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SA SUBSTATION MANAGEMENT SYSTEMS (TELEMETRY SYSTEMS) Fleet Strategy © Transpower New Zealand Limited 2013. All rights reserved. of 52

SA SUBSTATION MANAGEMENT SYSTEMS (TELEMETRY SYSTEMS)

Fleet Strategy

Document TP.XX xx.xx

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SA Substation Management Systems (Telemetry Systems) Fleet Strategy TP.FP 12.01 Issue 1 November 2013

SA SUBSTATION MANAGEMENT SYSTEMS (TELEMETRY SYSTEMS) Fleet Strategy © Transpower New Zealand Limited 2013. All rights reserved.

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SA Substation Management Systems (Telemetry Systems) Fleet Strategy TP.FP 12.01

Issue 1 November 2013

SA SUBSTATION MANAGEMENT SYSTEMS (TELEMETRY SYSTEMS) FLEET STRATEGY © Transpower New Zealand Limited 2013. All rights reserved.

Table of Contents

EXECUTIVE SUMMARY ...................................................................................................................... 1

SUMMARY OF STRATEGIES .............................................................................................................. 4

1 INTRODUCTION ....................................................................................................................... 5

1.1 Purpose ................................................................................................................................. 5

1.2 Scope .................................................................................................................................... 5

1.3 Stakeholders ......................................................................................................................... 5

1.4 Strategic Alignment ............................................................................................................... 6

1.5 Document Structure .............................................................................................................. 6

2 ASSET FLEET .......................................................................................................................... 7

2.1 Introduction to Telemetry Systems ....................................................................................... 7

2.2 Asset Statistics .................................................................................................................... 10

2.3 Asset Characteristics .......................................................................................................... 12

2.4 Asset Performance .............................................................................................................. 14

2.5 Risks and Issues ................................................................................................................. 15

2.6 Benefits of Substation Management System Technology .................................................. 17

3 OBJECTIVES .......................................................................................................................... 21

3.1 Safety .................................................................................................................................. 21

3.2 Service Performance ........................................................................................................... 21

3.3 Cost Performance ............................................................................................................... 22

3.4 Asset Management Capability ............................................................................................ 22

4 STRATEGIES.......................................................................................................................... 24

4.1 Planning .............................................................................................................................. 24

4.2 Delivery ............................................................................................................................... 30

4.3 Operations ........................................................................................................................... 32

4.4 Maintenance ........................................................................................................................ 34

4.5 Disposal and Divestment .................................................................................................... 35

4.6 Asset Management Capability ............................................................................................ 36

4.7 Summary of RCP2 Fleet Strategies .................................................................................... 40

APPENDICES ..................................................................................................................................... 42

A GLOSSARY OF ACRONYMS ................................................................................................. 43

B OPTIONS EVALUATION – COST BENEFIT ANALYSIS ....................................................... 44



SA SUBSTATION MANAGEMENT SYSTEMS (TELEMETRY SYSTEMS) FLEET STRATEGY © Transpower New Zealand Limited 2013. All rights reserved. Page 1 of 41

EXECUTIVE SUMMARY

Introduction

Substation telemetry systems enable the remote control and monitoring of our substations. The reliability of these telemetry systems is essential to maintaining visibility and control of the transmission network.

The operation of the transmission Grid increasingly requires a range of advanced capabilities that demand enhanced communications and data management functions at substations. Our future substation telemetry systems will be key elements in providing this improved Grid capability.

Our asset management approach for substation telemetry seeks to achieve high standards of reliability, and to provide the capability required to meet emerging Grid needs.

Asset overview

Our existing substation telemetry systems are based on remote terminal units (RTUs). The RTU provides the data gathering and communications capability at the substation. It is used to monitor digital and analogue signals from substation equipment, and to transmit indications to a control centre. The RTU also provides the pathway at the substation for commands from the remote control centre to be directed to substation equipment, such as for opening and closing circuit breakers.

We currently have approximately 304 RTUs in service at 178 sites. There is significant diversity within our RTU fleet, with five different models in service. The fleet is ageing, with more than half of all RTUs more than 10 years old. For some older models of RTU, it is no longer possible to procure new spare components, and existing spares are depleted.

RTU failures are currently occurring at an average rate of approximately one every six weeks. These failures are of significant concern because of the potential impacts of the loss of real-time monitoring and control capability on Grid reliability, safety and the System Operator’s role in the electricity market. Reliability performance of existing RTUs is forecast to decline over time.

In many cases, the existing RTUs are also reaching the limits of their capacity, and this is becoming a constraint on our ability to monitor power system equipment. The loading of RTUs has increased significantly over the past 10 years as a result of the progressive replacement of electromechanical protection relays with modern numerical relays.

These numerical relays have a wide range of functional capability, and produce far more signal outputs than the previous relay technology. The additional signals available from modern relays are valuable to Grid operators and engineers, but cause increasing load on the RTUs. Capacity constraints are becoming a significant driver for RTU replacement.

Enhanced Grid capability requirements

Customer’s expectations for the reliability of the transmission system are increasing, but at the same time there is a need to obtain maximum value from existing transmission primary plant, and defer or avoid major new investments. A range of technical solutions are emerging that will allow increased utilisation of the Grid, and improved responsiveness when faults or incidents occur.




Many of these new solutions require high-speed communications and data management between equipment at sites, and between sites and central control and monitoring facilities. These increasing demands for data communications and management have significant implications for our existing RTU-based substation telemetry systems.

One key requirement for improved responsiveness and performance is remote engineering access (REA) to the protection relays and other intelligent devices at substations. At present, our RTU-based telemetry systems cannot provide REA to these devices in an appropriately standardised and efficient manner.

Emergence of substation management system technology

Substation Management Systems (SMS) are a new generation of substation telemetry that can replace RTUs. SMS is based on an industrial-grade computer and a local area network (LAN) that is designed for operation in the substation environment. The SMS communicates with intelligent electronic devices (IED)1 in the substation, via the LAN, and with the remote control centre via broadband communications, typically fibre optic networks.

SMS technology facilitates a high level of standardisation in configuration and management of substation data systems, and includes the capability for REA to IEDs as a standard feature. Five benefits of SMS are noted below.

REA to substation IEDs allows for technical experts to remotely access the IEDs without having to be present at the substation. This facilitates prompt analysis of data following a fault, and enables faster response and restoration of supply to our customers.

Access to richer asset condition information, such as online transformer dissolved gas analysis, can provide us with advanced warning of a transformer failure.

SMS provides improved utilisation of primary assets through better information such as online temperature monitoring of transformers, local weather information allowing the wider implementation of dynamic line rating, and extended implementation of phasor measurements to monitor power system stability.

SMS reduces SCADA system loading through the ability to split operational data from non-operational data.

SMS is a standard platform for information-rich applications such as power quality (PQ) meters and transient disturbance recorders.

These opportunities from SMS technology are important enablers for achieving our vision of a flexible, efficient and resilient Grid as expressed in our long-term strategic document Transmission Tomorrow.

1 Intelligent electronic devices (IEDs) are devices that receive and send communication to primary equipment, such as

protection relays.




Substation telemetry strategies

The existing RTU telemetry fleet will require replacement to ensure continued high levels of reliability and to meet capacity requirements. Yet replacing RTUs on a like-for-like basis will not meet the increasing needs for enhanced data communications and management capability at substations.

Our strategy is to continue the progressive deployment of SMS as replacements for the existing RTUs, with a staged approach to be completed by 2025. The programme of SMS installation began in 2011/12.

We have developed a standard design for SMS, and commissioned our first installation. An initial programme of SMS installations has commenced that will replace RTUs at 46 sites in the RCP1 period.

Sites scheduled for implementation of SMS are prioritised based on the condition and functional capability of the existing RTU, and the specific benefits at the site that can be obtained through an SMS. The scope of work includes the procurement and installation of software required to support new standard communication protocols at substations.

During the RCP2 period, we will continue our programme of replacing RTUs with SMS at a further 70 sites, at a total forecast cost of approximately $47m.




SUMMARY OF STRATEGIES

The following summaries include the main strategies and their respective costs during the RCP2 period (2015/16–2019/20).

Capital expenditure

SMS Implementation RCP2 Cost $45.3m

Our existing telemetry fleet is based on Remote Terminal Unit (RTU) technology, which has limited capability compared to Substation Management System (SMS) technology. Over half of the current fleet of RTUs are more than 10 years old, and many have capacity limitations that are constraining our ability to monitor primary equipment.

Implementing SMS technology will significantly improve communications between and within our substations, which in turn will improve our capability to manage our assets. SMS will provide us with the data and access to devices we need to manage our assets more effectively.

Our strategy is to undertake a progressive, staged replacement of RTU-based telemetry systems with SMS telemetry systems. Cost-benefit analysis concludes that the implementation of SMS is similar in cost to retaining RTUs, but the benefits that SMS will provide make it the preferred option. The programme of replacing RTUs with SMS has already commenced, and we will expect to complete 46 sites during the RCP1 period.

During the RCP2 period, we will continue our programme of replacing RTUs with SMS at a further 70 sites, at a forecast cost of $45.3m.

IEC 61850 – Introduce New Intra-substation Communications Networks

RCP2 Cost $1.6m

Introducing a ‘hardened’ intra-substation communications network that meets international standards (IEC 61850) along with proprietary software on the corporate server will support REA and facilitate connection and configuration of a wide range of intelligent electronic devices (IEDs). It will also enable faster and cheaper fault response.

This strategy includes RCP2 expenditure of $1.6m. This is mainly for the software required to implement IEC 61850.

Chapter 4 has further details on these strategies and a discussion of the remaining strategies.




1 INTRODUCTION

Chapter 1 introduces the purpose, scope, stakeholders, and strategic alignment of the substation telemetry systems fleet strategy.

1.1 Purpose

We plan, build, maintain and operate New Zealand’s high-voltage electricity transmission network (‘Grid’). An important part of that infrastructure is the telemetry systems, which are used by our operators, engineers and service providers to monitor and control power system equipment.

The purpose of this strategy is to describe our approach to lifecycle management of the telemetry system assets. This includes objectives for future performance and strategies being adopted to achieve these objectives. The strategy sets the high-level direction for fleet asset management activities across the lifecycle of the asset fleet. These activities include Planning, Delivery, Operations, and Maintenance.

This document has been developed based on good practice guidance from internationally recognised sources, including BSI PAS 55:2008.

1.2 Scope

The scope of the strategy includes the following telemetry system assets:

Remote Terminal Units (RTUs) and associated peripherals

Control centre software for interfacing with RTUs

Time Synchronisation Clock (GPS clock).

1.3 Stakeholders

Substation telemetry systems enable the remote control and monitoring of our substations, and are essential for the operation of the transmission network and the electricity market.

Key stakeholders include:

relevant Transpower groups: Grid Development, Grid Performance, System Operations, IST and Grid Projects

regulatory bodies: Commerce Commission and Electricity Authority

generators

service providers

customers, including distribution network businesses.




