acs power transformers

ACS POWER TRANSFORMERS FLEET STRATEGY © Transpower New Zealand Limited 2013. All rights reserved. of 96

ACS POWER TRANSFORMERS

Fleet Strategy

Document TP.FS 20.01

November 2013

ACS Power Transformers Fleet Strategy TP.FS 20.01 Issue 1 November 2013


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ACS Power Transformers Fleet Strategy TP.FS 20.01

Issue 1 November 2013


Table of Contents

EXECUTIVE SUMMARY ...................................................................................................................... 4

SUMMARY OF STRATEGIES .............................................................................................................. 7

1 INTRODUCTION ....................................................................................................................... 8

1.1 Purpose ................................................................................................................................. 8

1.2 Scope .................................................................................................................................... 8

1.3 Stakeholders ......................................................................................................................... 8

1.4 Strategic Alignment ............................................................................................................... 8

1.5 Document Structure .............................................................................................................. 9

2 ASSET FLEET ........................................................................................................................ 10

2.1 Asset Statistics .................................................................................................................... 10

2.2 Asset Characteristics .......................................................................................................... 14

2.3 Asset Performance .............................................................................................................. 26

3 OBJECTIVES .......................................................................................................................... 39

3.1 Safety .................................................................................................................................. 39

3.2 Service Performance ........................................................................................................... 39

3.3 Cost Performance ............................................................................................................... 40

3.4 New Zealand Communities ................................................................................................. 40

3.5 Asset Management Capability ............................................................................................ 41

4 STRATEGIES.......................................................................................................................... 43

4.1 Planning .............................................................................................................................. 43

4.2 Delivery ............................................................................................................................... 51

4.3 Operation ............................................................................................................................. 57

4.4 Maintenance ........................................................................................................................ 60

4.5 Preventive Maintenance ...................................................................................................... 60

4.6 Disposal and Divestment .................................................................................................... 67

4.7 Asset Management Capability ............................................................................................ 68

4.8 Summary of RCP2 Fleet Strategies .................................................................................... 72

APPENDICES ..................................................................................................................................... 74

A POWER TRANSFORMER IMAGES ....................................................................................... 75

B ADDITIONAL COSTING INFORMATION ............................................................................... 76

C ADDITIONAL BENCHMARKING RESULTS .......................................................................... 77

D TRANSFORMER ASSET STRATEGY ECONOMIC ANALYSIS, 2010 ................................. 80

E POWER TRANSFORMER WINDING FAILURE HISTORY ................................................... 93

F HISTORIC TRANSFORMER ‘MID-LIFE’ OVERHAULS ......................................................... 96




EXECUTIVE SUMMARY

Introduction

Power transformers play an essential role within the transmission network by enabling the transfer of energy between different voltage levels of the Grid. The performance of power transformers is critical to maintaining reliability of supply to customers.

Our asset management approach for power transformers seeks to achieve a high level of reliability for this essential equipment, to mitigate safety hazards and to achieve least whole-of-life cost.

Asset fleet and condition assessment

As at June 2013 we had 352 power transformers in service.1 The main power transformer fleet comprises supply transformers and interconnector transformers. The two main configurations are three-phase transformers, and banks comprising a set of three single-phase transformer units.

The average age of the 132 banks of single-phase transformers is 51 years. There are 211 three-phase transformers, with an average age of 20 years. We also have 9 traction transformers, with an average age of 20 years.

Long-term reliable performance of power transformers depends mostly on the quality of the original design and manufacture, together with competent operation and maintenance.

Many older power transformers on the network are known to be of poor design and manufacture. In particular, the transformers manufactured in the 1970s and 1980s are considered to be high risk.

Our transformer fleet as a whole currently suffers from a high rate of forced and fault outages. This high rate leads to increased risk of interruptions to customers. We would need to cut this outage rate in half, just to be an average performer among our peers.

The single-phase transformers make a disproportionate contribution to the high rate of forced and fault outages. The tap changers and bushings of aged single-phase transformers are a particular cause of unreliability.

Our rate of major failures of power transformers also exceeds that of comparable international benchmarks. Major failures lead to significant risks to the reliability of service to customers, high costs of restoration and recovery, and can have potentially severe safety and environmental consequences.

Most of the causes of the defects, poor performance and major failure risks in the older transformers are related to their design and manufacture. These risk factors cannot be fully mitigated through maintenance. However, some specific risks and modes of failures are being addressed, through programmes of work to improve tap changer performance and replace high-risk bushings.

Our approach to procuring power transformers changed markedly from around 1992, in response to the high rate of power transformer failures we had experienced, and the associated risks and costs. From that point, we applied a much more demanding technical

1 For the purposes of this population count, we classify a three-phase set of single-phase transformers as one

transformer bank.




specification, and took a range of steps to ensure greatly improved quality in design and manufacture. Our current population of power transformers may now be divided into two main categories – those manufactured after 1992 that are of high-quality design and manufacture (about 40% at present), and those from earlier periods.

The performance to date of the 125 transformers we have purchased since 1992 has been good, with only one of these transformers suffering a major failure in service. This performance is significantly better than relevant international benchmarks, and a marked improvement on the performance of the legacy fleet.

We have developed an initial model of asset health for the transformer fleet. This model makes use of an economic analysis of optimum age for transformer replacement, and incorporates learnings from our operating experience over the past 20 years. The model shows that 11% of the fleet are now due for replacement.

Power transformer strategies

Our strategy for improving power transformer reliability is to progressively replace the population of transformers that have the worst asset health, are the worst performers, and are the most likely to suffer major failures.

Increasing customer demand at Grid Exit Points (GXPs) has often led to the replacement of older power transformers, as part of providing increased capacity. However, in 2009 we commenced a specific programme to identify and replace ageing power transformers, based on their condition and risk factors. Since 2005, we have replaced approximately 30 older power transformers, either for capacity enhancement or on the basis of condition and risk. This replacement programme is continuing through the RCP1 period.

We have also purchased a range of strategic spare three-phase power transformers to improve our ability to restore security in a timely manner, following the major failure of an in-service unit. Several of these strategic spares have already been deployed following the failure of an in-service unit, and allowed us to promptly restore security and minimise the risk of interruptions to customers. We now also have a mobile substation that can be used at small N security sites to enable extended outages for maintenance, and to facilitate the restoration of supply after a major failure.

The benefits of our transformer replacement and strategic spares programme to date include reductions in risk of interruptions to customers, reduced maintenance costs, and reduced environmental impact of acoustic noise and oil leaks. The replacement transformers also have significantly lower energy losses, compared with the original units.

Our long-term strategy is to replace the entire population of single-phase power transformers. We expect that this will take approximately 20 years to complete.

During the RCP2 period, we propose to replace 30 aged and high-risk power transformers at a total estimated cost of $106m. This replacement programme has been established after applying resource constraints.

As a consequence of the replacements planned in RCP1 and RCP2, the overall health of the transformer fleet is forecast to improve significantly over the period. Based on the current asset health model, it is forecast that the percentage of the fleet that is due for replacement will reduce from the current 11% to 4% by 2020. This improvement in forecast asset health will lead to a significant reduction in the risk to customers resulting from transformer forced and fault outages and major failures.




Improvements

In our planning for the RCP2 period we have made a number of improvements to the asset management of power transformers, including:

developing a prototype asset health forecasting model

using a customised estimate process to improve the scope and cost estimates

using network criticality to improve the prioritisation of works.

Further improvements will include:

refining the asset health model

refining the criticality framework.




SUMMARY OF STRATEGIES

The following summary lists the main strategy and its respective costs during the RCP2 period (2015–2020).

Capital expenditure (Capex)

Replace Unreliable Power Transformers RCP2 Cost $106.2m

Our strategy is to replace 30 unreliable transformers with modern equivalents over the RCP2 period. This includes the replacement of five transformers at Kinleith Substation as part of a large-scale project at that site. The replacement programme for the 30 transformers has been prioritised taking into account asset health, criticality, the coverage provided by national spares and the mobile substation, and integrated works planning considerations.

The cost estimates for these transformer replacements have been developed using a customised estimating process. The total forecast cost of the replacement programme during RCP2 is $106.2m.

Chapter 4 has further detail on this strategy and a discussion of the remaining strategies.




1 INTRODUCTION

Chapter 1 introduces the purpose, scope, stakeholders, and strategic alignment of the power transformer asset fleet strategy.

1.1 Purpose

The purpose of this strategy is to describe our approach to lifecycle management of our power transformer asset fleet. This includes a description of the asset fleet, 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 this asset strategy encompasses the fleet of supply and interconnector transformers including single-phase and three-phase types. It excludes transformers in the HVDC system, as their management is described in the HVDC Fleet Strategy.

1.3 Stakeholders

Power transformer assets are important components of the transmission system. Correct operation and maintenance of these assets enables the reliable operation of the power system. Key stakeholders for these assets include:

relevant Transpower Groups: Grid Development, Performance and Projects

regulatory bodies: Commerce Commission, Electricity Authority, and the Environmental Protection Authority

customers, including distribution network businesses and industrial plants and generators that are directly connected

local residents.

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 hierarchical connectivity by setting out our strategy for managing our power transformer assets to deliver our overall Asset Management Strategy. This fleet strategy directly informs the Power Transformer Asset Management Plan, which includes more detail on the timing of specific capital and operating works.

This hierarchical connectivity is represented graphically in Figure 1. It indicates where this fleet strategy and plans fit within our asset management system.




Figure 1: The Power Transformer Asset 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 the existing power transformer fleet including fleet statistics, characteristics and their historical performance.

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

Appendices are included that provide further detailed information to supplement the fleet strategy.

