMU0582.FREQ

P:HLYPMU0522.FREQ

P:HAYPMU0842.MW

P:HAYPMU0922.MW

-340

-330

-320

-310

-300

-290

-280

-270

-260

-250

49.8

49.9

50

50.1

50.2

50.3

50.4

50.5

50.6

50.7

27-Feb-15 17:43:26 27-Feb-15 17:44:18 27-Feb-15 17:45:10

Fre

qu

en

cy (

Hz)

Time

Tiwai Potline Trip Event 27/02/2015

P:BENPMU0582.FREQ

P:HAYPMU0592.FREQ

P:HAYPMU0842.MW

P:HAYPMU0922.MW

MW

M

W


69

Figure 33 HAY F3B switch event 03/03/2015

Figure 34 Tiwai emergency potline trip event 24/03/2015

Table 20 lists the under-frequency excursions during the FKC trial period.

Figure 35 to Figure 39 show PMU data for frequency and HVDC power output during the

frequency excursion events graphically.

-250

-200

-150

-100

-50

0

49.2

49.4

49.6

49.8

50

50.2

50.4

50.6

50.8

51

51.2

03-Mar-15 13:30:43 03-Mar-15 13:32:10 03-Mar-15 13:33:36

Fre

qu

en

cy (

Hz)

Time

HAY F3B Switch Event 03/03/2015

P:BENPMU0582.FREQ

P:HAYPMU0592.FREQ

P:HAYPMU0842.MW

P:HAYPMU0922.MW

MW

-300

-250

-200

-150

-100

-50

0

50

49.8

49.9

50

50.1

50.2

50.3

50.4

50.5

50.6

50.7

24-Mar-15 18:34:34 24-Mar-15 18:36:17 24-Mar-15 18:38:01

Fre

qu

en

cy (

Hz)

Time

Tiwai Potline Trip Event 24/03/2015

P:BENPMU0582.FREQ

P:HLYPMU0522.FREQ

P:HAYPMU0842.MW

P:HAYPMU0922.MW

MW


70

Table 20 List of excursions which occurred during the FKC Trial 16/10/2014 – 31/03/2015

Date/Tim

e

Event North

Island

Freq (Hz)

South

Island

Freq (Hz)

HVDC

modulatio

n (MW)

Figure

Reference

31-Oct-

2014

22:25

Generation co-

ordination centre data

entry issue

49.58 49.43 75 MW Figure 35

15-Nov-

2014

05:51

Pole 2 trip 50.40 48.81 Pole 2

tripped at

100 MW

Figure 36

15-Nov-

2014

06:13

Pole 3 stop 50.12 49.44 Pole 3

stopped at

35 MW

Figure 37

06-Jan-

2015

13:46

NI generation trip 49.43 49.55 60 MW Figure 38

23-Feb-

2015

01:51

NI generation trip 49.50 49.58 45 MW Figure 39

Figure 35 Co-ordination centre data entry issue event 31/10/2014

-180

-160

-140

-120

-100

-80

-60

-40

-20

0

49.2

49.4

49.6

49.8

50

50.2

50.4

50.6

31-Oct-14 22:24:58 31-Oct-14 22:26:24 31-Oct-14 22:27:50

Fre

qu

en

cy (

Hz)

Time

Control Centre Data Entry Issue Event 31/10/2014

P:BENPMU0582.FREQ

P:HLYPMU0522.FREQ

P:HAYPMU0842.MW

P:HAYPMU0922.MW

MW


71

Figure 36 Pole 2 trip event 15/11/2014

Figure 37 Pole 3 stop event 15/11/2014

-50

0

50

100

150

200

250

48.6

48.8

49

49.2

49.4

49.6

49.8

50

50.2

50.4

50.6

15-Nov-14 05:51:22 15-Nov-14 05:52:05 15-Nov-14 05:52:48

Fre

qu

en

cy (

Hz)

Time

Pole 2 Trip Event 15/11/2014

P:BENPMU0582.FREQ

P:HAYPMU0592.FREQ

P:HAYPMU0842.MW

P:HAYPMU0922.MW

MW

-50

0

50

100

150

200

250

48.6

48.8

49

49.2

49.4

49.6

49.8

50

50.2

50.4

50.6

15-Nov-14 06:11:31 15-Nov-14 06:13:15 15-Nov-14 06:14:59

Fre

qu

en

cy (

Hz)