1.4 Strategic Alignment

A good asset management system shows clear hierarchical connectivity or ‘line of sight’ between the high-level organisation policy and strategic plan, and the daily activities of managing the assets.

This document forms part of that connectivity by setting out our strategy for managing telemetry equipment to deliver our overall asset management strategy in support of the asset management policy. The hierarchical connectivity is represented graphically in Figure 1. It indicates where this fleet strategy fits within our asset management system.

Figure 1: Position of this Strategy within the Asset Management Hierarchy

1.5 Document Structure

The rest of this document is structured as follows.

Chapter 2 provides an overview of telemetry assets including fleet statistics, characteristics and their performance.

Chapter 3 sets out asset management related objectives for the assets. These objectives have been aligned with the corporate and asset management policies, and with higher-level asset management objectives and targets.

Chapter 4 sets out the fleet specific strategies for the management of the assets. These strategies provide medium-term to long-term guidance and direction for asset management decisions and will support the achievement of the objectives in chapter 3.

This fleet strategy makes use of a number of acronyms. An explanation of these acronyms is provided in Appendix A. Additional appendices are included that provide further detailed information to supplement the fleet strategy.

SMS Plan

SMS Strategy

Corporate Objectives & Strategy

Asset Management Policy

Asset Management Strategy

Lifecycle Strategies

DeliveryPlanning Operations DisposalMaintenance




2 ASSET FLEET

Chapter 2 provides a high-level description of the telemetry system fleet assets, including:

Overview of the fleet: explains the concepts of telemetry systems to give readers an understanding of the asset fleet and its function

Asset statistics: including population, diversity, age profile, and spares

Asset characteristics: including safety and environmental considerations, asset criticality, condition, and maintenance requirements

Asset performance: including reliability, safety and environmental, and risks and issues.

2.1 Introduction to Telemetry Systems

This section provides a brief overview of the purpose and function of telemetry systems, and describes the different technologies that are available.

RTU telemetry

Our existing substation telemetry systems are based on RTUs. The RTU provides the data gathering and communications capability at the substation. It is used to monitor digital and analogue signals from substation equipment, and transmit indications to a control centre. The RTU also provides the pathway at the substation for commands from the remote control centre to be directed to substation equipment, such as for opening and closing circuit breakers.

The RTUs at each substation communicate with a central host system that serves the main control centre. The remote control system as a whole is often referred to as a Supervisory Control and Data Acquisition (SCADA) system.

Illustrations of RTU-based telemetry systems are presented in Figure 2 and Figure 3.

When substation telemetry was first installed in the mid-1980s, the amount of data being relayed to the control room was usually limited to:

circuit breaker status (open, closed)

circuit breaker volts, amps

protection relay ‘flag’ status

ancillary system status (battery system and so on)

fire and intruder alarm status.

Most of the interfaces between the substation plant and the RTU were via direct connection of devices (such as circuit breaker status) and analogue inputs (such as circuit breaker voltage and current).

The modern technology of IEDs in substations provides greatly improved functional capability. These IEDs provide far more signals than the previous electromechanical protection relays, and the signal loading can be a significant issue for RTU processor capacity.




Figure 2: RTU-based telemetry system

Figure 3: Simplified RTU connection diagram




SMS telemetry

RTU technology is being superseded by a technology commonly referred to as ‘Substation Management Systems’ or SMS. The term is loosely used to describe a telemetry system that uses computers and LANs that have been designed specifically (hardened) to operate in electricity utility environments.

The implementation of SMS includes LANs between IEDs in the substation, and allows for very fast communication between devices. This enables new applications such as special protection schemes (SPS) and advanced protection schemes. It also allows for IEDs such as online dissolved gas analysis (DGA) for transformers and weather stations for dynamic line rating (DLR) to be easily connected to the LAN.

At the control centre, the implementation of SMS allows data streams to be separated from each other. This means that SCADA data required by operators to control the power system is split from engineering data. The benefit of this is ‘unloading’ of the SCADA server, which at present is processing SCADA data and engineering data.

The most immediate benefit of SMS is the provision of REA to substation IEDs. This allows the retrieval of information captured by IEDs without having to be present at the substation, and facilitates prompt analysis of data following a fault. This in turn enables faster response and restoration of supply to customers. At present, the only way to access these devices is by connecting a PC directly to them at the substation.

Figure 4 illustrates the salient differences between RTU and SMS telemetry systems.

Figure 4: Comparison of RTU and SMS topology




2.2 Asset Statistics

This section includes information on asset fleet population, along with their diversity and age profiles. These statistics and the associated risks are discussed in the following subsections.

2.2.1 Asset Population

Remote terminal units

As at June 2013 we have 178 sites2 where telemetry equipment is installed. Most of these sites are Transpower-owned substations or switching stations. However, some of the sites are owned by other parties, but have equipment that we are required to monitor. For example, Contact Energy owns a number of synchronous condensers at their site at Otahuhu that are used to provide reactive support to the Grid. We have telemetry installed at the Contact Energy site, to allow us to monitor the status of these condensers.

The 178 sites include several sites that are scheduled to be divested in the near future.

The fleet of RTUs includes many that were installed in the early days of substation de-manning and some of them date back to the 1980s, with over half of the fleet being older than 10 years. Over the years, many of the original RTUs have been upgraded or replaced with newer models. The size and age of the RTU fleet is provided in Table 1.

Type Age Units in Service

Comments

GE Harris D200 < 6 years 21 Current model

GE Harris D20VME < 6 years 79 Current model

GE Harris D20ME 6 to 8 years 15 No Ethernet

GE Harris D20M++ 8 to 12 years 78 No longer supported; no Ethernet; sometimes referred to as legacy units

Foxboro C50 > 11 years 111 Current model; sometimes referred to as a legacy unit

Total 304

Table 1: RTU Fleet

Time Synchronisation Clock

The substation telemetry fleet includes Time Synchronisation Clock (GPS clock) systems that are used to provide high-precision time tagging of events as they occur at substations.

Substation devices require precise time synchronisation for a variety of reasons, including post-event analysis. IRIG-B is a standardised protocol that we use for our electronic time signalling. Each substation is equipped with a GPS clock to provide the following functionality:

Amplitude Modulated IRIG-B to synchronise legacy type protection device

Un-modulated DC level-shift IRIG-B to synchronise modern substation devices.

2 As some of these sites have more than one RTU installed, the total number of ‘Units in Service’ is substantially more

than the number of sites with telemetry.




2.2.2 Fleet Diversity

Asset fleet diversity is an important consideration for asset management as it can be a driver of additional maintenance costs and risks.

Remote Terminal Units

The chart in Figure 5 shows the diversity of the RTU asset fleet.

Figure 5: Remote Terminal Units – Diversity

Apart from the C50 units, all RTUs use the same input/output modules and are plug compatible with each other (they are not, however, directly interchangeable as they employ different software versions). Only C50, D200, and D20VME units are able to communicate over Ethernet.

GPS clock

The average age of the GPS clock fleet is approximately six years, with the age profile shown in Table 2. The time synchronisation clocks have 10 - year warranties and life expectancies of approximately 15 years. There are four different types of clock in service and central processing units (CPUs) are no longer available for the older types of clock (model A and B) which means they must be replaced if their CPU fails.

Type - Model Age Comment

TCG-01 - A 8 to 12 years Cannot provide Ethernet-based time synchronisation signals.

Replace with clock revision TCG 01–E

TCG-01 - B 6 to 8 years Cannot provide Ethernet-based time synchronisation signals

TCG-01 - D <6 years Cannot provide Ethernet-based time synchronisation signals

TCG-01 - E <2 years Provides Ethernet-based time synchronisation signals

Table 2: Time synchronisation clock age profile

The chart in Figure 6 shows the diversity of the GPS clock asset fleet.

Figure 6: GPS clock – Diversity

D20M++ (28%)

D20ME (5%)

D20VME (25%)

D200 (7%)

C50 (36%)

REMOTE TERMINAL UNIT - DIVERSITY

TCG-01 GPS CLOCK – A (2%)

TCG-01 GPS CLOCK – B (38%)

TCG-01 GPS CLOCK – D (54%)

TCG-01 GPS CLOCK - E (6%)

TIME SYNC CLOCK - DIVERSITY




2.2.3 Spares

Spare component holdings consist mainly of replacement RTU cards to cover the risk of equipment failure. Other types of spare parts for RTUs are not usually held. Equipment is often covered under manufacturer warranty; otherwise it is considered more cost effective to replace faulty equipment.3

Some of the older RTUs (such as D20M++) are becoming obsolete with no spares left and no spares available for purchase. However, it is possible to use the D20ME and D20VME spare parts to replace failed D20M++ units. When doing this, additional configuration work is required.

Spares are held centrally by us and regionally by service providers. This ensures a reasonable geographical spread of spares.

2.3 Asset Characteristics

Telemetry assets can be characterised according to:

safety and environmental considerations

asset criticality

asset condition

maintenance requirements

emerging technologies

interaction with other assets.

These characteristics and the associated risks are discussed in the following subsections.

2.3.1 Safety and Environmental Considerations

Telemetry systems safety includes the following four considerations.

Remote monitoring: Remote monitoring is essential to enable alarms and indications from substations to be notified to the central control centre. Failure of telemetry can lead to potentially dangerous conditions going undetected, leading to the possibility of serious safety consequences.

Remote switching: Telemetry systems allow for switchgear to be operated remotely, in the sense that an operator is not required to stand in front of or next to the switchgear to operate it. This has obvious safety benefits in that should a fault occur on the switchgear during an operation, personnel will not be in harm’s way. This safety benefit usually only applies to situations where switchgear has remote operation capability.

Remote access limitations: An inability to remotely access IEDs and RTUs in a timely manner for fault interrogation and analysis could lead to a potential safety hazard through delayed identification and resolution of a serious fault.

Centralised configuration management: Safety hazards (including primary plant mal-operation) might arise in situations where a lack of a centralised configuration

3 Equipment with warranties includes Tekron clocks, D20VME RTUs, and D200 RTUs. The D20M++ RTUs had warranties

that have expired.




tool leads to configuration errors. For example, an operator at a substation may accidentally operate the wrong device thorough not having visibility of the status of associated plant at a remote substation.

There are no significant environmental issues associated with the management of the telemetry fleet.

2.3.2 Asset Criticality

We have derived a methodology that assesses the impact of the failure of busbars and circuits on the reliability of each customer’s point of service. All busbars and circuits are assigned a criticality of high, medium or low impact, depending on the effect on customers if those network elements are taken out of service.

For some asset fleets, these ‘network’ criticalities have been considered in conjunction with asset health indicators to provide an indication of which assets present our greatest risk. The criticality framework is however at an early stage of development and cannot be applied to the SMS fleet at this stage, because it does not currently provide an assessment of criticality for an entire substation site.

We are developing a wider criticality framework that takes into consideration the impact of individual assets (such as telemetry systems) and additional dimensions (such as safety and environmental risk). The development of the framework is in progress and will continue during RCP2.