Power Transformer Plan

Power Transformer 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 power transformer asset fleet, including:

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

Asset characteristics: including safety and environmental considerations, asset criticality, asset condition, asset health, maintenance requirements and interaction with other assets

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

The two main classes of power transformers considered in this fleet strategy are supply transformers and interconnecting transformers.

Supply transformers: These transformers connect between the main transmission/distribution network (220 kV or 110 kV or 66 kV) and supply networks (33 kV, 22 kV or 11 kV).

Interconnecting transformers: These transformers interconnect between the main transmission network (220 kV) and the regional transmission and sub-transmission network (110 kV or 66 kV).

Our fleet of power transformers also includes small transformers that provide local service and earthing functions. These small transformers are not given significant coverage in this fleet strategy because they typically have only minor impact on overall service, and we have spares that can be deployed promptly in the event of failure.2

Traction transformers (dedicated to supply KiwiRail) are not specifically covered in strategies in this document, but are dealt with on a case-by-case basis. There are spares to cover the traction transformer units in service.

2.1 Asset Statistics

This section describes the power transformer asset fleet population, along with their diversity and age profiles.

2.1.1 Asset Population

As at June 2013, we have 352 power transformers in service.

Some transformers are sets of three single-phase units grouped to form a bank. These banks of single-phase units currently make up approximately 40% of the transformer fleet.

2 The replacement of two aged local service transformers of unusual rating at Islington is planned during RCP2 as part of

a major upgrade of the local service supply system, as described in the Fleet Strategy – ACS Other.




The composition of the fleet is shown in Table 1.3

Type 220 kV 110 kV 66 kV & below

Total

Interconnecting – three-phase units 31 1

32

Interconnecting – 3 x single-phase units 22 1

23

Supply – 3 phase units 65 85 29 179

Supply – 3 x single- phase units 16 82 11 109

Traction 9 9

Total 143 169 40 352

Table 1: Power transformer fleet population

As at June 2013, we have 355 ‘other’ transformers in service, including local service, earthing, and regulators, as shown in Table 2.

Type 220 kV 110 kV 66 kV & below

Total

Local Service 2 0 213 215

Earthing 0 0 137 137

Regulators 0 0 3 3

Total 2 0 353 355

Table 2: Other power transformer fleet population

2.1.2 Fleet Diversity

Asset fleet diversity is an important asset management consideration, and there is significant diversity in our transformer asset fleet – in terms of type and manufacturer.

Power transformers

Our main system voltages are 220 kV, 110 kV, 66 kV, 50 kV, 33 kV, 22 kV and 11 kV. In addition to these, there are a few other supply and local service voltages to suit particular applications such as HVDC, SVCs, railway traction, distribution companies and industry requirements. Figure 2 shows the diversity of our power transformers.

Figure 2: Power Transformers – Asset Type Diversity

The transformer fleet originates from 57 different manufacturers and is highly diverse. Our transformers are generally ‘bespoke’. Each unit was specified, designed and built to meet site specific operational, seismic, and customer requirements. Only a very small number of

3 The voltages shown on the tables are the highest transformer voltage. We note that this may not necessarily mean that

it is the primary voltage of the transformer.

INTERCONNECTING - THREE PH UNITS (10%)

INTERCONNECTING - SINGLE PH UNITS (6%)

SUPPLY - THREE PH UNITS (51%)

SUPPLY - SINGLE PH UNITS (33%)

POWER TRANSFORMER - DIVERSITY




identical units were built for each design (often only one bank). Our strategies for reducing fleet diversity are described in detail in subsections 4.2.1 and 4.2.2.

There is a clear division in technical standards of our power transformers purchased prior to and after 1992. Power transformers purchased after 1992 are to a much higher technical standard than those purchased before 1992 (see subsection 2.2.3 for more details). Power transformers purchased after 1998 also have a much higher degree of component standardisation than those purchased before 1998. This includes components such as radiators, bushings, on-load tap changers, pumps, fans and control equipment.

Tap changers

As mentioned above, our transformer fleet consists of a diverse range of makes and models. Our fleet has about 200 different models and types of tap changers. Although many tap changers are from broadly similar families, the diversity in the fleet presents significant challenges for maintenance, as discussed further in subsection 2.3.4.

2.1.3 Age Profile

About half of our present power transformer fleet was installed during the period of significant expansion of the Grid between 1950 and 1970. Until the early 1970s, almost all transformer installations used single-phase power transformers. From the late 1970s, new transformers have been three-phase units, with the exception of those required for special applications in HVDC and SVC projects. The transition from single-phase banks to three-phase transformers is reflected in the age profile shown in Figure 3.

Transformer age profile

Figure 3: Power Transformers – Age Profile

The average age for the 132 banks of single-phase transformers is 51 years and 20 years for the 211 three-phase transformers.

Table 3 illustrates the effect on the age profile of the transition from purchasing mainly single-phase to purchasing mainly three-phase transformers during the 1970s. The table shows the average age of different transformer types in the fleet and compares the number

0

5

10

15

20

25

30

0 5 10 15 20 25 30 35 40 45 50 55 60+

AGE (YEARS)

INTERCONNECTING - THREE PH UNITS INTERCONNECTING - SINGLE PH UNITS

SUPPLY - THREE PH UNITS SUPPLY - SINGLE PH UNITS

POWER TRANSFORMER - AGE PROFILE




and percentage of those that are more than 50 years old. The table shows that currently no three-phase units are more than 50 years old.4

Type Average Age Number over 50 years % over 50 years

Interconnecting – three-phase 15 0 0%

Interconnecting – single-phase 50 14 19%

Supply – three-phase 20 0 0%

Supply – single- phase 51 60 81%

Table 3: Transformer average age breakdown by supply and interconnecting types as of 2013

2.1.4 Spares

Our contingency planning aims to respond promptly in the event of a transformer failure, to minimise the risk that a further failure of a parallel transformer will lead to significant interruptions of service for customers. Our objective is to restore full security within one calendar month of a transformer failure occurring, as outlined in subsection 4.3.2. Achieving this objective depends on the availability of spare transformers. The transformer spares holdings are dominated by single-phase units, as set out in Table 4.

Type 220 kV 110 kV 66 kV

& below Total

Interconnecting: three-phase units 3 1 0 4

Interconnecting: single-phase units 13 1 0 14

Supply: three-phase units 4 5 3 12

Supply: single-phase units 11 52 9 72

Total 31 59 12 102

Table 4: Transformer spares by type and voltage

The progressive replacement of single-phase transformers with modern higher-rated three-phase units over the period to 2010 created a growing number of in-service transformers that could not be replaced by a spare transformer in the event of a major failure. To mitigate the increasing risk, a range of strategic spare three-phase power transformers were procured.

The spares holdings are discussed in more detail below.

Spares – single phase transformers

On-site spares are provided at most sites where single-phase transformers are installed. A typical supply substation with N-1 security consists of six single-phase transformers (described as two single-phase banks) and a seventh spare single-phase unit maintained on site as an operational spare.

In addition to the single-phase spares at substations, a number of spare units are stored in warehouses. Many of the old single-phase spares at warehouses would require extensive remedial work to restore them to operational condition. However, they still have significant value as backups for second contingencies.

Many of the older single-phase banks fitted with on-load tap changers have a common drive mechanism that connects the three single-phase transformers. The transformer tap

4 Fifty years in itself has no special significance, but it is close to the nominal life expectancy for power transformers

adopted in some jurisdictions.




changers and tap changer drive mechanism are not interchangeable between different models of transformers even if the rating is the same. So if one of the single-phase units should fail and there is no matching single-phase spare, it may, depending on the tap changer, be necessary to replace the entire bank with a strategic three-phase spare to maintain full operational capability.

Spares – three-phase transformers

No major spares were held for three-phase units were held until procurement of strategic spares commenced in September 2008. Sixteen strategic spares now provide coverage for 98% of our entire present and expected future three-phase fleet. Two of these units are in manufacture at the time of writing:

1 off three-phase 110/33-22-11 kV, 15 MVA supply spare is due for delivery to New Zealand in February 2014

1 off three-phase 220/66/11 kV, 250 MVA interconnecting spare is due for delivery to New Zealand in June 2014.

Spares – bushings

A number of spare standard bushings have been purchased and are in store at Otahuhu, Bunnythorpe and Addington. Yet many of these spares are not interchangeable between different transformer makes and models. We are currently assessing the condition of all spare bushings and the extent of coverage that they provide.

2.2 Asset Characteristics

The power transformer asset fleet can be characterised according to:

safety and environmental considerations

asset criticality

asset condition

maintenance requirements

interactions with other assets.

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

2.2.1 Safety and Environmental Considerations

Safety and the environment are key considerations because minimising safety and environmental impacts is a key part of our commitment to New Zealand communities. These risks can also require costly mitigation if not considered early in asset management planning.

Safety considerations

The most significant safety considerations for the power transformer fleet are set out below.

Bushing explosion

Bushing failures are a serious safety risk because many of the old transformer bushings are made of porcelain. An explosive failure may result in sharp shards of porcelain being propelled into the surrounding environment.




Oil

Oil is hazardous, and personnel are required to wear protective gear when working with oil.

Transformer oil fires are a low probability event, but the consequence can be severe. A major transformer oil fire, even if fully contained in the bunded area, may take days to extinguish. There is potential for serious harm to personnel, and there may be damage to adjacent equipment.

Working at heights

Work at heights is a safety issue for transformers, because maintenance and repair works are often carried out at the top of the transformer, a substantial height above ground.

Manual operation of on load tap changers

Some older transformers in the fleet require manual operation of motor-driven tap changers in the control cubicle with the transformer still energised. This is a significant safety risk as there is a chance that the tap changer or transformer can fail while the operator is next to the control cubicle/transformer.