Time

Pole 3 Stop Event 15/11/2014

P:BENPMU0582.FREQ

P:HAYPMU0592.FREQ

P:HAYPMU0842.MW

P:HAYPMU0922.MW

MW


72

Figure 38 NI generation trip event 06/01/2015

Figure 39 NI generation trip event 23/02/2015

-270

-250

-230

-210

-190

-170

-150

49.3

49.4

49.5

49.6

49.7

49.8

49.9

50

50.1

50.2

06-Jan-15 13:45:50 06-Jan-15 13:46:34 06-Jan-15 13:47:17

Fre

qu

en

cy (

Hz)

Time

NI Generation Trip Event 06/01/2015

P:BENPMU0582.FREQ

P:HAYPMU0592.FREQ

P:HAYPMU0842.MW

P:HAYPMU0922.MW

MW

-180

-160

-140

-120

-100

-80

-60

-40

-20

0

20

49.4

49.5

49.6

49.7

49.8

49.9

50

50.1

50.2

50.3

23-Feb-15 01:50:53 23-Feb-15 01:51:36 23-Feb-15 01:52:19

Fre

qu

en

cy (

Hz)

Time

NI Generation Trip Event 23/02/2015

P:BENPMU0582.FREQ

P:HAYPMU0592.FREQ

P:HAYPMU0842.MW

P:HAYPMU0922.MW

MW


73

APPENDIX D – POSITIVE TIME ERROR TREND

This appendix discusses some potential causes of the positive time error trend

investigated throughout the FKC trial. Most of the analysis was completed using PI data

which presents some difficulties:

when assessing historical data it is difficult to determine which behaviour occurs

naturally from the system and which behaviour is due to co-ordinator

intervention. Even if it could be inferred from the data, isolating that information

when looking at data statistically is difficult

PI data time stamps are not aligned completely so certain correlations may not be

represented correctly.

During the trial it was noted at times that time error appeared to increase more during

periods in which load was decreasing. This appears logical as when load is ramping

down generation will react to frequency increase due to the reduced load and adjust

MW’s accordingly. If this occurs continuously over an extended period of time the

momentary frequency increase would accumulate into an increasing time error.

To assess this, data from 16/10/2014 to 13/01/2015 was analysed during the periods

when FKC was on. A rate of change of load (∆𝑀𝑊

𝑑𝑡) – MW value normalized against peak

for the day - and a rate of change of time error (∆𝑇𝑖𝑚𝑒𝐸𝑟𝑟𝑜𝑟

𝑑𝑡) was taken for each time

instant and plotted against one another.

Note that ∆𝑇𝑖𝑚𝑒𝐸𝑟𝑟𝑜𝑟

𝑑𝑡 here is not frequency, it is the rate of change of time error trend from

PI data at a scale which is not meaningful to translate back to frequency values.

For this theory to have weight, we expect to see an approximately inverse linear

relationship between ∆𝑀𝑊

𝑑𝑡 and

∆𝑇𝑖𝑚𝑒𝐸𝑟𝑟𝑜𝑟

𝑑𝑡. Figure 40 and Figure 41 show

∆𝑇𝑖𝑚𝑒𝐸𝑟𝑟𝑜𝑟

𝑑𝑡 vs

∆𝑀𝑊

𝑑𝑡

plots for single days from the period mentioned above. Here a very rough trend can be

observed representing what is expected. Many other days were looked at and the trend

was not evident at all.

Figure 42 shows the ∆𝑇𝑖𝑚𝑒𝐸𝑟𝑟𝑜𝑟

𝑑𝑡 vs

∆𝑀𝑊

𝑑𝑡 plot for the whole period, here it is difficult to say

that a trend is observed.


74

Figure 40 Rate of change of time error vs the rate of change of normalized MW over day 5/01/2015

Figure 41 Rate of change of time error vs the rate of change of normalized MW over day 14/01/2015

-0.02 -0.015 -0.01 -0.005 0 0.005 0.01 0.015 0.02-0.8

-0.6

-0.4

-0.2

0

0.2

0.4

0.6

Rate of change of MW (normalized)

Rate

of

change o

f T

ime E

rror

-0.04 -0.03 -0.02 -0.01 0 0.01 0.02 0.03 0.04-0.4

-0.2

0

0.2

0.4


Rate

of

change o

f T

ime E

rror


75

Figure 42 Rate of change of time error vs the rate of change of normalized MW

North Island industrial load has a significant effect on frequency behaviour. Time periods

were analysed with certain North Island industrial loads on and off and the effect on time

error deviation has been assessed. The periods North Island industrial loads are not

operational are weekends and the Christmas / New Year period.