2.3.3 Asset Condition

We undertake regular condition assessments for the majority of our asset fleets. For telemetry assets, condition is difficult to assess because the assets are static and are either functioning correctly or have failed (so there is no easily observable degradation in performance that can be used to check on asset condition). Asset condition assessment is therefore limited to a visual inspection of the physical condition of an asset by a qualified employee or service provider. Asset condition information is used to prioritise maintenance work. The plans for asset condition assessments during RCP2 are described in subsection 4.4.1.

2.3.4 Maintenance Requirements

This subsection describes the maintenance requirements of the telemetry fleet, which have informed the maintenance strategies discussed in section 4.4.

The most common types of maintenance carried out on telemetry assets are:

preventive maintenance, including:

- condition assessments

- servicing

corrective maintenance, including:

- fault response

- repairs.

Over the last five years around $33,000 was spent on preventive maintenance each year, while $230,000 was spent on corrective maintenance each year. Further details on the above maintenance works is provided in the Maintenance Lifecycle Strategy.




In addition to the categories of maintenance work above, we also periodically undertake maintenance projects, which typically consist of relatively high-value planned repairs or replacements of components of larger assets. No substantial maintenance projects have been carried out on the telemetry system fleet during the past five years.

2.3.5 Interaction with Other Assets

Telemetry assets are inherently related to substation equipment such as circuit breakers that they monitor and control. The characteristics of the equipment to be monitored or controlled will impact the requirements for telemetry assets.

It is often more efficient (both in terms of cost and reliability) to replace telemetry equipment at the same time as the larger equipment it is interfaced with. Alignment of capital expenditure across our multiple programmes, including the telemetry assets, is managed through the Integrated Works Planning (IWP) process, which is discussed in subsection 4.1.4.

Telemetry systems connect to the IEDs in substations, of which there are a growing number. This growing number of IEDs and the growth in data transfer has put increasing pressure on the existing fleet of RTUs.

2.3.6 Emerging Technologies – the Benefits of SMS

RTUs are ‘first generation’ telemetry systems.

SMS telemetry systems are now being increasingly used by electricity transmission utilities around the world4 as a replacement for RTUs, to interconnect devices at substations and to transmit data back to control centres. SMS is the technology of choice because its capacity, ease of use and standardised connectivity enables many benefits to the utilities.

The benefits of SMS are set out in more detail in section 2.6.

2.4 Asset Performance

This section describes the historic performance of the telemetry systems asset fleet.

2.4.1 Reliability

Achieving an appropriate level of reliability for our telemetry assets is essential because of the impact of telemetry failures.

If an RTU fails, the immediate consequences are the loss of remote control and monitoring capability for the equipment served by the RTU. The loss of remote control and monitoring means:

the Grid owner is unable to fully meet obligations under the Electricity Industry Participation Code to provide real-time information about the status of the Grid assets to the System Operator

the System Operator must make operational and dispatch decisions in the absence of complete information about the Grid, with potentially significant effects on the electricity market

4 For example in Australia, PowerLink, ElectroNet and Ausgrid are installing substation automation systems similar to

those being installed by Transpower.




manual methods may be required to update electricity market models for changes in equipment status, and this can be vulnerable to human errors

the Grid operating centre has no visibility of the status of equipment, and is unaware of any alarms or changes in state (such as the operation of protection systems)

in the event of a tripping, there will be no immediate notification of what has happened, and this will delay response. In addition, attendance at site will be required to investigate and restore the network, but this may involve a considerable response time for personnel to travel to site. By contrast, when remote control is available, manual re-closing of transmission line circuits following a tripping is often undertaken within a relatively short period, provided that information available from distance to fault indication suggests that the fault is not in a populated region.

In some cases, following the failure of an RTU it has been necessary to provide continuous attendance at site until the problem is resolved.

In recent years, RTU failures have occurred approximately once every six weeks on average and have caused a temporary loss of control centre visibility and control of the affected substation. Failed components are generally replaced within 24 hours from store spares.

Failures occur due to a number of reasons. Typically, power supplies, main processors and input/output cards fail. Compared to the D20 series RTUs, C50 RTUs are generally more reliable than the other RTUs.

Failure rates are forecast to increase if the average age of the RTU fleet increases.

We do not have sufficient reliability data for the SMS installations to be meaningful because we are at a very early stage of the SMS deployment programme.

2.4.2 Capacity

In many cases, the existing RTUs are reaching the limits of their capacity, and this is becoming a constraint on monitoring power system equipment.

The RTU processor loading has increased significantly over the past 10 years as a result of the progressive replacement of electromechanical protection relays with modern numerical relays. These numerical relays have a wide range of functional capability, and produce far more signal outputs than the previous relay technology. The additional signals available from modern IEDs are valuable to Grid operators and engineers, but cause increasing load on the RTUs.

Capacity constraints are becoming a significant driver for RTU replacement.

2.5 Risks and Issues

This section discusses issues and risks relating to the performance of the telemetry system assets. Subsection 4.1.2 addresses the risks and issue in the strategy to convert substations from standard RTUs to SMS.

Our existing RTU-based telemetry system no longer meets our business requirements for access to substation data, efficient configuration and management of IEDs, management and capture of real-time data, interoperability and compatibility with the needs of our SCADA system. The consequences of this are provided below.




Vendor support of systems and spares

There are currently about 304 RTUs in service, the majority consisting of ageing devices over 10 years old. The older D20M++ units in particular no longer have spares available from manufacturers. This means that if these units fail, we will be drawing down our stock of spare parts. Once the stock is used up, we will be forced to replace these units.

Situational awareness

Maintenance service providers working at a site only have limited and often disparate situational awareness of the state of the assets and power system. What information they do have is typically obtained from talking directly to Grid asset controllers. The limitations imposed by RTU technology means there are currently very few sites with systems for providing local SCADA functionality to provide maintenance service providers with visibility of the status of Grid equipment.

Bespoke solutions

Bespoke systems have already been installed to provide focused solutions for specific projects. An example of this is the ‘phasor measurement’ project. This project was implemented to gather phasor data from nine different substations and relay it back to Transpower House where a software suite known as ‘Psymetrix’ is used to analyse the data and provide valuable real-time information on power system stability.

The project involved installing hardware at each of the affected substations to allow the phasor monitoring instruments to communicate with the control centre. This hardware included ‘data concentrators’ that are similar to those being planned for installation as part of the standard SMS solution. The cost of providing and installing the data concentrators at the nine sites for the phasor measurement project was approximately $450,000.

The scope and capability of the equipment installed for the phasor measurement project was tailored specifically to the needs of the project (it enabled two new high-speed data measurements for each site), and there is limited scope to use this new hardware for other purposes.

The standard SMS solution allows for the phasor measurement to be implemented without the need for new substation hardware.

Diversity

The number of different models of RTU used in the existing system causes inefficiency, because of the requirement for a wide diversity of maintenance expertise and spares. Installation of standardised SMS telemetry systems across the majority of our substations will reduce fleet diversity.

Data bandwidth constraints

The bandwidth afforded by existing technologies used for serial communications within substations, typically between 2400 and 9600 baud, places severe constraints on the amount of data that can be transferred between devices and the telemetry system within the substation. These constraints will be removed with the implementation of inter-substation Ethernet-based communications as a standard feature of the deployment of SMS and the IEC61850 protocols.

Our new nationwide communications network ‘TransGo’, provides high-speed, high-capacity fibre optic communications between our control centres and our substations. However, existing communication arrangements within substations constrains our ability to make full use of the TransGo network. These limits prevent engineers from accessing the data sources




that are available in the field, and this has detrimental impacts on our performance in post-event analysis and asset maintenance.

2.6 Benefits of Substation Management System Technology

This section sets out the main benefits of deploying SMS, which support the operation, performance, and management of our primary assets in line with our long-term vision of a flexible, efficient and resilient Grid as described in Transmission Tomorrow.

Remote Engineering Access

REA is a feature of SMS that allows technicians and protection engineers to access IEDs such as the numerical protection relays we have at most of our substations, without having to be present at the substation.

Most of our protection relays (IEDs) have inbuilt ‘disturbance recorders’ that are automatically triggered by power system events to gather data, which is invaluable for post-fault analysis. At present, this type of event information can only be retrieved by sending maintenance staff to site so they can plug their computers into the relay and download the data. Those staff then have to email the data to a protection engineer who can study the data to help determine what caused the fault, and/or where the fault may have occurred. This process can result in delays of hours between the event occurring and the data being made available to the protection engineer.

Further, the IEDs have limited capacity to store event information. So, if it is not retrieved promptly, there is risk that multiple events will cause the oldest event data in an IED to be overwritten and lost forever. If this data is available immediately to the protection engineer, then decision making will speed up and allow a more rapid restoration of supply. Retrieving and storing data for all events will also allow better post-fault analysis to be carried out.

REA facilitates faster and cheaper fault response, and will allow some failures to be addressed remotely. The immediate benefit will be more rapid supply restoration for our customers following an interruption.

Some preventive maintenance tasks will also be able to be carried out remotely once REA is available. It will be possible to provide expert remote support to the service provider at the substation where previously on-site presence was required.

In summary, REA will provide us with a wealth of timely information, including fault data, device configurations and routine data. It will provide the following five benefits.

Loss of supply incident restoration times can be reduced by remotely accessing fault event information from protection IEDs to aid decision making without having to wait for a service provider to travel to the site.

Many outages caused by IED or telemetry configuration faults (such as an incorrect setting in a relay) can be addressed without needing to travel to site. This ensures a much faster return to service while also avoiding the high costs associated with call outs to site.

Device configurations can be recorded and reported on using centralised tools without the need to undertake site-by-site audits or relying simply on documentation.




Any routine task associated with telemetry or IEDs that has an acceptable risk profile (for example, by checking IED fault logs) can be completed in its entirety from a remote location, without the need to send service providers to site.

Remote support can be efficiently provided to on-site staff, allow other service providers and our engineers to be more fully engaged in site works without the need to be on site. This means that even projects separated by great distances can be sustained by a single resource without the need to travel.

Better asset condition information

SMS will provide us with real-time condition monitoring information that is presently constrained by the capacity of our telemetry system. This information may include:

transformer dissolved gas analysis (DGA)

transformer oil temperature analysis

distributed temperature sensing (DTS) of cables

circuit breaker gas pressure.

There is currently only a very limited capability to appropriately use asset condition monitoring devices, despite their availability. This makes it difficult to deliver just-in-time targeted maintenance services and has a direct impact on the longer-term planning and management of asset maintenance programmes.

To support compliance with modern industry best practice, appropriate asset monitoring data will be identified, exported and reported. This will facilitate the regular and automated asset condition and performance assessments that are needed to:

identify assets requiring urgent maintenance, early life reconditioning or replacement

find assets where preventive maintenance can be deferred

detect assets that are consistently underperforming, where remediation work is required

undertake proactive environmental monitoring (such as managing sulphur hexafluoride (SF6) gas).

Reduction in telemetry installation and configuration costs

Our RTU-based telemetry systems usually use different communication protocols from the devices with which they have to communicate. This requires protocol converters to be installed to get the systems running. In some cases, bespoke protocol converters are developed specifically for peripherals that are new to us.