Environmental considerations

We are committed to managing environmental impacts associated with the transmission network and will proactively protect, enhance and respect the environment. In this respect there are a number of issues with the power transformer fleet.

Insulating oil

All power transformers are filled with insulating oil which is classed as an environmental hazard. Some of our larger transformers contain more than 50,000 litres of oil. It is important to prevent and contain spillage when filling, treating or emptying the transformer oil. Power transformers are installed within a bunded area that will catch all oil spillage and oil contaminated storm-water and direct this to an oil interceptor which will separate the oil and water. The captured oil is pumped into a storage container and the water discharged into a storm-water drain.

We occasionally undertake oil treatment on site for some of our transformers. The oil treatment process involves using ‘fuller’s earth’ to filter oil of moisture and other contaminants. The contaminated ‘fuller’s earth’ must be disposed of appropriately to ensure that the waste does not have a harmful effect on the environment.

Noise emissions

Acoustic noise emissions can be a significant concern depending on the neighbouring environment. A few sites have been fitted with sound walls to block the transformer noise reaching residential areas. Modern three-phase transformers feature improved environmental characteristics, including lower acoustic noise emissions than single-phase units. Our strategy to replace older units with three-phase units will therefore improve the environmental impact of the transformer fleet. This aspect is discussed in more detail in chapter 4.

2.2.2 Asset Criticality

We have derived a methodology that assesses the impact of the failure of busbars and circuits on the reliability of each customers point of service. ‘Circuits’ in this context includes transformers. All busbars and circuits are assigned a criticality of either high, medium or low




impact, depending on the effect on customers if those network elements are taken out of service.

These ‘network’ criticalities have been considered in conjunction with asset health indicators to provide an indication of which transformers present our greatest risk. However, the criticality framework is at an early stage of development. Currently it does not consider factors such as contingency arrangements, spares availability and site access issues, all of which play a role in identifying the best investment option for the transformer fleet.

The chart in Figure 4 sets out the proportion of power transformers in each criticality category.

Figure 4: Power Transformers – Criticality

2.2.3 Asset Condition

In this subsection, we describe the overall condition of transformers and their major components separately. The reason for this is that transformer components have a significant effect on the individual transformer asset health, and to an extent its condition. The asset health model is described in more detail in subsection 2.2.4.

We undertake regular condition assessments on our power transformer fleet, but we do not rely on condition assessment as the only basis for risk assessment and forecasting. Based on our own experience and understanding of historic major failures, it can be observed that the condition assessments prior to failure have not usually indicated any warning signs. For a more detailed breakdown of historic transformer major failures, see Appendix E.

Transformer procurement before and after the early 1990s

The root cause of the majority of our historic major transformer failures has been attributed to defects in design and manufacture. The lessons from these major failures indicated the need for a significant change in our approach to specifying and purchasing power transformers, to ensure greatly improved quality in design and manufacture.

A major change in procurement practice occurred in the early 1990s. As a consequence, our transformer population may now be divided into two main categories – those manufactured after 1992 and those from earlier periods.

The transformers procured after 1992 are deemed to be of high-quality design and manufacture (approximately 40% of the fleet population at present) as they were subjected to a high level of specification, stringent design reviews, manufacturing inspections and witnessed tests. The transformer purchase specification has been further improved over the last few years so that standardised components such as tap changers, bushings, radiators, fans and pumps, temperature monitors, Buchholz and pressure relief devices are purchased. To further reduce fleet diversity and enhance standardisation, these transformers were only tendered to 2–3 pre-selected transformer manufacturers.

LOW (87%)

MEDIUM (12%)

HIGH (2%)

POWER TRANSFORMER - CRITICALITY




The transformers procured before 1992 are deemed to be at significantly increased risk of failure. Further details of these transformers are discussed in the following sections.

Single-phase transformers

The ageing fleet of single-phase transformers poses some maintenance concerns. Approximately 85% to 90% of the older single-phase transformers have been overhauled over the last 25 years to address generic problems such as:

broken winding support blocks

loose, damaged, wet and deteriorated windings, leads and barrier insulation

wet and damaged bushings

misaligned and worn on-load and off-load tap changers

badly corroded radiators.

The mid-life overhaul of these transformers has helped to ensure reliable operation. There have been few significant failures of transformers that have previously undergone major overhaul.

The remaining 10% to 15% of single-phase transformers have not been overhauled. These units are considered to be uneconomic for overhaul, but may require more frequent maintenance than overhauled units, and are at greater risk of major failure. The majority of the additional maintenance requirement is associated with high moisture levels and replacement of aged ancillary components.

Three-phase transformers

As discussed in subsection 2.1.3, our three-phase transformer fleet is generally much younger than the single-phase units and is in good condition overall. This is reflected in the much lower forced and fault outage rates of three-phase transformers compared with single-phase units (see subsection 2.3.1).

Three-phase transformers purchased up to the early 1990s were built to the older standards, and are vulnerable to failure as a result of original design and manufacturing defects. We do not intend to undertake mid-life major overhauls on these transformers, and these factors combined means that the older three-phase units have an increased risk of major failure when compared with their modern equivalents.

Tap changers

Mechanically ganged tap changers

Many of the older single-phase transformers use mechanically ganged tap changers which suffer from deterioration in the drive shafts and internal diverter componentry. Typically, these types of tap changers require extensive maintenance to the drive shafts, bushings and gears as these wear very easily compared to other types of tap changers. We have 40 transformers with this type of tap changer still in service.

Known defective tap changer types

Poorly designed mechanical cubicles

We have identified 20 transformers with tap changers as having poorly designed mechanical cubicles. The designs are poor in the sense that the drive shafts and seals get corroded very




easily and require frequent/costly maintenance to address. Two transformer manufacturer types are associated with poor mechanical cubicle design: Fuji and Mitsubishi.

Tap changers requiring design updates

We have reviewed all tap changers in our fleet, to identify performance issues and risks experienced by other utilities with those same makes and models.5 The purpose of this investigation is to help us identify and anticipate risks and issues that may arise from our tap changers and plan for appropriate maintenance.

The review highlighted a number of specific tap changer makes/models with modes of failure that include:

significant gear wheel spindle wear that leads to one or more phases failing to operate during a tap change

roller contacts may fail to tap and cause significant arcing

fixing screws on drive shaft seals and motor mountings may break due to hydrogen embrittlement.

These issues are well known to the original manufacturers (or their successors), and upgrades for tap changer mechanisms have been developed to mitigate risks. Yet the vulnerabilities of these tap changers and the availability of upgrades have not been well communicated.

Three transformer tap changer makes are affected: ATL, Ferranti, and AEI. We are currently developing a programme of work for the tap changers identified as requiring an upgrade.

Bushings

Modern condenser type transformer bushings have test taps that enable straightforward measurement of bushing condition. However, most of the old transformer bushings do not have test taps hence it is difficult to assess the condition of the bushings without removing the entire bushing from the transformer. Also, in the past, some bushings have suffered from deteriorating seals and caused oil leaks.

Resin bonded paper bushings were also widely used in transformer design in the early 1950s through to the 1980s. These types of bushings have a high failure rate and are no longer used in modern designs. Unfortunately our original records do not allow us to determine which of our transformers have resin bonded paper bushings. The only way to determine this is to take suspect transformers out of service to remove the bushings for inspection.

Our single-phase and three-phase transformers generally require significant bushing repair or replacement at 30 years of age. The components that may fail after 30 years are:

bushing oil seals, leading to risk of electrical insulation failure

oil sight glasses (which become blocked and impossible to read, preventing the identification of low oil levels that can lead to failure).

In some severe cases, it is more cost-effective to replace the entire bushing rather than repair oil seals that have failed – especially if the bushing internal components have deteriorated due to moisture ingress as a result of the failed oil seals.

5 Based on Energy Networks Association’s ‘National Equipment Defect Reports, June 2013’ and on recommendations

from Brush (as the successor of ATL).




A broken or damaged insulator shed (due to an external flashover or foreign object impact) will also usually require complete replacement of the bushing, rather than repair.

If the bushing is well maintained, the internal electrical components should last as long as the transformer core and windings (that is, 50 years or more).

The strategies to address the failure risk of all existing and new bushings are presented in section 4.4 and subsection 4.2.2.

Control systems

Deterioration of control system components is commonly observed in transformers after about 30 years in service, and can lead to forced and fault outages. The components that are typically most at risk of age-related failure include:

cooling control relays

oil and winding temperature monitors and probes6

fans, fan motors and pump relays

tap changer motor drive control relays

cubicle weather seals.

Our single-phase and three-phase transformers generally require significant control system repair or replacement at around 30 years of age to ensure reliable performance.

Cooling systems

Cooling systems comprise radiators, fans and circulating oil pumps.

The older single-phase units are cooled by radiators alone (comprised of tubes or plates). The plates are formed of thin sheets of mild steel and are prone to rusting around the welds, internally and externally, necessitating major repairs or replacement.

Modern plate radiators are made from thicker sheet steel and shaped to eliminate internal deposits and then thoroughly washed and coated to prevent corrosion. The outer surface is galvanised and then painted to provide a rust resistant coating.

In some recent projects we have introduced stainless steel radiators, to mitigate site-specific pollution factors such as the presence of hydrogen sulphide (H2S) in geothermal areas. We have limited operating experience with stainless steel radiators to date and are not yet able to draw firm conclusions about their long-term performance.

Our operating experience with transformer cooling fans has shown that they typically have to be replaced two or three times during the lifetime of the transformer. Fitting of improved temperature controls has reduced the number of fan start/stop operations and the length of fan running times.