The data, both with and without this North Island industrial load, shows:

the absolute value of the maximum time error is significantly larger than the

minimum

significantly more time is spent with time above 1 second than below 1 second

the ratio of time positive compared to time negative in each island is not

materially affected by the North Island industrial load.

The differences observed with and without North Island industrial load are:

standard deviation is significantly lower for both the North Island and South

Island with North Island industrial load off

time error barely exceed 2 seconds with North Island industrial load off

time error spends significantly more time greater than 1 second with North Island

industrial load on than with North Island industrial load off

Other conclusions may be drawn from the data, but it is difficult to determine what is

influenced by system co-ordinator intervention and what the power system’s natural

behavior is. Overall we can say that although North Island industrial load aggravates the

situation, the same pattern is observed even when the load is off.

-0.05 -0.04 -0.03 -0.02 -0.01 0 0.01 0.02 0.03 0.04-0.8

-0.6

-0.4

-0.2

0

0.2

0.4

0.6

0.8

1


Rate

of

change o

f T

ime E

rror


76

Table 21 Time Error Statistical Analysis NI/SI with North Island industrial load on and off

NI - North

Island

industrial load

Off

SI - North

Island

industrial load

Off

NI - North

Island

industrial load

On

SI - North

Island

industrial load

On

max 1.968 2.325 2.865 2.878

min -1.365 -1.295 -2.059 -2.014

average 0.000 0.137 0.096 0.246

median -0.020 0.122 0.014 0.157

standard

deviation

0.363 0.382 0.535 0.525

data points

(PI data 1

minute

resolution)

25445 25445 36005 36005

time above

2s %

0.00% 0.10% 0.41% 0.59%

time above

1s %

0.61% 1.72% 6.22% 8.18%

time positive

%

47.51% 63.98% 51.54% 67.61%

time

negative %

52.49% 36.02% 48.46% 32.39%

time below

1s %

0.13% 0.66% 1.44% 0.56%

time below

2s %

0.00% 0.00% 0.01% 0.00%

Asymmetries in governor gate opening/closing may rates cause a difference in

over/under frequency correction speed.

Some governors may have faster or slower gate opening rates than closing rates which

could affect the rate at which frequency was corrected whether it was high or low. If a

significant number of governors had slower closing rates than opening rates, over-

frequency would be corrected slower and hence accumulate into an increasing frequency

Looking into the governor models, this was not found to be so. For most governors

which had different opening and closing rates, they had faster closing than opening

rates. If they were having an effect faster closing rates would lead to a negative rather

than positive trending time error.

To examine whether the change in load was causing the time error issue a dynamic

power flow was undertaken in TSAT.


77

In the power flow a load was stepped up, allowing the frequency to settle, then stepped

down. This was done repeatedly over about 600 seconds. The time error was extracted

from the data and not found have an increasing trend.

Figure 43 is an example of the simulation stepping Stoke-33 load up by 45 MW, and

down by 45 MW. This is done repeatedly in 60 second intervals over about 700 seconds.

Figure 43 shows the frequency, time error, and one of the two Stoke 33 active power

loads simulation results.

Looking at the frequency and time error plots, we can see there is no significant creeping

of time error and frequency stays roughly centred at 50 Hz.

The results show that, in the simulation, there was no link between FKC, load steps and

time error trending positive was found.

Figure 43 TSAT STK33 Load step simulation frequency, time error and STK33 load results


78

Other matters were considered and determined to have no conclusive link to the time

error issue:

MFK dead band:

the effect of the MFK dead band was considered. It was hypothesised

the time spent above/below 50 Hz and inside the MFK dead band may

contribute to accumulating time error

it was found the amount of time frequency was between 50 Hz and

within the 0.01 Hz MFK dead band was insignificant and could not be

contributing to accumulating time error.

the daily peak trend:

the daily peak trend was trending downwards towards the summer

trough period over Christmas and New Year. The load trending

downwards was analysed for an effect on time error trending positive.

No data suggested that the daily peak trend is a plausible cause.


79

APPENDIX E - USING HVDC FREQUENCY OFFSET FROM

HMI TO MINIMISE TIME ERROR DIVERGENCE

As discussed in section 8.3, North and South Island time errors diverged consistently

during the FKC trial. While they consistently diverged, the gradient at which they

diverged was consistent for only a few days at a time. It is still unclear what affects the

gradient at which the time errors diverge. However, it has been observed the rate

remains consistent over extended periods of time.