RTU systems need to be individually designed and configured for the sites they are installed at. This requires off-site and on-site technician time. The wiring of new devices to RTU systems involves installing point-to-point connections between the devices and the RTU.

SMS reduces installation costs through the use of standardised cabling and communications protocols along with the ‘plug and play’ feature these protocols allow. Many aspects of the setup and commissioning of SMS telemetry are automatic, so the setup and commissioning times are much lower than for comparable RTU-based systems. These benefits are realised for the commissioning of new sites, and for the addition of new peripherals at existing sites.




IEC 61850 intra-substation communications, and centralised configuration management

IEC 61850 is a substation automation standard that specifies a defined data model, a standard naming convention and an engineering process that integrates prescribed format input files into a design. It will standardise communications between devices inside a substation. It allows for ‘plug and play’ functionality, enforcing/facilitating design and automatic configuration. This will enable time and cost savings, by avoiding the current manual design and configuration activities. High-capacity data cabling is used to form the network connection between the individual substation devices and the SMS computer.

SMS telemetry facilitates and supports the implementation of IEC61850.

Reduced maintenance costs

Replacing the existing RTUs with SMS will lower the overall age of the fleet and reduce the diversity of the fleet. This will lead to reduced maintenance costs for our telemetry systems fleet.

Reduced SCADA system loading

The primary role of the SCADA system is to provide system operators with real-time visibility and control of substation assets such as circuit breakers and disconnectors. Over time however, the SCADA system has begun to be used for non-operational data gathering. Non-operational data includes information that is not required by the operators, but is useful for other staff such as maintenance engineering personnel and power system modellers. Gathering and storing this non-operational data is adding to the load on the SCADA system.

Loading is an issue because the SCADA system uses proprietary software and dedicated hardware. Every data point that is ‘bought back’ from the substations, even the non-operational data, uses up this software and hardware capacity. When capacity limits are reached, additional software licences and more hardware is required. SCADA system expansions are risky, disruptive and costly for the system operator. A reduction in data needlessly going to the SCADA system will permit the following:

reduction of (or at least a freeze on) the SCADA database size, saving on AREVA licensing and maintenance fees which are currently calculated on this basis

greater ease of SCADA database maintenance, as the growing database size increases complexity and the hours required to undertake tasks

reduction in the number of nuisance alarms (generated by the non-operational data) that regional operators have to deal with on a daily basis

longer-term savings on hardware as server CPU, memory and disk use rates are reduced.

Streamlined data retrieval for engineering analysis and asset management

SMS allows for automated data retrieval. The systems that are installed along with SMS include software tools for automatically filtering and formatting data, resulting in faster and less resource-intensive data retrieval than is possible at present using the RTU-based telemetry system.

The current telemetry system produces inconsistent datasets from substations. Values measured at one site may not be available at another, while being duplicated at a third site. Similarly, there are inconsistencies in naming, accuracy, dead banding and reliability. The




standardisation of data requirements that will occur with the introduction of SMS will ensure consistent datasets can be reliably returned from our assets without unnecessary duplication. Further, the use of consistent naming standards will allow data to be managed in a consistent manner inside the substation and the office.

There are likely to be other benefits that will be realised over time as awareness of the possibilities that SMS provides are realised by engineering and maintenance staff. One example that illustrates the possible areas where SMS may enable use of new data streams includes the analysis of PQ issues.

At present, PQ data gathering is carried out on an ad hoc basis, using a small fleet of portable PQ meters fitted with mobile phone transmitters. The PQ meter will automatically phone a central data repository to dump its data after an event. Transfers can be slow due to the size of the data files; so the resolution of the data is often reduced to control file size. SMS would allow PQ meters already available inside many of our IEDs to be regularly transmitting high-resolution PQ data to a central repository, and so giving engineers access to a rich data source that is presently not possible to attain.

Improved utilisation of primary assets

The amount of data we can retrieve from our substations is largely constrained by the capacity of the existing telemetry system. This constraint is limiting our use of devices that could provide us with a better picture of how our assets are being utilised in real time.

Real-time primary asset information that will become available following the implementation of SMS will allow us to operate our assets more effectively (we could utilise their full capacity better than we can at present). The benefit is that investment in new or upgraded primary assets will be deferred through the ability to more fully utilise existing capacity. Examples of this that will be possible with SMS include:

real-time temperature monitoring of transformers and cables allowing them to be operated closer to their maximum rating during contingency events than at present

dynamic line rating (DLR) - real time information on local weather conditions can be transmitted via SMS and will enable the trial and possible implementation of dynamic line ratings

real-time phasor measurement (synchrophasors) that allow us to monitor power system stability and retrieve this information following an event for analysis of how the system responded, to help us determine the need for investment in new primary reactive power assets.




3 OBJECTIVES

Chapter 3 sets out asset management related objectives for telemetry assets. As described in section 1.4, these objectives have been aligned with our corporate management objectives, and higher-level asset management objectives and targets as set out in the Asset Management Strategy.

Our overarching vision for the telemetry system assets is to provide operators and engineers with sufficient and accessible data to provide safe, efficient control of the Grid and to enable comprehensive analysis and understanding of the Grid in real time and historically. Further objectives have been defined in the following four areas:

Safety

Service performance

Cost performance

Asset management capability.

These objectives are set out below, while the strategies to achieve them are discussed in chapter 4.

3.1 Safety

We are committed to becoming a leader in safety by achieving injury-free workplaces for our employees and to mitigating risks to the general public. Safety is a fundamental organisational value and we consider that all incidents are preventable.

Safety Objectives for the Telemetry Fleet

- Allow operators and maintainers to have visibility of the status of remote plant from the substation they are working at.

- Increase the percentage of network operations to be carried out remotely.

3.2 Service Performance Ensuring appropriate levels of service performance is a key underlying objective. The overall service performance objectives for the Grid in terms of Grid Performance (reliability) and Asset Performance (availability) are set out in the Asset Management Strategy.

Grid performance objectives state that a set of measures are to be met for Grid Exit Points (GXPs) based on the criticality of the connected load. In addition, asset performance objectives linked to system availability have been defined. These high-level objectives are supported by a number of fleet specific objectives, and we will work towards these being formally linked in the future.

Service Performance Objectives for the Telemetry Fleet

- Reduced interruption restoration times for those substations with telemetry installed, and reduced overall average network fault resolution time.

- Average of six or less telemetry failures each year by 2020 (currently 6 to 12 RTU failures each year).




- Compliance with the latest information security standards recommended for critical infrastructure.

3.3 Cost Performance Effective asset management requires optimising lifecycle asset costs while managing risks and maintaining performance. We are committed to implementing systems and decision-making processes that allow us to effectively manage the lifecycle costs of our assets.

Cost Performance Objectives for the Telemetry Fleet

- Reduced annual telemetry fleet maintenance costs.

- Reduced cost to projects when adding additional equipment to the telemetry system, as SMS supports ‘plug and play’ technology.

3.4 Asset Management Capability We aim to be recognised as a leading asset management company. To achieve this, we have set out a number of maturity and capability related objectives. These objectives have been grouped under a number of processes and disciplines that include:

Risk Management

Asset Knowledge

Training and Competency

Continual improvement and Innovation.

The rest of this section discusses objectives in these areas relevant to the telemetry fleet.

3.4.1 Risk Management

Understanding and managing asset-related risk is essential to successful asset management. We currently use asset criticality and condition as proxies for a fully modelled asset risk approach.

Asset criticality is a key element of many asset management systems. We are currently at an early stage of developing and implementing the framework as we work towards formal and consistent integration of asset criticality into the asset management system. We have commenced this by prioritising fleet replacement expenditure programmes based on the criticality framework.

Risk Management Objectives for the Telemetry Fleet

- Annual revision of SMS installation prioritisation based on growing experience with SMS and improving criticality framework.

- SMS installed at all high-criticality sites by 2020.

3.4.2 Asset Knowledge

We are committed to ensuring that our asset knowledge standards are well defined to ensure good asset management decisions. Relevant asset knowledge comes from a variety of sources including experience from assets on the network and information from the




manufacturers. This asset knowledge must be captured and recorded in such a way that it can be conveniently accessed.

Asset Knowledge Objectives for the Telemetry Fleet

- Event records immediately available to engineers following system faults from substations with SMS installed.

- Improved standardisation of data.

- Reduced instances of fault data loss.

3.4.3 Training and Competency

We are committed to developing and retaining the right mix of talented, competent and motivated staff to improve our asset management capability.

Training and Competency Objective for the Telemetry Fleet

- Sufficient trained people available that can work on advanced SMS technology and systems safely while minimising human element incidents (HEIs).

3.4.4 Continual Improvement and Innovation

Continual improvement and innovation are important aspects of asset management. A large source of continual improvement initiatives will be ongoing learning from our asset management experience.

Continual Improvement and Innovation Objectives for the Telemetry Fleet

- Increased data available for input into asset health models and other asset management tools to facilitate better optimisation of asset management decisions.

- Addition of Single Line Diagrams to Annunciators for improved situational awareness for less critical sites.

- Development of Modelling Integrator System (MI5) for automatic configuration and data naming of SMS as an improvement of the Configuration Reader tool.




4 STRATEGIES

Chapter 4 sets out the strategies we will use to manage our telemetry assets. These strategies are designed to support the achievement of the objectives in chapter 3 and reflect the characteristics, issues and risks identified in chapter 2.

The strategies are aligned with our lifecycle strategies below and the chapter has been drafted to be read in conjunction with them.

Planning Lifecycle Strategy

Delivery Lifecycle Strategy

Operations Lifecycle Strategy

Maintenance Lifecycle Strategy

Disposal Lifecycle Strategy

This chapter also discusses personnel and service provider capability related strategies which cover asset knowledge, training and competence.

Scope of strategies

The strategies focus on expenditure that is planned to occur over the RCP2 period (2015–2020), but also include expenditure from 1 July 2013 to the start of the RCP2 period and some expenditure after the RCP2 period (where relevant). Capex planned for the period is covered by the strategies in section 4.1, while opex is mainly covered by section 4.4.

4.1 Planning

The planning lifecycle is primarily concerned with identifying the need to make capital investments in the asset fleet. The main types of investment considered in this strategy are:

enhancement and development

replacement and refurbishment.

We support these activities through a number of processes, including:

Integrated Works Planning (IWP)

cost estimation.

Capital investment drivers

Categories of capital investment generally have specific drivers or triggers that are derived from the state of the overall system. These drivers include demand growth, safety, compliance with Grid reliability standards, technology change and failure risk (indicated by asset criticality and health measures).

The strategies below consider the long-term implications for these drivers as we extend our planning horizon as part of our programme of asset management improvement.

4.1.1 Enhancement and Development

New telemetry assets will be installed whenever we upgrade or build substations to meet increased customer demand.




Network development projects

Invest in new SMS telemetry equipment as required for planned network

development projects.