2.2.4 Asset Health

Asset Health Indices (AHI) is an asset management tool used to provide a systematic approach to prioritisation of asset management interventions, based on a range of factors including asset condition. In our model, the health of an asset is expressed as a forecast of

6 We note that modern electronic temperature monitors provide improved features and performance, but are likely to

require lifecycle replacement within a 20-year period rather than the typical 30-year life of the older electromechanical monitoring devices.




remaining useful life. We use the asset health model to make a prediction of the year when the asset will no longer be considered fit to remain in service. The AHI forecast of remaining useful life is based on modelling deterioration or risk that cannot be addressed by normal maintenance (where maintenance to address the deterioration or risk is not possible/practical, or is uneconomic). At this point major intervention is required, such as total replacement of the asset or refurbishment that significantly extends the original design life.

Asset health indicators provide a proxy for the probability of failure in asset risk management analysis.

Asset health indicators are also used in conjunction with asset criticality to assign priority within asset management planning processes.

The AHI is calculated using factors including:

the current condition of the asset

the operating environment

economically optimal replacement age assumption (see Appendix D for more details)

the age of the asset (relative to nominal expected life)

the typical degradation path of transformers

any model/type or usage factors that affect the risk or rate of degradation, such as known defects or failure modes, or exceptionally good historic performance.

We are still at a relatively early stage in the development and application of AHI. More details on our asset health methodology are set out in the document ‘Asset Risk Management – Asset Health Framework’.

An asset health indicator for power transformers could theoretically be calculated based on performance data such as whole-of-life cost, failure rate, condition, hazard functions and unplanned outage costs. However, our relatively small and diverse population base makes it difficult to define an asset health model based entirely on statistics.

We are also not able to rely heavily on using data available from international sources, because of the particular characteristics of our fleet. Data on the critical period in an asset’s life, following the manufacturer’s design life, is usually not available, as utilities have typically replaced assets by this time.

Our approach to developing an asset health model has been based on assessment of a number of key factors for our power transformer fleet. For each of these factors, we have developed a standard approach to calculating the impact on asset health. These factors and their corresponding remaining life adjustments and commentary are shown in Table 5.

Factors Adjustment to remaining life

Commentary

Base life

Manufactured <1992 – Base

life of 60 years

Manufactured >1992 – Base

life of 70 years

As outlined in subsection 2.2.3, we have improved our transformer

design specification since 1992. Only one of the transformers

manufactured after 1992 has had a winding failure. We expect this

type of transformer to have a longer base life than those

manufactured before 1992. The base life of transformers

manufactured before 1992 is established from the economic

analysis for optimal age for replacement, as detailed in Appendix D.




Factors Adjustment to remaining life

Commentary

Major overhaul

Single-phase units that have

undergone major overhaul –

remaining life is adjusted by

an increase of 10 years

We have completed a programme of major overhaul on most single-

phase transformers in our fleet. As these overhauled transformers

have not yet had a major failure or intervention, we expect them to

be fit to remain in service for at least another 10 years.

Winding design or

manufacturing

defects

Specific makes and models

to have their remaining life

adjusted by a decrease of 15

years

We have experienced a high rate of failure of a particular type of

220 kV interconnecting transformer. The cause of the failure has

been attributed to generic winding design defects. The remaining life

adjustment is based on a simple engineering statistical analysis

comparing the specific makes/models with the rest of the entire fleet.

Transformer

components

Mechanically ganged tap

changers – remaining life


years

Tap changer generic design

defects – remaining life


years

Bushing generic design

defects – remaining life


years

As discussed in subsection 2.2.3, components such as tap changers

and bushings contribute to a significant portion of failures and

unplanned outages. We have identified specific makes and models

of these transformer components and have assigned the respective

remaining life adjustments based on simple engineering

analysis/judgement.

Poor external

condition

Poor external condition -

remaining life adjusted by a

decrease of 5 years

Technically, poor external condition is not a driver for replacement.

Even so, the remaining life adjustment made for it is a proxy for

whole-of-life costs (that is, increased maintenance cost or

environmental oil leak costs).

Poor internal

condition

High moisture content -


decrease of 10 years

High DGA/Furans –


decrease of 10 years

Oil tests of moisture content, dissolved gases and Furans can

indicate failure risk. We have identified individual transformers that

have a ‘high’ reading and assigned the adjustments to them.

Table 5: Power transformer factors and asset health

We allocate power transformers into AHI bands of ‘now due’, 0–2 years, 2–7 years, 7–12 years, and 12+ years. The distribution of asset health for the power transformer fleet as at 2013 is set out in the chart in Figure 5.

Figure 5: Power Transformers – Asset Health as at 2013

The AHI shows that a significant number of transformers are ‘now due’ or have a remaining life between 0 and 2 years. Our strategy for improving asset health is set out in subsection 4.1.2.

12+ YRS (76%)

7-12 YRS (8%)

2-7 YRS (4%)

0-2 YRS (1%)

NOW DUE (11%)

POWER TRANSFORMERS -ASSET HEALTH (12/13)




2.2.5 Maintenance Requirements

This subsection describes the maintenance requirements of power transformer assets. These requirements have informed the maintenance strategies discussed in chapter 4.

The most common types of maintenance carried out on power transformers are:

preventive maintenance, including:

- condition assessments

- servicing

corrective maintenance, including:

- fault response

- repairs

maintenance projects.

The Maintenance Lifecycle Strategy provides further details on our approach to the above maintenance works, and the specific maintenance requirements are included in the relevant service specification documents.

Preventive

Condition assessments

The internal condition of power transformers cannot be directly observed and this presents a challenge in quantifying their failure risk. There are many transformer tests used for condition assessments such as Dissolved Gas Analysis (DGA), furans and Degree of Polymerisation (DP) tests (these are described in detail below).

These tests can help us understand how the transformer ages and indicate if there are any systemic issues. However, these condition assessment techniques only provide inferences about actual transformer condition, and standard techniques are unable to identify many factors that contribute to transformer failure.

In some cases, testing may indicate the need for more intensive monitoring using on-line DGA monitors. Our experience is that these online monitors are helpful, but are often more useful in identifying the cause of failure after the fact, than in preventing failures.

Our condition monitoring tests and inspections are as shown in Table 6.

Frequency Activities

Monthly: An in-service visual and audible noise level 1 inspection during routine station inspection

Yearly: An in-service level 2 inspection is carried out, which is more comprehensive than the level 1 inspection and includes operational checks.

A thermo-graphic survey is carried out during a survey of the station.

Oil screen tests.

Dissolved gas analysis of oil samples.

Two yearly: Tests of inhibitor levels in oil samples.

Four yearly: An out-of-service diagnostic inspection of the transformer and all of its components.

Out-of-service diagnostic tests, including winding insulation resistance and polarisation index, and tests of bushing insulation.

Tests of levels of furans in oil samples.

A high-level condition assessment on which to base major work such as refurbishment, repair or replacement.




Frequency Activities

Two, four or six yearly:

Major service of on-load tap changer (interval depends on make, type and operating duty).

Table 6: Condition-monitoring tests and inspections

We also use other condition assessment techniques on power transformers, including:

tests such as furan analysis, and direct measurement of paper insulation samples to assess the physical deterioration of the insulation paper

sweep frequency response analysis (SFRA) to assess winding displacement and other anomalies that may result from the transformer being exposed to severe through-faults

power factor tests to determine the moisture and contaminants within the cellulose insulation

hot collar tests to assess the condition of the dielectric in older bushings (see subsection 2.3.4 for more details of the risks associated with older bushings).

The following subsections explain the monitoring undertaken as part of our regular asset condition assessments.

Dissolved gases

Oil samples are taken manually from all power transformers for laboratory analysis, typically on an annual basis, to assess levels of dissolved gas, and other condition indicators. Power transformers are also equipped with Buchholz relays which catch any free gas from internal incipient faults and initiate an alarm when gas levels reach a threshold level.

A small number of power transformers are equipped with on-line dissolved gas monitoring (which raises an alarm if gas levels or rate of gas generation exceed set levels). Gas level trends are indicative of certain types of faults and can provide information to determine if the transformer has to be removed from service immediately or requires monitoring more closely.

Transformer core, windings and cellulose insulation

The effective life of transformer windings is based on the condition of the winding, core and cellulose insulation (which deteriorates mechanically and, to a lesser extent electrically, due to heat, acids, water and other compounds in the insulating oil). The average condition of the cellulose can be monitored by furan tests of the oil and Degree of Polymerisation (DP) tests on cellulose samples can provide useful indications of deterioration.

Transformers must be removed from service to carry out DP tests on samples of cellulose in the oil. The DP measures the mechanical strength of the cellulose insulation, which is a direct measure of the transformer windings’ ability to withstand short-circuit faults. A transformer may have windings with a low (end of life) DP reading, but it may survive in service in this condition for many years, provided it does not suffer any significant damage through short-circuit faults on the network.

We note that DP samples can usually only be taken of the insulation on leads, or the outermost parts of the windings, and may not indicate the true state of deterioration of inner parts of the winding.

The degradation of the cellulose generates a number of furanic compounds that dissolve in the oil, and these can be measured by testing the oil. Particular furans and the level of furans are indicative of the average level of deterioration of the cellulose. Transformer cores




generally last well over 50 years, and while they may develop internal defects that generate elevated levels of dissolved gases these defects generally do not adversely affect the transformer’s ability to remain in service. Older transformers (single-phase and three-phase) typically have multiple internal earthing connections for the core, end frame and main tank that can cause continuous internal electrical discharges. This results in elevated internal oil gas activity that may mask more serious developing faults in the windings from being detected during routine oil Dissolved Gas Analysis (DGA) tests.