During the FKC trial, whenever the time errors were separated by a significant amount a

10 mHz frequency offset in the HVDC HMI was applied to one of the island frequency

sources used by the HVDC. This caused the time error between the two islands to rapidly

converge. On the 27th December 2014, a 1 mHz offset was applied to attempt to counter

the time error divergence and prevent it from occurring at all, or at least reduce the

gradient as much as possible.

Looking at the data a gradient of time error divergence can be taken which can be back-

calculated to a constant frequency difference between the two islands. The formula

below describes the relationship between time error divergence and equivalent frequency

offset. The unit seconds/day for time error divergence has been chosen as it is

convenient for interfacing with MS Excel time format where “1” represents one day.

∫𝑓𝑒𝑞𝑢𝑖𝑣𝑎𝑙𝑒𝑛𝑡 𝑜𝑓𝑓𝑠𝑒𝑡

50𝑑𝑡 = 𝑇𝑖𝑚𝑒_𝐸𝑟𝑟𝑜𝑟_𝐷𝑖𝑣𝑒𝑟𝑔𝑒𝑛𝑐𝑒 (

𝑠𝑒𝑐𝑜𝑛𝑑𝑠

𝑑𝑎𝑦)

𝑆𝑒𝑐𝑜𝑛𝑑𝑠 𝑖𝑛 𝑑𝑎𝑦

0

On 27/12/2014 a 1 mHz offset was applied to the HVDC frequency offset. Looking at the

gradients we can analyse its effect. The following discussion is based on the data

presented graphically in Figure 44.

The initial gradient of time error divergence is -1.55 seconds/day. This corresponds to a

frequency offset of approximately -0.902 mHz.

A 1 mHz frequency offset was applied which resulted in time error drifting the opposite

direction at a measured rate of 0.13 seconds/day which is equivalent to a frequency

offset of about 0.075 mHz. This is expected as 0.075 + 0.902 = 0.977 mHz, which given

the noise in the measured gradient is close enough to the 1 mHz offset which was

applied to the HMI.

The gradient then changed at about midday on 28/12/2014 to 1.93 seconds/day which

corresponds to a frequency offset of about 1.115 mHz. The 1 mHz offset was then

removed and a gradient of 0.068 seconds/day was measured, corresponding to a

frequency offset of about 0.039 mHz. Once again this is expected, as 1.115 – 0.039 =

1.076 mHz which basically corresponds to the 1 mHz offset applied to the HMI. The

remaining 0.076 mHz is likely due to fluctuation in the 1.115 mHz measurement data, as

it is a short measurement time, the fluctuation has a greater impact on the accuracy of

the calculated gradient.


80

Figure 44 Time error trend with 1 mHz offset applied 26/12/2014 – 30/12/2014

From this we can deduce the HVDC frequency offset input can be used to counter time

error divergence and will be effective.

Even before the offset was applied, the rate of divergence was very high and required

converging multiple times a day. The minimum offset of 1 mHz was still too course to

balance it out accurately. With lower rates of divergence this will be more of an issue.

Applying a frequency offset to the HVDC control can be effectively used to counter time

error drift. Also discussed in Appendix E - Using HVDC frequency offset from HMI to

minimise time error divergence was that the minimum 1 mHz step is too course to

provide for all but the most severe time error divergence gradients.

To allow the time error divergence gradient to be countered in a more refined way, an

update to the HVDC HMI is currently underway to allow decimal places to be input in the

“Frequency Offset from HMI” input fields (shown in Figure 45). The HVDC control system

was assessed for capability to be able to accurately process inputs in the µHz range, so

all that is required is to update the input field to accept decimal places.

Unlocking this capability will allow more accurate adjustments to be made. For example,

in the case study discussed in Figure 44, an offset of 0.9 mHz would have countered the

time error divergence to almost 0 seconds/day, rather than sending it in the opposite

direction at a reduced rate. More importantly, it would allow lower gradients of time

error divergence to be countered effectively.


81

Figure 45 HVDC HMI frequency offset to be adjusted

A tool is being developed to streamline the calculation of the correct value to be input

into the HVDC frequency offset field. When implemented the tool will automatically

generate a recommended value based on time error PI data. It will be made available to

system co-ordinators and provide consistent methodology for managing the time error

divergence issue.

Documents

Frequency Keeping Control Trial Technical Review Report