System growth projects principally include new greenfield lines or the uprating of existing lines, which may also require additional substations and other supporting equipment. Much of this new equipment will require new telemetry assets to control and monitor them. All new telemetry systems will be implemented using SMS technology.

While the number of large upgrade projects will decline during RCP2, a number of smaller projects are expected in the coming years. These will require new protection schemes and SMS to meet their individual specifications. The costs of the SMS assets required for large-system growth projects are not discussed in detail here as they are included as part of the overall development project.

4.1.2 Replacement and Refurbishment

Replacement is expenditure to replace substantially all of an asset. Refurbishment is expenditure on an asset that creates a material extension to the end of life of the asset. It does not improve its attributes. This is distinct from maintenance work, which is carried out to ensure that an asset is able to perform its designated function for its normal life expectancy.

Staged SMS implementation

Carry out a staged replacement of RTUs with modern SMS.

The condition, performance and risks associated with the existing RTU fleet are set out in chapter 2. The potential benefits available from deployment of SMS are outlined in section 2.6.

Our strategy is to realise these benefits by progressively deploying SMS as replacements for the existing fleet of RTUs, which are ageing and have limited capacity. This will be implemented by a staged approach that will be completed by 2025.

We have set out an economic comparison of options for the replacement of RTUs in Appendix B. In order to simplify the analysis, normalised average installation costs have been derived, but the total cost is aligned with that forecast for the RCP2 period ($45.3m) provided in the asset management plan. A summary of the option analysis is set out below.

Option evaluation

The option evaluation in Appendix B covers two different options. Under option 1 – the reference case – the previous approach to managing our RTU telemetry assets would be continued, with RTUs that are no longer supported by the manufacturers being replaced with modern equivalent units.

Option 2 involves a programme of converting existing substations from RTU to SMS telemetry, in a staged approach that will be completed by 2025. Sites are prioritised based on the condition of the RTU, the obsolescence of the RTU, the criticality of the site, as well as other factors that affect the level of benefit to be gained from SMS. A lower cost model of the SMS hardware would be installed at smaller sites that do not require the full SMS functionality afforded by the model of SMS system installed at the larger substations.




The net present value results of the assessment are summarised in Table 3. The benefits are quantified incremental benefits; that is, above the current level of value derived from RTUs at present.

Option Description Net Present

Capital Costs ($m) [A]

Net Present Benefits ($m)

[B]

Net Present Value ($m)

[B] – [A]

Relative to Reference Case

($m)

Option 1 RTU replacement 44.5 5.2 -39.3 0.0

Option 2 SMS rollout 58.3 14.2 -44.1 -4.8

Table 3: Cost benefit analysis summary table

Option 2 ‘SMS roll-out’ has a lower NPV than option 1 ‘RTU replacement’ by about 10%. The analysis includes consideration of a number of benefits that SMS will bring, but it excludes ‘opportunity’ benefits that are expected to be realised by SMS but that are difficult to quantify. These unquantified benefits include access to more and better data as well as the potential for increased utilisation of assets. A full description of SMS benefits is provided in section 2.6, and they are quantified (where possible) in Appendix B.

In light of the closeness of the NPV of the options, and in consideration of the expected unquantified benefits that SMS will deliver, option 2 ‘ SMS rollout’ is preferred over option 1 ‘RTU replacement’.

Impact on fleet diversity

As the staged implementation of SMS proceeds, the proportion of D20M++ units will decrease as they are progressively replaced, followed by D20ME, then the D20VME and D200 units (concurrently), and followed finally by the C50 units. The charts in Figures 7 to 10 show the forecast diversity of the telemetry fleet population through the planned stage approach to SMS implementation.5

Figure 7: SMS Population at July 2013

Figure 8: SMS Population at the start of RCP2



5 SMP16 is the model of equipment used for SMS.

M++ ME

VME D200

C50 SMP16

SMS - POPULATION (JUL 2013)

M++ ME

VME D200

C50 SMP16

SMS - POPULATION (START RCP2)

M++ ME

VME D200

C50 SMP16


M++ ME

VME D200

C50 SMP16





Prioritisation

Legacy RTU replacements have been prioritised based on a number of criteria, including technical obsolescence and unit condition. In terms of technical obsolescence, D20M++ units are prioritised ahead of the other legacy RTUs because these units no longer have spares available and they are no longer supported by the vendors. The condition prioritisation is based on the 5-yearly condition assessments, which include diagnostic inspection.

While lack of vendor support and condition are the main considerations for replacement prioritisation, the works will also be scheduled, where possible, to coincide with other related works, such as replacement of protection relays.

Forecast volumes

There are 167 sites where RTUs will ultimately need to be replaced.

We have already developed a standard design for SMS, and commissioned our first installation. Our initial programme of SMS installations has commenced and we expect to replace RTUs at 46 sites in the RCP1 period. We forecast the replacement of RTUs at a further 70 sites in RCP2, and 51 in RCP3.

Cost

We have used a volumetric approach to cost forecasting, with the forecast based on estimated average costs for each site. Typically, small and medium sites will require one RTU each, while large sites will require two RTUs each and very large sites will require two or more RTUs. The cost of individual projects are forecast closer to the time of their implementation, so the cost forecast below for RCP1 includes some projects for which we have forecast their cost individually. Detailed cost estimate data is provided with the cost benefit analysis in Appendix B.

The total forecast cost of replacing RTUs with SMS during the RCP2 period is $45.3m.

GPS clock replacements

Replace GPS clocks when replacement criteria are met.

The replacement criteria for time synchronisation clocks are met when:

firmware is unsupported or site requirements change so that the existing clock does not meet the timing and interface requirements (such as for Ethernet-based time synchronisation)

maintenance, reconditioning or repair costs are no longer acceptable

essential spares or replacement components can no longer be purchased.

Impact on fleet diversity

With reference to the current diversity outlined in subsection 2.1.2, the diversity of the time synchronisation clocks as a result of this replacement strategy is shown in Figure 11. The charts show that the strategy will make a significant change to the composition of the fleet.




Figure 11: Time Synchronisation Clocks – Diversity (2020)

Volumes and costs

We plan to replace about 170 clocks between 2013 and 2027: 29 will be replaced in RCP1, 49 in RCP2, and the balance in subsequent years. Cost estimation for GPS clock works is volumetric based and has been completed using the Transpower Enterprise Estimation System (TEES) (US Cost) system. Our approach to cost estimation is discussed further in subsection 4.1.4. We estimate that the average unit cost of replacements will be approximately $8,300 for each site. Therefore, we forecast an expenditure of approximately $407,000 on GPS clock replacements during RCP2.

Remote engineering access

Introduce REA to substations to allow remote management of electronic

devices in the substation.

We expect the introduction of REA to provide many benefits, as described in section 2.6. The REA installation work will be carried out at the same time as the SMS replacement at those sites to optimise resource synergies by avoiding double handling and rework.

Most of the work and cost involved in enabling REA will be for on-site configuration of the SMS, cabling between devices, loading and configuring firmware, commissioning and some software downloads to devices. We have included the cost of installing REA as part of the cost of installing SMS at each site.

4.1.3 Integrated Works Planning

Our capital governance process – IWP – includes the creation of business cases that track capital projects through three approval gates, with the scope and cost estimates becoming more accurate as the project becomes more refined.

The IWP process seeks to ensure that works are delivered and undertaken in an efficient and timely manner. Planning of all substation telemetry works takes into consideration any potential synergies with other projects. In particular, when seeking to optimise substation telemetry works the following factors are taken into account.

Legacy serial communications replacement timing

Replace legacy serial communications to IEDs when a site migrates to an

Ethernet-capable protection scheme or REA is planned.

We will replace legacy serial communications with Ethernet when the legacy RTU at the site is being replaced. Ethernet communications have a much greater bandwidth than legacy serial communications.





TIME SYNC CLOCK - DIVERSITY(PLAN - 2020)





TIME SYNC CLOCK - DIVERSITY(DO NOTHING - 2020)




Efficiencies can be gained by lumping together the design and installation process with other upgrades. It can also ensure that diversity of communication protocols across the network is reduced by upgrading communications at the same time as RTUs.

Retaining legacy peripheral units

Leave the existing peripheral input and output modules and associated wiring

in service where possible whenever a new SMS is installed, but plan for the

replacement of these items as outages permit.

The decision to retain peripherals will be made after successful testing of direct connection of peripheral units to the new SMS device. Should testing be unsuccessful, all legacy peripheral units will be replaced when the RTUs are replaced.

The other situations in which the peripheral units will be replaced are where:

a protection scheme is upgraded, and the inputs/outputs modules can be collected at the equipment cabinet with an Ethernet device

a peripheral module is faulty and requires replacement

the active input and/or output modules are sparsely populated across multiple devices of a similar kind and it is justified to rationalise these inputs and outputs and migrate to a new Ethernet enabled device

the existing peripheral module equipment wiring is in a seriously degraded condition, sufficient to impact on reliability.

If the legacy peripheral units can be kept in place, the project to replace the RTU is more likely to be delivered on time because it will require fewer outages. However, the hardwired input/output connections will still need to be replaced in the near future, as soon as planned outages permit it.

4.1.4 Cost Estimation

Cost estimation is a key stage of the capital investment process and forms a critical input into projects at various stages in the planning process. Historically, cost estimates for substation telemetry were developed using proprietary systems. This has now transitioned to a central cost estimation team, which uses the cost estimation tool (TEES).

TEES is used to make initial high-level cost estimates using volumetric forecasting and to record customised cost estimates for large individual projects. We have established positions of Project Engineer and Project Cost Engineer, which will support the feedback loop of pricing for capital works. The cost estimates aim to achieve P50.6 Further details of our cost estimation approach can be found in the Planning Lifecycle Strategy document.

6 P50 means that there is a 50% probability of the actual cost being below the estimate.




P50 scoping of volumetric works

Scope SMS projects to achieve P50, an estimate of the project cost based on a

50% probability that the cost will not be exceeded.

Many types of replacement projects works are reasonably repetitive with largely similar scope, and thus categorised as volumetric works for the purpose of cost estimation. The key determinant of accurate cost estimates for volumetric capital projects is the effective feedback of cost out-turns from completed, equivalent scope of works. Volumetric estimates are determined using the TEES (US Cost) system. Tailored ‘building blocks’ have been developed for assets based on actual cost out-turns from completed, equivalent works. This feedback-based process is used to derive average unit costs for future works.

Cost and scope estimation for RTU replacements over the RCP2 period is an example of volumetric forecasting. Like other volumetric estimates, RTU replacement costs are estimated using the TEES (US Cost) system. Tailored ‘building blocks’ have been developed for the main unit types based on actual cost out-turns from completed, equivalent works. This feedback-based process is used to derive average unit costs for future installations. The assumptions made in using the average out-turn cost include that the:

real unit cost is representative of future unit cost

proportion of the cost attributable to labour and materials is essentially constant.

See subsection 4.1.2 for details on how cost estimation is applied to the replacement projects.