Servicing

Transformer tap changers

On-load tap changers operate in response to voltage regulation requirements. The frequency of operation can vary from several operations each day to more than 20 each day. As with all mechanical equipment, the bearings and gears wear, locking pins loosen, limit switches move, grease and lubricants harden and thicken hampering operation of tap changers. Modern tap changer manufacturers have improved the designs of their tap changers, reducing maintenance requirements (and improving reliability). Some maintenance is still required, but is non-invasive.

On-load tap changer contacts wear out due to arcing during normal on-load tap changer operation. The drive mechanisms of on-load tap changers ultimately wear out as a result of normal operation. The oil qualities of on-load tap changers deteriorate due to oil breakdown products generated during normal arcing operation. Off-load tap changers can fail due to oil carbonisation around tap changer contact surfaces.

Tap changers can fail if they are improperly repaired or re-assembled. Recent on-load tap changer problems are attributable to limited experience and knowledge of the tap changer maintainers.

Our single-phase and three-phase transformers generally require routine servicing every 4 years and significant tap changer servicing at 10–30 years of age. The actual time period depends on the number of tap operations and the loadings at which tap changing occurs. The components that require repair or replacement during servicing are:

on-load tap changer motors, springs, bearings and gear mechanisms

on-load tap changer contacts

off-load tap changer contacts.

Corrective

Fault response

The main causes of power transformer events requiring a call out fault response are:

older tap changer-drive mechanisms (that are badly worn causing alignment problems with subsequent jamming)

bushing failure due to moisture ingress and overheated terminations

cooling system and instrumentation faults.

Repairs

The most common repairs required for power transformers are:

oil leak repairs




overhaul and reconditioning of tap changer drive mechanisms

radiator repairs

bushing replacements

treatment of corrosion on metalwork and painting.

Oil leak repairs

Our single-phase and three-phase transformers generally require significant oil leak repairs between 15 and 40 years of age. We specify that all our new transformers have high-temperature gaskets and O-rings (typically made of Viton). Most existing older transformers have low-temperature non-Viton gaskets that deteriorate due to thermal ageing, weather conditions and hidden corrosion on mated metal surfaces. Viton gaskets on more recent transformers may also deteriorate prematurely due to (imperfect) original manufacture, incorrect installation procedures or hidden corrosion on mated metal surfaces.

Transformer radiators may also develop oil leaks due to continued thermal expansion and contraction that may cause the welded metal seams to fail after a period of time. The radiators may be repaired or replaced on site depending on the severity of the oil leaks and the general corrosion condition of the external and internal metal surfaces.

Corrosion control

Our single-phase and three-phase transformers typically require significant external corrosion repair at 15 years of age. We specify that all our new transformers have paint systems that meet the severe marine requirements of the AS/NZS 2312 Standard, which has a design life of 15 years to first maintenance.

Often the 15-year design life of the paint system is not achieved due to less-than-perfect application of the paint system when new, and undetected physical damage that may occur to the painted surfaces during installation. The undetected damage to mated metal surfaces during installation is a common cause of premature corrosion. In addition, some painted surfaces may not be cleaned effectively by rainfall and this can shorten the paint life to less than 15 years in a severe marine environment.

Historic spend – maintenance

We normally spend between $3m and $4m a year on transformer maintenance. We have spent about $1m to $1.5m on preventive maintenance and about $2m to $2.5m on corrective maintenance each year over the last 5 years.

Maintenance projects

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.

Maintenance projects are usually planned at least 12 months in advance, and are usually part of a long-term strategy for a particular fleet of assets. Maintenance projects are included in the Integrated Works Planning (IWP) process and are supported by individual business cases.

Historically, we have spent approximately $6m a year over the last 5 years, and the predominant work was a programme of major overhauls on our single-phase transformer fleet. See Appendix F for more information.




2.2.6 Interaction with Other Assets

An IWP allows for coordination between transformer works and associated assets and equipment to minimise disruption and reduce costs. When undertaking power transformer works, we take the following factors into account:

supply transformer replacement works are to be undertaken in conjunction with outdoor 33 kV to indoor switchgear conversion projects where possible

transformer replacement work should be coordinated with major customer project works

coordination of other protection upgrade work with transformer protection works.

Optimal management of the transformer asset fleet needs to consider the interdependencies and interactions with other asset fleets. Operational restrictions limit the periods for maintenance outages, and consequently associated equipment in the same branch is usually maintained in conjunction with the power transformer. This may include outdoor or indoor switchgear, cables, terminations, gantries, insulators, protection equipment, and so on.

2.3 Asset Performance

This section describes the historic performance of the power transformer fleet together with any associated risks and issues.

2.3.1 Reliability Performance

Achieving an appropriate level of reliability for our asset fleets is a key objective as it directly affects the services received by our customers. Reliability is measured primarily by the frequency and length of outages.

Most transformer installations have been provided with N-1 security. This is achieved with two power transformers, each capable of carrying the maximum substation load in the event of a short-term outage7 of one transformer.

Redundancy is a particularly important for transformer performance. A transformer failure at a station with N-1 security (that is, a backup transformer) will have a smaller impact than a transformer failure at a station with N security (that is, where there is no redundancy), which would cause an immediate and prolonged interruption to customers. Redundancy at a site typically reflects customer choice and the impacts of asset failure. N security sites are typically smaller stations and generation sites.

Major failures

Australia/NZ CIGRE surveys show a probability for total major and minor failure of power transformers of approximately 1.0% a year for each transformer. This increases to 1.5% each year for transformers greater than 30 years of age. The probability of a major (winding) failure is approximately 1/3 of the total failure rate. Our annual rate of major 220 kV transformer failures is comparatively poor, with a winding failure rate of around 0.83% each year (for banks, rather than units). The average major failure rate for the entire population is

7 Most transformers are able to carry the maximum substation load on a cyclic basis until the security is restored by the

return to service of the original transformer following the outage, or the mobilisation and commissioning of a strategic spare. This may take up to a month.




one winding failure every 10 months (based on our winding failure history over the past 37 years). The 220 kV transformer winding failure rate each year over 37 years is more than 3 times that of the 110 kV transformers. The average age of the 220 kV transformers experiencing winding failures is fairly low, at 24 years.

Winding failures

The distribution of winding failures (from 2007 to 2012) by primary voltage is illustrated in Table 7. A detailed list of winding failures can be found in Appendix E.

Fault type 220 kV 110 kV 66 kV 50 kV 33 kV 11 kV Total

Winding Failure 4 2 0 0 0 0 6

Table 7: Power Transformers – Winding Failures

Table 7 shows there are more winding failures for the 220 kV transformer fleet. High-voltage stresses are likely to contribute to winding failures.

Analysis of the root cause of major failures indicates that in almost every case the failure is attributable to design and/or manufacturing errors. They would not have been predicted through routine CA techniques.8

Improvements in the design, procurement, and commissioning of transformers since the 1990s has improved their performance. Yet 56 220 kV transformers dating from the 1970s to the 1980s are still in service. These units present a higher risk of winding failure (resulting from design and manufacturing defects) than their modern equivalents.

Tap changer failures

From 2007 to 2012, tap changers have caused 26 forced and fault outages. The main recorded type of tap changer failure is incomplete or incorrect operation. Others include tap changers being jammed, overheated, broke in operation and blown fuses. Of the 26 outage incidents, 15 were caused by tap changers on single-phase units. The tap changers that have failed in this period have not indicated a common manufacturer design defect. However, as outlined in subsection 2.2.3, mechanically ganged tap changers are vulnerable to deterioration and mal-operation.

Forced and fault outage performance

The following charts in Figures 6 and 7 show the forced and fault outages of transformers over the period from 2006/07 to 2011/12. The population of single-phase transformer banks and three-phase transformer banks was approximately equal over the period, with 3 phase transformers just outnumbering single-phase transformer banks by 2011/12. Figure 6 shows the relatively poor performance of single-phase transformer banks.

8 The majority of the failure modes were dielectric failures under impulse, or mechanical and electrical failure on

through-fault. These failures occurred with little or no prior warning. Routine power transformer condition assessment techniques would not have predicted most of these failures.




Figure 6: Power Transformers – Forced/Fault Outages9

The causes of the forced and fault outages are set out in Figure 7.

Figure 7: Power Transformers – Fault Causes10

The forced and fault outage rate of single-phase transformers is significantly higher than that for the three-phase transformers. The leading causes of outages differ significantly. Faults and failures of tap changers are the most significant cause of the poor performance of single-phase transformer banks. The root causes of tap changer related failures are age related deterioration and inadequate design. The majority of the ‘other’ outage causes in 2010/11 and 2011/12 were caused by Bucholz trips due to the Christchurch earthquakes and aftershocks.

9 Historic population data (used to normalise outage numbers) derived from current fleet data and population figures

published in 2009. 10

This data includes outages affecting all ‘power’ and ‘other’ transformers. Note this data is not normalised.

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

06/07 07/08 08/09 09/10 10/11 11/12

OU

TAG

ES P

ER B

AN

KSINGLE PHASE THREE PHASE

POWER TRANSFORMER - FORCED AND FAULT OUTAGE

0

5

10

15

20

25

30

35

40

06/07 07/08 08/09 09/10 10/11 11/12

EQUIPMENT FAILURE AGEING /FAIR WEAR AND TEAR

BIRDS /DROPPINGS OTHER

POWER TRANSFORMER - FORCED AND FAULT OUTAGE CAUSES




2.3.2 Performance and Cost Benchmarking

We have been involved in the International Transmission Operations & Maintenance Study (ITOMS) since 1994. This study involves performance and maintenance cost comparisons (including reliability) between 27 transmission utilities from North America, Europe, Asia, Australia and New Zealand and provides a useful opportunity for us to compare performance and identify opportunities for improvement.

While comparisons need to be treated with care (given different country-specific characteristics that are not normalised for), ITOMS results below provide a good general indication of our performance and maintenance costs compared to overseas electricity networks.

Outage performance

Figure 8 and 9 (taken from the ITOMS 2011 benchmarking round) show transformer forced and fault outages (per unadjusted transformer) for 100 kV–199 kV and 200+ kV transformers. Our total forced and fault outage rate for 110 kV and 220 kV transformers is significantly above the average rate of the ITOMS 2011 benchmark group. We are represented by the ‘K’ marker in each figure.

Figure 8: International Comparison of 100 kV–199 kV Transformer Performance

Figure 9: International Comparison of 200+ kV Transformer Performance

The average forced and fault outage rates reported in the ITOMS 2011 results are approximately 3.5% each year for 100 kV–199 kV and 5% for 200+ kV transformers. We would need to reduce the present forced and fault outage rates for transformers substantially, just to be an average performer in this study.

The main cause of our poor performance was equipment failure due mainly to minor equipment malfunctions (for example, a pressure relief device junction box was severely corroded and caused a trip). Equipment faults were responsible for 48% of transformer forced and fault outages in the study. The remaining forced and fault outages include Buchholz relay trips during the Christchurch February 2011 earthquakes and aftershocks.

Table 8 compares the forced and fault outage rate performance reported by participants in the ITOMS 2011 study against our performance (in events per 100 each year).




Voltage ITOMS Best Performer

ITOMS Average Transpower Average

100 kV–199 kV 0 3.4 6.6

200+ kV 0.37 5 12

Table 8: Forced and Fault Outage Rate against Benchmark Average

Cost performance

The following Figures from the ITOMS 2011 benchmarking round show composite service level and cost for 100 kV–199 kV and 200 + kV transformers. We are represented by the ‘K’ marker. The vertical axis represents the spectrum of forced and fault outage performance, from 0 (worst performer), to 2 (best performer).

Figure 10: 100-199 kV Transformers – Performance and Cost (ITOMS 2011)




Figure 11: 200+ kV Transformers – Performance and Cost (ITOMS 2011)

We are observed to be in the ‘higher-cost, lower-performer’ quadrant for all voltage classes.

Benchmarking results between 2005 and 2011, show that the maintenance spend for 110 kV and 220 kV transformers has remained about the same since 2005. Over the same period, our unplanned outage rates for 220 kV transformers is generally trending upwards, but the 110 kV transformers outage rates has decreased since 2005. While the increasing outage rates for 220 kV transformers can be partly attributed to anomalies such as the Christchurch earthquakes, there is a clear need to improve reliability. We would need to reduce our outage rates by more than 50% just to be an average performer.

Approximately 60% of all the forced/fault outages (disregarding anomalies11) over the last 20 years are attributed to minor equipment malfunction/failure which does not cause damage or prolonged outages. While we are working to reduce these minor failure rates, we are also concerned with the risk of major failures that could cause significant damage and prolonged outages, with significant risk of interruptions to customers. The main cause for major failures are the bushings, windings and tap changers.

2.3.3 Safety and Environmental Performance

Subsection 2.2.1 described safety and environmental issues related to power transformers. This subsection reports on their actual safety and environmental performance.

Safety

We are committed to providing employees and service providers with a safe and positive working environment, and minimising risks to the public. An explosive failure of an oil filled

11

These anomalies include incidents involving animals, droppings, lightning strikes and earthquakes.




power transformer may endanger personnel and the public from flying porcelain, oily blast and fire. Fire walls are being erected around a few power transformers that may present high risk to personnel and to adjacent plant and buildings. In the last few years, three safety incidents associated with power transformers were recorded:

in 2009, human error resulted in a finger injury while turning a transformer wheel

human error resulted in a near-miss incident in January 2013 when a staff member slipped while servicing a transformer

in February 2013, human error resulted in a small oil leak from a transformer. No injuries were reported.

Environmental

In the last few years, the following environmental incidents were recorded:

in 2012, Benmore T2 lost approximately 360 litres of transformer oil into the Benmore tailrace (the cause was a leaking heat exchanger and both heat exchangers were repaired)

as reported above in safety incidents, there was a small oil leak from a transformer at Southdown (the leak was quickly contained).

Minor oil leaks that are fully contained by our bunding and interception systems are not specifically reported.

2.3.4 Risks and Issues

This section briefly discusses risks and issues related to managing the current population of power transformers. The proposed strategies to mitigate the risks below are presented in chapter 4.

Maintenance costs and reliability of aged single-phase transformers

The ageing fleet of single-phase transformers have increased maintenance requirements and reliability risks, compared to the modern equivalent three-phase transformer:

the three single-phase units each have individual tanks, and therefore three times the number of flanges, seals, instruments, and so on, of a three-phase transformer

experience shows that routine maintenance and repair costs for the average bank of single-phase transformers are about twice that of the equivalent three-phase transformer

single-phase tap changer drive mechanisms typically experience significant wear, leading to issues with tap changer reliability

moisture ingress into old bushings caused by age-related deterioration of the old bushings leads to corrosion and oil leaks, and increased risks of major failure

the original bushings of single-phase transformers do not meet our current seismic strength requirements, and are vulnerable to failure in a major event.

Deteriorating condition

Power transformers deteriorate with age; particularly their cellulose insulation and insulating oil which are affected by heat, moisture, acids and the compounds generated by the deterioration of the cellulose, oil and internal coatings (such as varnishes, sealants and




glue). As a consequence of the deterioration of mechanical and electrical strength of the solid insulating materials, the transformer has a reduced ability to withstand the forces generated by high through-fault currents and switching surges.

If the asset health of the transformer fleet deteriorates over time, there is a risk of that transformer failure rates will be higher.

High fault levels and switching surges

High fault and switching surge currents cause undesirable effects on transformers such as loosening of the windings and leads, movement of the conductors, tearing of the cellulose insulation and consequent reductions in electrical clearances and possible flashovers. While most transformers are designed to withstand the expected fault level, exposure to a number of large through-faults shortens the life of a transformer. It can be difficult to measure the extent of these transients and to model the effect they may have on an aged transformer.

Seismic design capability

Many of the older power transformers, although fitted with seismic restraints, do not comply with our latest seismic design requirements. These older transformers are expected to withstand a moderate seismic event, but failure may occur for earthquakes within the current design standard.

Fleet diversity

As mentioned in subsection 2.1.2, our transformers are diverse in design and manufacture. This creates issues for maintenance, especially with the transformer tap changers where unique and specialist knowledge may be required for each different make and model. Historically, we have held training sessions for our maintenance service providers and we will continue doing this to retain the knowledge and skills in the industry.

Failure modes

Significant power transformer failures fall into five general categories:

winding failures

tap changer failures

failures due to excessive moisture levels in oil

bushing failures

control and instrumentation system failures.

Winding failures

The windings of heavily loaded power transformers deteriorate due to thermal ageing which breaks down the internal cellulose insulation, releasing moisture into the transformer oil. This reduces the internal dielectric strength and increases the risk of electrical failure. The thermal ageing of the internal cellulose insulation also causes shrinkage which weakens the mechanical strength of windings and increases the risk of failure under short-circuit through-fault conditions.

While the consequences of thermal ageing apply to some extent to transformers on our network, our transmission transformers are not usually heavily loaded. As a result, their windings are not usually at significant risk of failure from load-related thermal ageing.




The history of major winding failures of transformers on our network since 1978 shows that the main causes of these failures were defects in design and manufacture, rather than thermal ageing.

The experience of transformer failures on our network can be used to draw inferences about the risks of other transformers of identical or similar design/manufacture purchased at the same time. Our assessment is that, in general, all transformers on our network purchased in the 1970s and 1980s are of inadequate design and manufacture, and are at risk of suffering winding failure.

At present, 28 units purchased during this period have elevated Dissolved Gas Analysis (DGA) levels in their insulating oil that are indicative of an incipient12 fault. The gases are generated by the deterioration of the insulation and oil as a result of electric discharge and/or overheating. These units require close, ongoing scrutiny. A significant increase in one or more of the combustible gases triggers further tests, the fitting of continuous monitors, and an internal inspection and repair if required.

Tap changer failures

Tap changer failures have a more complex failure pattern than winding failures. Tap changer failures depend not only upon the quality of original design and manufacture, but also on how many times the tap changers have operated, their loading conditions during operation and how well they have been maintained.

There have been problems with the manually operated mechanisms resulting in misaligned contacts, leading to burnt contacts, gassing in the oil, and the actual tap position not agreeing with the tap position indicator.

The design of on-load tap changers has changed considerably over the years with some of the older units being unidirectional. For example, the power transfer of older units can only be from the primary to the secondary winding and, unlike modern tap changers, they cannot be operated with a reverse power flow from the secondary to the primary winding.

The older on-load tap changers require more frequent maintenance compared with modern units. Major services of older units are required at 5,000 or less operations, compared with modern units that only need to be serviced at 50,000 operations or more. The older units are the major cause of forced and fault outages of power transformers, particularly single-phase banks, because of their design and manufacture as well as their condition.

There are many different makes, types and models of on-load tap changers, requiring an extensive range of maintenance skills that the service providers generally do not have. Overseas specialists have been engaged to carry out major repairs and servicing of some of the modern tap changers.

A number of years ago, a tap changer manufacturer’s representative carried out a series of nationwide one-day courses for our service providers on the function, operation and maintenance of on-load tap changers. Unfortunately our service providers have relatively high staff turnover and this knowledge has slowly dissipated. Loss of skills from the industry and lack of actual practical experience in working with tap changers may become a further factor leading to deterioration in the performance of older, maintenance-intensive tap changers.