4.2 Delivery

Once the planning activities are completed, capex projects move into the Delivery Lifecycle. Delivery activities are described in detail in the Delivery Lifecycle Strategy. The following discussion focuses on delivery issues that are specific to the SMS fleet.

4.2.1 Design

The design process aims to design SMS solutions with enduring, cost-effective technology. We have a design standard for SMS, which includes REA, human machine interface (HMI) and related Ethernet communications. The design standard document is associated with a set of Remote Systems standard drawings that are published on the intranet and internet for design consultants to use as templates. It prescribes the appropriate design for things such as SMS cabinet layout, cabling, IED connections, national SCADA connections, time synchronisation, and documentation.

Standard SMS design

Develop a standard SMS design for existing and new substations.

For new and existing installations, the SMS system should take advantage of IEC 61850, where the majority of IEDs installed will support IEC 61850. The standard SMS design will be specified to:

enable DNP3 over IP communications to national SCADA

communicate with the station HMI




standardise on the HMI where required

communicate directly with the centralised historian facility (PI Historian)

enable IEC 61850 support for IED communication

enable DNP3 over IP support for IED communication (to permit use of those IED that do not support IEC 61850).

Key components of the standard design will be:

gateway managing communications to substation devices, SCADA, HMI, Historian and central configuration management

substation LAN

substation discrete input/output

central configuration management suite

REA tool suite

source resilience – critical information will be sourced from both protection relays to ensure that loss of data will not result in a loss of service.

Fleet design diversity

Minimise, as far as practical, the design diversity of SMS.

Standardising on the design of SMS telemetry reduces risks and costs of bespoke designs, and facilitates deployment of SMS for new and replacement projects.

Standardising equipment procurement limits diversity in the fleet, reduces support engineer training requirements, reduces spares holdings, ensures interchangeability of entire units and components, and facilitates maintenance. The costs of maintenance are also reduced, particularly in regards to configuration management.

Low-cost data acquisition and control alternative

Deploy suitable alternatives to SMS where a low-cost data acquisition and

control is required for remote sites with a low point count.

Some of our smaller substations may not require the range of benefits provided by a full SMS telemetry system. At sites where the data and remote access requirements are relatively low, we will consider installing a smaller model of the SMS telemetry system than those installed at the majority of sites. The design requirements of such a solution will be based on the following criteria.

Hardware will be based on technology families that are similar to those currently being deployed, for ease of configuration and support.

Digital inputs, digital outputs and analogue inputs should not exceed 24.

Communications speed required would not exceed 64 kb/s and GSM or a similar low-cost alternative link will be suitable.

Data acquisition will be based on exception polling rather than continuous polling, to reduce communications data requirements.




These solutions will be installed in a self-contained weather-tight enclosure with suitable IP ratings to prevent moisture ingress, dust ingress, and provide adequate cooling.

4.2.2 Procurement

Vendor management

Manage vendor relationships to ensure ongoing support, closer relationships,

and reduce dependence on vendors.

Equipment obsolescence can be delayed by having good vendor relationships and support in place. This includes technical support so that assets can continue to be repaired and have component parts replaced with spares as required for many years. We will increase our level of effort in regards to vendor relationships during RCP2.

4.2.3 Commissioning

Commissioning is an important part of the Delivery lifecycle, and the aspects of commissioning that are common across fleets are described in the Delivery Lifecycle Strategy. This subsection highlights commissioning strategies that are specific to SMS projects.

Extensive SMS testing at commissioning

Undertake comprehensive testing of SMS as part of commissioning.

Extensive testing will be undertaken at the time of installation to identify problems early and ensure correct operation. Following successful commissioning tests, equipment information will be recorded in company databases in line with company standards.

4.3 Operations

The Operation Lifecycle phase for asset management relates to planning and real-time functions. Operational activities undertaken are described in detail in the Operations Lifecycle Strategy. The following discussion focuses on operational issues that are specific to the SMS fleet.

4.3.1 Real-Time Asset Management

The operation and real-time monitoring of telemetry equipment is managed by the System Operator National Control Centres, the National Grid Operating Centres, and Grid Performance Remote Systems. The National Control Centres coordinate real-time power system management, which includes managing system security, energy flow and voltage. The strategies for real-time asset management that are specific to the SMS fleet are provided below. Further information on the benefits we expect from real-time information functions of SMS is provided in section 2.6.

Migration of third party communications to secure ICCP

Migrate all third party communications to a centralised solution based on the

secure Inter-Control Centre Communications Protocol (ICCP) by 2025.




All existing (and future planned) point-to-point third party RTU connections at substations will be migrated to a centralised high-speed ICCP service to enable the sharing of operational data, to meet requirements under the Electricity Industry Participation Code, and for control and operation of third party assets located at substations.

To ensure security, all external ICCP communications will be based on the secure version of the ICCP protocol.

IEC 61850

Comply with IEC 61850, a substation automation standard, through the

installation of proprietary software on the corporate server.

IEC 61850 is an important development for electricity transmission utilities, which offers a number of benefits, as discussed in section 2.6. A single instance of a proprietary 61850 centralised configuration management suite (Chronos) will be installed in the corporate server computers. Authorised access by designers, modellers and technical support/maintenance staff will be controlled through the existing IST infrastructure services and business applications security setup. We estimate that the initial installation and future version upgrades will cost $1.6m during RCP2.

Data integration and automatic reporting

Integrate data gathered from substations into other systems (such as the PI

Historian) to provide relevant data as inputs into decision-making processes

and generate automatic reports.

Many functions will require specific reports to be created to assist in extracting value from the gathered data. In addition to manual ad hoc reporting, the following types of automated reports are likely to be required:

timed reports (generated automatically on daily, weekly and monthly basis)

normal triggered reports (generated as a result of an event or other trigger such as a counter reaching a particular value)

exception triggered reports (generated as a result of something not happening, or not happening within expected parameters).

Central management of substation IEDs

Centrally manage the configuration and ongoing management of IEDs in

substations using a suite of vendor-provided tools.

IED Manager Suite (IMS) is a back-of-house umbrella application that provides the necessary security, remote configuration management, automated event data retrieval and supervision of manufacturers’ IED engineering tools for online REA to substation IED devices. It facilitates device management, data retrieval, event storage, and incident reporting. IMS is needed to deploy REA.

The Configuration Manager function within the IMS suite of tools provides centralised configuration management. A duplicated instance will be installed in the corporate server computers to ensure availability when machines are out for service, upgrade, patching or in




the event of software/hardware problems. Licences for each IED will be purchased in addition to the base applications.

SCADA use reduction

Remove the processing of all non-operational data from the national SCADA

service by 2025.

The load on the SCADA system can be reduced, and the need for additional capacity avoided, by separating non-operational data from operational data. SMS telemetry allows this separation to occur.

4.4 Maintenance

The maintenance of our assets spans the majority of their lives. Our approach to maintenance and the activities we undertake are described in detail in the Maintenance Lifecycle Strategy. We class maintenance tasks into the following main categories:

preventive maintenance

- condition assessments

- servicing

corrective maintenance

- fault response

- repairs

maintenance projects.

The remainder of this section describes our maintenance activities and strategies relating to RTUs and SMS. It identifies where and how these strategies relate to the higher-level strategies and objectives for the overall fleet.

4.4.1 Preventive Maintenance

Preventive maintenance is work undertaken on a scheduled basis to ensure the continued safety and integrity of assets and to compile condition information for subsequent analysis and planning. Preventive maintenance is generally our most regular asset intervention, so it is important in terms of providing condition information and feedback into the overall asset management system. Being the most common physical interaction with assets, preventive maintenance is also a potential source of safety incidents and human error.

We intend to implement the following preventive maintenance on its SMS fleet in support of the objectives stated in chapter 3.

Remote Terminal Unit condition assessments

Carry out condition assessments on RTU assets as appropriate.

Regular diagnostic testing on RTUs is required every five years. This should support the reliability objectives in chapter 3 by reducing the number of equipment failures. This condition assessment is used to reassess the expected remaining life of the asset and whether it should be replaced.




Having reliable condition data enables us to plan and carry out work based on standard defined failure mode and risk-based criteria, incorporating risk and lifecycle cost optimised solutions.

4.4.2 Corrective Maintenance

Fault response

Fault response is required to restore the function of assets as quickly as possible to maintain supply to customers.

RTU failure response

Replace failed in-service RTUs within 24 hours, investigate the failure, and

repair the RTU if feasible and economic.

We will replace RTUs that fail while in service no later than 24 hours after the failure. Then we will investigate the RTU and have it repaired if feasible and economic. Then the repaired RTU will be added to the stock of spares to replace the spare RTU that was used in the fault response phase.

Repairs

SMS assets are not as well suited to repair as substation primary assets. SMS are complex IEDs and it is usually not feasible to repair them should they malfunction. Instead, the manufacturer may provide repairs or replacements, or they will be replaced with one of our spares.

4.4.3 Maintenance Projects

As discussed in subsection 2.2.4 maintenance projects typically consist of relatively high-value planned repairs or replacements of components of larger assets. Maintenance projects would not be expected to increase the original design life of the larger assets. Maintenance jobs are typically run as a project where there are operational and financial efficiencies from doing so. The drivers for maintenance projects include asset condition, mitigating safety and environmental risks, and to improve performance.

Over RCP1 and RCP2 we do not intend to implement maintenance projects for the SMS fleet.

4.5 Disposal and Divestment

The disposal and divestment phase includes the process from when planning of disposal of an asset begins through to the point where we no longer own the asset. The approach is set out in detail in the Disposal and Divestment Lifecycle Strategy. This subsection describes the strategies for disposal of assets within the SMS fleet.

4.5.1 Asset Disposal

The implementation of asset disposal has many similarities with capital projects, including consideration of cost, safety, environmental impacts, and project management. Aspects that are specific to successful disposal projects are site restoration and termination of all support activities and planning.




Disposal of equipment

Dispose of transducers where they are no longer needed, and salvage

components from decommissioned RTUs.

Modern numerical relays provide the same data that was previously provided by transducers. The Secondary Systems Fleet Strategy describes the ongoing transition to numerical protection relays, which will allow almost all transducers to be decommissioned.

RTUs that are made redundant following replacement with SMS telemetry systems are ‘scavenged’ for usable spare parts such as Power supplies, I/O cards and chassis. All non-usable or unnecessary components are sent to a specialist electronics disposal company for breaking down and recycling.

4.5.2 Divestment Strategies

A number of substation divestments are planned for the RCP2 period. We intend to divest 12 substations between 2013/14 and 2014/15,7 with a further four sites to be divested during the RCP2 period.8 The replacement and refurbishment strategies discussed above exclude the sites that are planned to be divested.

4.6 Asset Management Capability

We require national Grid assets and equipment to be managed, maintained, tested and operated to high standards of skill, professionalism and safety supported by high-quality asset knowledge and risk management tools. To achieve the required standards, works must be carried out only by individuals with competencies that are appropriate and current. Further detail on our planned approach to competency is provided in the Competency Framework.

This section describes the approach used to ensure that these competencies are present in those undertaking work on the SMS assets. The capability strategies are described under two headings: Asset Knowledge, and Training and Competence.

4.6.1 Asset Knowledge

Robust asset knowledge is critical to good decision making for asset management. The SMS fleet is a key part of our asset knowledge because the assets are used to transmit asset data to the operating centres.

Centralised long-term historical archiving

Retain all retrieved substation data for a period of at least 25 years for the

purposes of reporting, post-event analysis and the identification of long-term

trends.

While the need to undertake post-event analysis and to provide regular reports on a wide range of subjects is self-evident, it is also important to consider the value of identifying long-term trends and patterns – particularly as many field assets have very long operational lives.

7 Substations: DAR, SPN, PAL, HIN, MOT, COB, MPI, UTK, WRA, GIS, APS, and CLH. APS and CLH do not have RTUs.

8 Substations: ADD, MLN, KEN, and TOB. TOB does not have an RTU.




The long-term historical archive using the PI Historian system will provide:

acquisition of data from source systems

management of data

provision of hierarchical overlays to provide intuitive and standardised access information

analysis and visualisation tool sets for data

automated monitoring, notification and reporting

on-demand delivery of data to other systems (such as SCADA data to PI, and condition data to AMIS).

Improve data management

Proactively manage data sourced from substations to deliver the right data, to

the right people, in the right format and at the right time.

The information available from devices at our substations is substantial and is growing at a steady pace. New devices with additional functionality allow the state and stability of the power system to be measured in real time, while the installation of new devices with built-in condition and performance monitoring allows reporting on equipment health. Yet more data does not translate directly to more value, and careful management is needed to generate truly useful information so the data can be appropriately extracted, stored and reported on. Appropriate areas of focus include:

segregation of operational and non-operational data

information that is required for the Grid Management and Control (GMC) will be treated as critical and will be routed via the SCADA system; other data will be committed directly to a long-term archive without going through the SCADA system.

Data integration

Data gathered from substations will be integrated into other systems (such as PI Historian) to directly provide relevant data as inputs into decision-making processes.

Provision of source resilience

For critical information, source resilience will be provided where available to ensure that the loss of a data source will not result in a loss of service. In most cases this will be achieved by sourcing data from both protection schemes.

New data sources

As business requirements change and demand new data from substations, new data sources will be exploited (if available already) or created.

Asset Overlays: Reporting and data management functions should function at the individual asset level (e.g. HLY T5) but also at the asset class level (e.g. all SF6 breakers).

Automatic reporting

Many functions will require specific reports to be created to assist in extracting value for the gathered data. In addition to manual ad hoc reporting, the following three types of automated reports are likely to be required:




timed reports (generated automatically on a daily, weekly and monthly basis)

normal triggered reports (generated as a result of an event or other trigger such as a counter reaching a particular value)

exception triggered reports (generated as a result of something not happening, or not happening within expected parameters).

SMS technology

Monitor RTU, REA, DATA and HMI technology for future deployment, keeping

pace with technology on a cost-effective basis.

Technology and user requirements are constantly evolving. Existing systems were designed and determined using the best tools, information, technology and standards available at the time. Over the years, the systems, standards and requirements have changed. The electrical and information systems are being driven harder and more capacity is demanded of the installed assets – the existing tools simply cannot deliver what is now required.

4.6.2 Training and Competence

We require our assets and equipment to be maintained, tested and operated to high standards of skill, professionalism and safety to ensure satisfactory functioning of the network.

We have two service specifications that define the competency requirements for working on transmission assets:

TP.SS 06.20 Minimum competencies for lines maintenance

TP.SS 06.25 Minimum requirements for Transpower field work.

We maintain a minimum baseline of retained skilled workforce: engineers and site works operators who understand the physical assets. This subsection details the training and competence strategies that are specific to the SMS fleet.

Specialised maintenance service providers

Continue use of specialised maintenance service providers.

Not all maintenance service providers have the skills required for SMS work, but some specialists do have the skills. Using specialist service providers reduces the risk of HEIs. This strategy is cost effective, as it would be more expensive to maintain high levels of these types of skills for all maintenance service providers, and full capability across all service providers is unnecessary.

Specialists may have higher unit rates than some other service providers, but these costs can be readily offset by the benefits of reduced HEIs and the avoided costs of achieving full capability across all regular maintenance service providers.

Substation Management Systems training and recruitment

Establish a programme of training and recruitment to increase the availability

of dedicated resources skilled in the implementation of SMS, with the aim of

being able to complete 18 new installations each year by 2015.




Labour resourcing is critical to the success of any labour-intensive works, such as undertaking a substation modernisation programme. Appropriate resourcing is a combination of having the right number of people, with the right skills, in the right place at the right time.

Existing demands on the resources required to support the existing fleet of RTUs and IEDs is expected to remain constant, with any substation modernisation work representing additional work. To meet the expected demand for skills, the right combination of training and recruitment is critical to ensure that programmes of work can be delivered. New resources can be used to backfill existing positions to release more experienced staff, or can be engaged in site work as part of an implementation team.

Given the large amount of proposed work, pre-empting the expected resource shortfall is a high priority.

Operational capacity and strategic partnerships

Build appropriate, strong operational and strategic partnerships with service

providers.

Modern substation devices with greater capabilities also entail an increased level of inherent complexity. Substation management and control systems are typically full computer systems, and though this computerisation delivers much sought after features it may also introduce increased management and maintenance overheads.

New skills are required, as the gap between substation systems and information technology systems continues to close rapidly. While many of the necessary skills can be procured or gained through training, the level of inter-system integration needed in the future will require new and strengthened partnerships to be fostered internally and with key vendors. All involved parties will need to work closely as a united cross-functional team, to achieve the programme of work that is set out in this Substation Management Systems Fleet Strategy.

A special team consisting of appropriate operational and project-based resources from the following two groups will be created:

equipment and system vendor(s)

maintenance service providers.

A special focus will be on the development, testing and full-scale implementation of a substation modernisation programme.




4.7 Summary of RCP2 Fleet Strategies

Planning

Enhancement and Development

Invest in new SMS telemetry equipment as required for planned network development projects.

Replacement and Refurbishment

Carry out a staged replacement of RTUs with modern SMS.

Replace GPS clocks when replacement criteria are met.

Introduce REA to substations to allow remote management of electronic devices in the substation.

Integrated Works Planning

Replace legacy serial communications to IEDs when a site migrates to an Ethernet-capable protection scheme or REA is planned.

Leave the existing peripheral input and output modules and associated wiring in service where possible whenever a new RTU is installed, but plan for the replacement of these items as outages permit.

Cost Estimation Scope SMS projects to achieve P50, an estimate of the project cost based on a 50% probability that the cost will not be exceeded.

Delivery

Design

Develop a standard SMS design for existing and new substations.

Minimise, as far as practical, the design diversity of SMS.

Deploy suitable alternatives to SMS where a low-cost data acquisition and control is required for remote sites with a low point count.

Procurement Manage vendor relationships to ensure ongoing support, closer relationships, and reduce dependence on vendors.

Commissioning Undertake comprehensive testing of SMS as part of commissioning.

Operations

Real-time Asset Management

Migrate all third party communications to a centralised solution based on the secure Inter-Control Centre Communications Protocol (ICCP by 2025.

Comply with IEC 61850, a substation automation standard, through the installation of proprietary software on the corporate server.

Integrate data gathered from substations into other systems (such as the PI Historian) to provide relevant data as inputs into decision-making processes and generate automatic reports.

Centrally manage the configuration and ongoing management of IEDs in substations using a suite of vendor-provided tools.

Remove the processing of all non-operational data from the national SCADA service by 2025.

Maintenance

Preventive Maintenance

Carry out condition assessments on RTU assets as appropriate.

Corrective Maintenance

Replace failed in-service RTUs within 24 hours, investigate the failure, and repair the RTU if feasible and economic.

Disposal and Divestment

Asset Disposals Dispose of transducers where they are no longer needed, and salvage components from decommissioned RTUs.

Capability

Asset Knowledge

Retain all retrieved substation data for a period of at least 25 years for the purposes of reporting, post-event analysis and the identification of long-term trends.

Proactively manage data sourced from substations to deliver the right data, to the right people, in the right format, and at the right time.

Monitor RTU, REA, DATA and HMI technology for future deployment, keeping pace with technology on a cost-effective basis.




Training and Competence

Continue use of specialised maintenance service providers.

Establish a programme of training and recruitment to increase the availability of dedicated resources skilled in the implementation of SMS, with the aim of being able to complete 18 new installations each year by 2015.

Build appropriate, strong operational and strategic partnerships with service providers.



Appendices

SA Substation Management Systems (Telemetry System) Fleet Strategy TP.FP 12.01


SA SUBSTATION MANAGEMENT SYSTEMS (TELEMETRY SYSTEMS) FLEET STRATEGY © Transpower New Zealand Limited 2013. All rights reserved. Appendices | page 43

A GLOSSARY OF ACRONYMS

Acronym Title Description

CBA Cost Benefit Analysis A method for comparing the cost and benefit of a range of alternative investment options.

DLR Dynamic Line Rating A method where the instantaneous rating of a transmission line is able to be more closely linked to the prevailing environmental conditions.

DNP3 Distributed Network Protocol IEEE standard protocol for transferring SCADA data between a master device and a slave device.

EMS Energy Market Services EMS provides GXP Metering and Geospatial services for Transpower and delivers market information to the industry.

HEI Human Element Incident An incorrect action that resulted in a Grid interruption.

HMI Human Machine Interface A screen that provides an operator with real-time status and control of a substation.

ICCP Inter-Control Centre Communications Protocol

An IEC standard protocol (IEC 60870-6) for exchanging information between control centres characterised by bilateral peer-to-peer data transfers as opposed to uni-directional master slave protocols like DNP3.

IEC 61850 International Electrotechnical Commission standard number 61850

International standard for a communications protocol intended for use by electronic devices in electrical substation environments.

IED Intelligent Electronic Device A label given to many modern electronic devices that feature microprocessor controls and features to enable easy configuration and interfacing to other devices.

IMS IED Manager Suite

An umbrella application that provides the necessary security, remote configuration management, automated event data retrieval and the supervision of manufacturers’ IED engineering tools for online remote engineering access to substation IED devices. It facilitates device management, data retrieval, event storage, and incident reporting.

IP Internet Protocol The dominant protocol used for sending packets of data from a source to a host via a network.

LAN Local Area Network A communications system that connects computers together at a local level (such as within a substation).

PI Historian Process Information Historian A time series database for extracting historical information about the states and events in the national Grid.

RCP Regulatory Control Period A 5 year period

9 over which the Regulator (Commerce Commission) sets

allowed revenue to efficiently meet costs.

REA Remote Engineering Access The ability to monitor, interrogate and control devices, such as protection relays, from a remote location.

RTU Remote Terminal Unit The part of the telemetry system that provides the link between individual items of plant at a substation, and the central control room.

SCADA Supervisory Control and Data Acquisition

A collective term for the system that provides the remote control and monitoring of substations.