While the more modern tap changers on three-phase transformers have provided reasonable reliability in the past, overseas evidence indicates that faults can occur. We have

12

An incipient fault is one that may cause the transformer windings to fail.




experienced performance issues with a number of tap changers installed on three-phase transformers over the last 2 to 3 years. The types of issues being experienced are problems with the motor control cubicles and external drive shaft systems which are deteriorating and require regular maintenance. In some cases it is considered that we need to replace these units.

Modern tap changers require manufacturer updates periodically (some of which are issued in response to observations from failures). Yet the communication from the original manufacturer of the need for these updates has been inconsistent. Many of these updates will only occur if the original tap changer manufacturer is used to undertake maintenance.

We have recently become aware of important updates required on a number of tap changers. A programme of work to implement the priority updates is commencing during the RCP1 period and will continue through RCP2.

The strategy to address the risk of failure of all existing and new tap changers is presented in subsections 4.2.1, 0, and 4.5.1.

Moisture levels in oil

Transformer oil has two functions, one as an insulator and the other as a coolant. The quality of the oil has to be maintained to a high level, to ensure insulation strength. As the oil ages, the degradation products from thermal, chemical reactions and moisture within the transformer will degrade the oil and further accelerate the degradation of the insulation. This will shorten the life of the transformer.

The release of moisture into the transformer oil due to cellulose breakdown reduces the safe maximum load that the transformer can carry without the risk of sudden failure of insulation, caused by air bubbles or free water formation during cool down after high load periods. Electrical insulation failure in these circumstances typically causes severe damage to the transformer windings.

With modern transformer designs, electrical clearances are reduced and the insulating materials and fluids are subject to higher electrical stresses than in the older transformers, (for example, the minimum insulating strength of oil required for older transformers is 30 kV, while in modern transformers it is 50 kV). With these higher electrical stresses in modern transformers, it is necessary to ensure that the insulating oil is dry (very low water content) to prevent any electrical discharges occurring in the oil or oil impregnated insulation.

We test the oil periodically to ensure it is dry, but this test is temperature dependent. The insulation contains most of the moisture in the transformer and this migrates between the insulation and oil depending on the temperature of the transformer (for example, as the temperature rises the oil migrates from the insulation and into the oil). If the insulation is very wet (>5%) and the transformer is fully loaded or overloaded, the oil may become saturated with water leading to consequential flashover and a major failure.

We currently undertake yearly monitoring of the moisture in oil levels and pay particular attention to the moisture levels in modern three-phase transformers. To date, the moisture levels in the modern three-phase transformers are acceptable.

Bushing failures

The risk of bushing failures depends not only on the quality of original design and manufacture but also the environmental conditions where the bushings have been installed and how well they have been maintained. Moisture ingress due to weather-related




degradation around moisture seals is a particular cause of bushing failures. Generally, bushings have a shorter life than the main internal components of power transformers.

The strategies to address the failure risk of all existing and new bushings is presented in section 4.4 and subsection 4.2.2

Control and instrumentation systems

Defects in transformer control and instrumentation systems have been a significant cause of transformer forced and fault outages.

Transformer control and monitoring systems on most older transformers have already been replaced as a part of the historic transformer overhaul programme. The scope of work typically included replacing the old mercury/reed switch Bucholz (Gas/oil operated) relays with aseismic units, to avoid false operation during a seismic event.

Many older oil and winding temperature thermometers were inaccurate or faulty and were replaced with modern temperature monitors.

The remaining ageing control systems present a significant risk of causing forced and fault outages if no action is taken. Our strategy for managing this risk is outlined in subsection 4.5.1.

Transformers with corrosive sulphur

The refining processes used to manufacture transformer oil have changed significantly over the past 30 years. This has changed the constituents and characteristics of the oil.

Certain sulphur compounds in transformer oil can react with the copper (that is, windings and busbars) or silver, causing metallic corrosion. This creates fine deposits that embed within the paper insulation. The metallic deposits are conductive and, as a result, create a conductive path that in turn lowers the dielectric strength of the paper insulation.

International experience has shown a number of documented cases of transformer failures that are believed to be due to corrosive sulphur compounds contained in transformer oils.

The transformer oil industry now believes it has solved the issue as a result of changes to oil refining processes. All transformers we have purchased since around 2007 have been tested for corrosive sulphur to confirm none is present.

Transformers purchased between 2000 and 2006 are considered to be most at risk, following the failure of transformers manufactured in the early 2000s. Tests of corrosive sulphur in oil can be completed to assess the extent of the problem in each transformer. However, it is difficult to predict whether a transformer will fail because of corrosive sulphur. Latest international advice indicates that the transformers most at risk are units that are either highly loaded (resulting in moderate to high internal oil temperatures), or units with a lack of oxygen in the oil.

In 2009, we tested 13 transformers for the presence of corrosive sulphur (focusing on units of high importance), and found evidence in 7 of them. International expert opinion remains divided on the relationship between the extent of corrosive sulphur and the risk of a transformer failure. We have not yet taken any specific steps to mitigate the risk that may be caused by corrosive sulphur within these 7 transformers.

Three of the seven transformers found with corrosive sulphur are of most concern, because of the severity of the corrosive sulphur and the criticality of the transformers. Our strategy for dealing with these three transformers is set out in subsection 4.5.1.




Fire risks

Transformer fire is a very low probability event, but the consequences are severe. Typical installation arrangements for single-phase transformers are at increased risk because a fire will spread quickly between the units and adjacent banks and equipment. There is less of a risk of fire spread with modern three-phase units because the installation is designed to incorporate fire walls or is spaced at greater distances.

In general, our policy is to install fire walls to provide protection against the effects of transformer fire on adjacent equipment, where there is insufficient separation distance. Firewalls not only protect adjacent transformers but also disconnectors, circuit breakers, bus support posts, voltage transformers, current transformers and buildings. The highest risks associated with transformer fire are in situations where two adjacent transformers provide N-1 security for customer load. The installation of fire walls is aimed at preventing sustained interruptions to customers, as well as saving other primary plant.

However, the retrofitting of fire walls between units of single phase banks is impractical, and in some cases, the retrofitting of fire walls between complete banks of single phase transformers is also impractical.

Oil filled power transformers are typically installed in a bunded area which will catch any spilled oil and drain it into a tank extinguishing the burning oil. An oil fire in the bunded area may take days to extinguish and can damage nearby equipment. Some older installations have several banks of single-phase transformers all installed in a single bunded area, leading to increased risk of fire spread and consequential damage.

New transformer installations can be provided with a range of risk mitigations that will help manage the consequences of fire. Yet there are limited risk mitigations can be successfully applied to the legacy population, particularly for single-phase transformer banks.

Lack of on-load tap changing capability

Many older single-phase transformers only have off-load tap selectors. The lack of on-load tap changing capability on these transformers has led to the need for dispensations from asset compliance requirements under the Electricity Industry Participation Code.

Transformers without on-load tap changers create constraints on the acceptable operating range of primary system voltage that are much tighter than would be the case with on-load tap changer transformer. In some locations, these constraints limit the flexibility of the System Operator in managing the system, or are projected to do so, with future load growth. These constraints can result in increased costs of operating the power system, particularly in the provision of additional reactive support.

In some cases, the lack of on-load tap changer capability at a GXP leads to requirements for short outages for temporary changes to off-load tap settings, prior to the removal from service of a transmission circuit. This may be required by the System Operator to ensure voltage remains within the target range during the transmission circuit outage. Changing the off-load tap setting requires attendance on site.

Transmission circuits may be removed from service on a daily basis over an extended period to enable major programmes of transmission line work, and this can lead to daily requirements for changes to off-load tap settings. The attendance on site at the start and end of each day is costly, and the frequent operation of the off-load tap selectors can lead to unreliability. It also increases the exposure to the risk of HEIs.




Double contingency events

The most serious risk arising from a major failure of a three-phase power transformer is that a further failure occurs in the (typically) single remaining transformer before work can be completed to restore security. Such double contingency events can lead to extended interruptions to customers that cannot be quickly resolved.

Major internal repairs of three-phase transformers can take 6 to 18 months to complete, and the lead time for transformer procurement is 12 to 24 months.

If the failure of the first unit involves an electrical fault, the remaining transformer may be severely stressed by the passage of the fault current. In addition to the fault stress, the remaining transformer in service will also be loaded with the full substation load. While the transformer is rated for the full substation load, this may lead to increased ageing of the transformer components or increased generation of dissolved gasses.

Supply transformer installations are typically a pair of identical transformers. Double-contingency events may arise from a common cause.

Other less severe double-contingency events include the failure of a transformer during a planned outage of a parallel transformer, leading to loss of supply until the parallel transformer can be restored to service.

Asset knowledge

Asset knowledge is a critical input into asset management decisions. While our basic transformer asset knowledge, such as the transformer age, make/model and external condition is currently sufficient, there are some areas where we can improve. The following are some asset knowledge issues we have identified.

A portion of our asset management database is currently decentralised. In particular, transformer test results, condition assessment reports and detailed maintenance records are stored electronically in a variety of locations and are not always readily accessible.

Some transformer test results, such as DGA, are well maintained in the asset management database, but there is a need to further capture SFRA, winding, bushing, tap changer, control system and furans test results.

We do not currently have a formal record of the volumes of oil used in topping up oil levels in transformers.

Asset information is currently deficient for auxiliary equipment. This includes the makes and models, condition and age of pressure relief devices, cubicles and so on. Transformers are also bespoke items and many parts and auxiliary equipment are not common/standardised.

Our data-gathering requirements need improvement to ensure that our various service providers take a consistent approach to the coding and recording of asset data.