SMS Substation Management Systems

A computer-based local area network (LAN) that has been designed specifically to operate in electricity utility environments. SMS supersede RTUs.

SPS Special Protection Scheme A power system protection system that provides an automated response to contingency events.

T+N project Telecommunications and IP Networking project

A major project currently being undertaken to provide high-speed and high-capacity fibre optic based communications to all Transpower substations.

TEES (US Cost)

Transpower Enterprise Estimating System

Cost estimation system used by Transpower.

Table 4: Acronyms

9 The first regulatory control period (RCP1) was four years.




B OPTIONS EVALUATION – COST BENEFIT ANALYSIS

The cost benefit analysis presented below compares two options.

1. Retain an RTU-based telemetry system, but address diversity and lack of support issues through a progressive replacement existing RTUs with up-to-date models. This option is referred to as ‘RTU replacement’.

2. Move to an SMS-based telemetry system by continuing with the present programme of replacing older RTUs with SMS. Continue the programme during and beyond RCP2 until all required RTUs have been replaced. This option is referred to as ‘Staged SMS rollout’.

B1 Number of sites and RTU/SMS units

We have telemetry installed at a total of 167 (not counting divestments) sites around the country. The current SMS project has committed to converting 46 of these sites from RTU-based telemetry to SMS-based telemetry by March 2015, at which time a total of 121 sites will still have RTU-based telemetry systems.

B2 Cost Benefit Analysis – assumptions

The following four assumptions have been made regarding the cost benefit analysis.

a) The costs and benefits for each option are the same up to year 15/16. This reflects the assumption that the current SMS project will be continued until the start of RCP2 (in March 2015).

b) The CBA for each option is calculated over a 15-year period from the last installation work, which is consistent with the expected lifespan of telemetry assets.

c) The costs and benefits for each option are as provided in the following sections.

d) The real discount rate is set at 7.0% p.a.

B3 Option 1 (reference case) – RTU replacement

The existing RTU-based telemetry system is diverse and ageing. It provides a basic level of performance and functionality that will allow for the continuing control and information gathering of plant at our substations. Under option 1, RTUs would be progressively replaced with current models as the fleet ages and older models lose vendor support. The replacement programme would reduce fleet diversity and maintenance costs, but the functionality and performance of the telemetry system will be largely the same as at present.

As this is the minimum level of investment needed to keep the telemetry system current, it is provided as the reference against which the other options are compared.

B3.1 Costs

The costs include:

RTU box, wiring, panels, design, installation, commissioning for each site

installing a substation communication network (LAN) for each site

installing an HMI at each site

upgrading 15 sites a year until all of the sites have been done

control centre software to enable SMS installed in RCP1.




The parameters of the analysis are provided in Tables 5 to 7.

Assumptions

Sites in total (as of April 2015) 121

Sites each year 15

Years to complete all sites 8

Table 5: Cost benefit analysis – Option 1 assumptions

Costs Cost/unit

RTU box, wiring, panels, design, installation, commissioning for each site $300,000

LAN – Substation LAN costs vary from $60,000 to $110,000 for a large site $80,000

HMI (Survalent price as per OHW, DRY, OTA installations etc.- mainly software licenses costs)

$50,000

Site Total $430,000

Annual Total (Installations at 15 sites p.a.) $6,450,000

Table 6: Cost benefit analysis – Option 1 cost assumptions

In addition, costs will be incurred to allow the benefits of the SMS installations committed during

RPC1 to be used. This includes the proprietary software required at the control centre (Chronos) and

its maintenance.

Year Cost

15/16 $750,000

16/17 $250,000

17/18 $250,000

18/19 $250,000

19/20 $0

20/21 $1,000,000

Table 7: Cost benefit analysis – Option 1 cost assumptions (control centre software)

B3.2 Benefits

Benefits under this option are limited to reduced maintenance costs realised through having a newer telemetry system fleet and reduced diversity (see Table 8).

Benefit category Description Full RTU –

benefits Notes

Reduction in RTU Maintenance Costs

Present spend on preventive and corrective maintenance is around $260,000 each year

Assume a new fleet of SMS requires only 3/4 of this cost to maintain due to reduced diversity and lowered age.

$32,500

Still require site visits for configuration and event data uploads, but maintenance callouts will likely be reduced due to newer RTUs. (Estimate a halving of maintenance costs.)

Total

These are annual benefits following rollout to all sites. As the project is completed, the benefits will be realised on a pro-rata basis. (For example, if the project is 20% complete, the annual benefits will be 20% of this value.)

$32,500

Table 8: Cost benefit analysis – Option 1 benefit assumptions




B4 Option 2 – SMS rollout

Under this option, RTUs will eventually be replaced with an SMS in a staged manner over several years (more than the five years of RCP2). The priority order that determines which RTUs are replaced first is determined by when:

the RTU at a site is technically obsolete

the RTU reaches its reliability or capacity limit

additional functionality is required at the site, which cannot be met using the existing RTU.

Option 2 involves upgrading on average 15 sites a year until all sites have been upgraded.

B4.1 Costs

The costs include:

supply and installation of a new SMS at each site

software needed to provide a control room interface to the SMS.

In order to simplify the analysis, installation costs have been derived that are based on the forecast total RCP2 cost divided by the number of sites planned for conversion, giving a notional average cost per site.

Under Option 2, SMS would be installed as per the programme indicated in Table 9.

Year Sites

RTUs Small Medium Large Very large Total

11/12 0 2 0 0 2 4

12/13 9 1 0 0 10 10

13/14 12 4 1 0 17 17

14/15 12 5 0 0 17 17

RCP1 subtotal 33 12 1 0 46 48

15/16 4 7 5 2 18 24

16/17 3 5 4 2 14 26

17/18 7 4 4 1 16 23

18/19 1 5 8 0 14 42

19/20 0 2 4 2 8 72

RCP2 subtotal 15 23 25 7 70 187

20/21 1 10 5 1 17 19

21/22 6 9 1 1 17 17

22/23 10 2 4 1 17 18

RCP3 subtotal 17 21 10 3 51 54

TOTAL10

65 56 36 10 167 289

Table 9: Cost benefit analysis – Option 2 programme

10

The total figures exclude the effect of divestments.




The estimated cost of the SMS rollout programme, under the Option 2 assumptions is provided in Table 10.

Year SMS Chronos Total

12/13 $2,154,305 - $2,154,305

13/14 $4,122,375 - $4,122,375

14/15 $3,620,000 - $3,620,000

15/16 $11,204,000 $750,000 $11,954,000

16/17 $9,099,000 $250,000 $9,349,000

17/18 $8,175,000 $250,000 $8,425,000

18/19 $9,833,000 $250,000 $10,083,000

19/20 $6,972,000 - $6,972,000

20/21 $10,938,000 $1,000,000 $11,938,000

21/22 $7,877,000 - $7,877,000

22/23 $7,747,000 - $7,747,000

23/24 -

-

24/25 -

-

Table 10: Cost benefit analysis – Option 2 cost assumptions

B4.2 Benefits

A full description of the benefits provided by SMS telemetry systems is provided in section 2.5 of the fleet strategy, and are summarised as:

REA – the ability to interrogate substation IEDs without having to be on site

improved asset condition information, and access to real-time condition monitoring information

reduction in telemetry installation and configuration costs – configuration will be less time consuming compared to existing RTU telemetry systems

reduced maintenance costs

reduced SCADA system loading – non-operational data will be split from operational data

improved utilisation of primary assets – richer information on primary assets will allow us to operate them closer to their limits.




Table 11 describes each benefit category and their estimated Option 2 benefits.

Benefit category

Description Qty. Rate SMS

annual benefits

Notes

Remote engineering access

Avoided system minutes @0.5 each year (6917 MW-min @$20k/MWh) resulting from faster event analysis and reduced restoration times.

0.5 $2,305,667 $1,152,833 Un-notified outage costs.

Lower cost in REA based on $1,500 for each site visit; four incidents each week. Presently, site visits are required to retrieve event data.

208 $1,500 $312,000

Better asset condition information

SMS will facilitate retrieval of asset condition information, which will allow faster fault identification, and savings through targeted maintenance rather than routine time base strategies: Fewer routine inspections by use of online condition monitoring. Reduce by 1 day the 5-yearly inspections.

18 $1,500 $27,000

Condition monitors can be connected to RTUs and via SCADA to PI.

Reduction in telemetry installation and configuration costs

Reduced project capital costs –$70,000 on hardwired IO on two large projects each year.

2 $70,000 $140,000 Simplified design, IO nearer source, less wiring costs.

Reduced project delivery times: 2 weeks for design, 2 weeks for commissioning.

6 $16,800 $100,800 Efficiencies in simplified design.

Automatic configuration of SCADA and REA systems, saving 1 work week for each project, conservatively 2 projects each month (all Grid projects).

24 $3,400 $81,600 Template-based designs.

Reduction in RTU Maintenance Costs

Present spend on preventive and corrective maintenance is around $260,000 each year. Assume a new fleet of SMS will require only 3/4 of this cost for maintenance due to reduced diversity and lowered age.

0.25 $260,000 $65,000

Reduced SCADA system loading

Improved availability of operational systems through reduced CPU loadings and disk usage. With SMS, SCADA will no longer be the dumping ground for data used by engineers outside the control centres. Instead, the data will be diverted to a historian, freeing up SCADA (SCADA point license costs @$50,000 each year).

1 $50,000 $50,000

Saving in license costs for 10% growth each year of SCADA database points.

Access to more and better data

There are benefits in having access to more data that are difficult to quantify but nonetheless should be mentioned. These may include:

- power quality data (such as disturbances that do not result in an interruption)

- streamlined data acquisition and automatic generation of reports.

Not quantified.




Improved use of primary assets

Deferred capital expenditure through closer-to-the-limit operation; for example:

- could end up deferring investing in a new GXP

- could defer uprating a transformer through continuous monitoring by running it closer to the limit.

Not quantified.

Total

These are annual benefits following rollout to all sites. As the project is completed, the benefits will be realised on a pro-rata basis. For example, if the project is 20% complete, the annual benefits will be 20% of this value.

$1,929,233

This is the benefit of having all sites converted to SMS. Annual benefits for the SMS options are pro-rated based on how many are done each year.

Table 11: Cost benefit analysis – estimated Option 2 benefits

B5 Economic Analysis

The economic analysis of the options, by means of a high-level NPV calculation, provides an indication of the long-term cost of each option. The analysis of future option costs is based on a discount rate of 7%. The analysis spans 15 years following the date of the last SMS installation works, as this is the life expectancy of most SMS equipment.

Table 12 provides a year-by-year breakdown of the components that comprise the NPV analysis and summarises the results.

Ref Option name

Net Present Capital

Costs ($m) [A]

Net Present Benefits

($m) [B]

Net value ($m)

[B] – [A]

Relative to reference

case

Option 1 RTU replacement 44.5 5.2 -39.3 0.0

Option 2 SMS rollout 58.3 14.2 -44.1 -4.8

Table 12: Summary of NPV Results

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