Photographic evidence of the external condition of the transformer is currently lacking, so the condition is difficult to assess without specifically engaging the maintenance service provider on site.

Our strategy for improving asset knowledge is set out in subsection 4.7.1.




3 OBJECTIVES

Chapter 3 sets out asset management related objectives for the power transformer asset fleet. As described in section 1.4, these objectives have been aligned with our corporate and asset management policies, and higher-level asset management objectives and targets.

The overarching vision for our power transformer assets is to improve the overall performance of transformers taking into account network criticality. Further objectives have been defined in the five following areas:

Safety

Service performance

Cost performance

New Zealand communities

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.

Recognising the reduced level of control we have in relation to public safety, we will take all practicable steps to ensure Grid assets do not present a risk of serious harm to any member of the public or significant damage to property.

Safety Objectives for Power Transformers

- No injuries/fatalities resulting from explosive failure of power transformers.

- No injuries/fatalities resulting from working in confined spaces in power transformers.

- No injuries/fatalities resulting from working at heights on a power transformer.

- No injuries/fatalities resulting from electrocution while working on power transformers.

3.2 Service Performance

Ensuring appropriate levels of service performance is a key underlying objective for us. We have specified service performance in terms of Grid Performance (reliability) and Asset Performance (availability) in our 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 Power Transformers

- The 10-year rolling average major failure rate to be less than 0.3% each year.

- The forced and fault outage rate to be less than 7% each year.13

- Restore security of supply within one calendar month of a major failure occurring.

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 full lifecycle costs of our assets. We have defined cost performance objectives in our Asset Management Strategy, including a commitment to make asset management decisions that minimise whole-of-life costs for the asset fleet and for the transmission system overall.

Cost Performance Objectives for Power Transformers

- Minimise whole-of-life transformer cost by taking into account cost of losses.

- Minimise maintenance cost via standardisation of transformer componentry.

- Minimise maintenance cost by high standards of corrosion control specification.

3.4 New Zealand Communities Asset management activities associated with the power transformer asset fleet have the potential to impact on both the environment and on the day-to-day lives of various stakeholders. Relationships with landowners, communities and customers are of great importance to us and we are committed to using asset management approaches that protect the natural environment. Overarching environmental objectives have been developed as part of the Asset Management Strategy. These include a need to achieve greater than 90% compliance with Resource Management Act (RMA) 1991 environmental requirements of RMA consents within one month of notification.

New Zealand Communities Objectives for Power Transformers

- No significant oil spills into the environment.

- No significant spread of oil fires from power transformers.

- Ensure all new power transformer installations are noise compliant with local council bylaws.

- Noise pollution for existing power transformer installations is effectively managed and minimised.

- Minimise damage to third-party properties.

13

The average forced and fault outage rate is about 7.5% over the last 5 years (removing the Christchurch earthquake events). Given the replacement rate of single-phase transformers over RCP2, a 7% rate is considered appropriate.




3.5 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 power transformer fleet.

3.5.1 Risk Management

Understanding and managing asset-related risk is essential to successful asset management. We currently use asset criticality and asset health as a 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 our criticality framework (see subsection 2.2.2) to support asset management decisions. As discussed in subsection 2.2.4, we have developed an asset health model for the power transformers fleet, which is an important determinant of replacement requirements.

We are currently at an early stage of developing and implementing the models as we work towards formal and consistent integration of asset criticality into the asset management framework.

Risk Management Objectives for Power Transformers

- Incorporate asset criticality in the prioritisation of transformer replacements.

- Increase the frequency of assessment for critical assets.

- Seek improvements in health for high priority transformers

- Continual improvement of the transformer Asset Health Indices (AHI) model.




3.5.2 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 Grid, 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 Power Transformers

- Develop a transformer corrosion model.

- Develop a bushing overhaul/replacement model.

- Develop an on-load tap changer overhaul model.

- Accurate recording and frequent maintenance of asset information.

3.5.3 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 Power Transformers

- Engage overseas specialists to resolve issues with specific tap changer makes and models.

3.5.4 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 Power Transformers

- Improve existing procedures and practices via the use of new materials, diagnostic devices or techniques.

- Maintain awareness of good international procedures and practices in transformer management, and evaluate new initiatives for possible adoption.




4 STRATEGIES

Chapter 4 sets out the fleet specific strategies for the management of the power transformer asset fleet. These strategies are designed to support the achievement of the objectives in chapter 3. They reflect the characteristics, issues and risks identified in chapter 2 and provide medium-term to long-term guidance and direction for asset management decisions. 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 RCP2 period is covered by the strategies in sections 4.1 and 4.2, while opex is covered by the strategies in sections 4.3 to 4.6. The majority of capex relates to asset replacement, as described in subsection 4.1.3.

4.1 Planning

This section describes the strategies for the Planning Lifecycle for the power transformer asset fleet. It identifies where and how these strategies support the higher-level lifecycle strategies and objectives for the overall fleet.

Planning activities

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

enhancement and development

replacement and refurbishment

customer-driven projects

spares acquisition.

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 or from individual power transformers. 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

Commissioning of new or upgraded transformers is driven primarily by load growth exceeding the capability of current assets.

Other important drivers for power transformer fleet investments include security of supply, redundancy, and fleet standardisation. These are discussed in further detail below.

System growth

Ensure that the transformer fleet is managed to ensure compliance with grid

reliability standards in support of our objectives and procure and install new

transformers to enable system growth.

Our Annual Planning Report (APR) considers the latest generation and demand forecasts for the upcoming 10-year period. During the planning process, we assess the capability of the transmission network against these forecasts to identify the Grid investments needed to meet the grid reliability standards, or which provide a net electricity market benefit. The APR summarises planned and possible upgrades of interconnection and connection assets, including power transformers.

For new or upgraded interconnection transformer assets with an expected cost greater than $20m, a Major Capex proposal will be prepared and submitted for approval. For new or upgraded interconnection transformer assets with an expected cost less than $20m, an enhancement or development project is established under Base Capex. The process includes consulting customers and applying investment tests.

4.1.2 Replacement and Refurbishment

This subsection describes replacement and refurbishment strategies for the power transformer fleet. 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. Specific interventions have been defined for power transformer assets based on an assessment of AHI and informed by relative criticality. These interventions and their rationale are set out below.




Replacement strategies

Power transformer replacements

Replace single-phase and three-phase transformers with more reliable new

three-phase units based on failure risk.

Our power transformer replacement strategy is to replace a number of transformers that have been identified as requiring replacement during RCP2 primarily due to their relatively high risk of failure as indicated by poor asset health. The main factors that have been considered when assessing transformers for replacement are included in the power transformers asset health model (see subsection 2.2.4). A broader qualitative description of the risks and issues considered is provided in subsection 2.3.4. The identification of transformers to be replaced has also included consideration of other factors, including strategic timing such as undertaking a range of capital works simultaneously at one site (such as the various projects planned for the Kinleith substation during RCP2).

Replacing these risk-prone transformers will result in reduced failures, outages, maintenance costs, environmental impact, and safety risk.

Replacement economic justification

A high-level cost-benefit analysis has been conducted to estimate the economically optimal age for replacement of a typical 220 kV single-phase transformer, and compare Net Present Value (NPV) costs with a ‘run-to-failure’ strategy. This study is summarised in Appendix D. The costs and benefits taken into account in the study include capital costs, maintenance costs, transmission losses and unserved energy from major failures or repairable failures on the parallel branch. The analysis shows that it is better to replace a transformer at a certain age than to allow it to run to failure, even before the less easily quantified effects are considered.

The predicted optimum age for replacement depends on the analysis assumptions, but is around 60 years. This is similar to, or slightly higher than, the nominal life expectancy used in other jurisdictions. The NPV of costs of the replacement policy are approximately 5% lower than those of ‘run-to-failure’. The NPV and optimum age for replacement should be taken as conservative because the less easily quantified risks all favour earlier replacement.

Prioritisation of transformer replacements

A broad risk management approach is required for making decisions about prioritising transformer replacement. This should take into account system criticality, fleet-wide experience, individual condition assessment information, GXP performance and availability of matching spares. A fleet replacement plan has been developed that will schedule replacement of transformers based on multiple criteria including:

criticality

asset health and the unit’s contribution to fleet AHI (that is, units with high moisture and high loading, defective tap changers, defective bushing models, and so on)

a focus on aged, single-phase transformers given their high maintenance costs and relatively high forced and fault rates

priority given to older 220 kV transformers given the higher likelihood for winding failures from high-voltage stresses




spares coverage (that is, single-phase on site spare, three-phase strategic spare or mobile substation)

consideration of overall site strategy

historic GXP performance and targets.

Programme cost

The costs of transformer replacement are estimated on a case-by-case basis using our process for customised cost estimation. This approach is used rather than volumetric forecasting because of the large-scale unit costs and because of the significant differences between sites. Further details on the cost forecasting process are provided in subsection 4.1.5.

Our plan for the RCP2 period includes 28 single-phase transformer replacements and 2 three-phase transformer replacements. The total costs of transformer replacements are estimated to be about $106.2m14 during the RCP2 period.

Impact of replacement strategy

Figure 12 shows the effect of the asset management plan15 on the forecast asset health of the power transformer fleet.

The asset health is forecast to improve significantly over the period to 2020, with the proportion of ‘Now Due’ reducing from 11% to 5%.

Figure 12: Transformers Forecast Asset Health

Benefits of modern three-phase transformers

Modern three-phase power transformers are manufactured based on computer aided designs (CAD) that have been refined considerably in recent years with improved materials, manufacturing processes and testing techniques. As a consequence, modern transformers are considerably smaller, lighter, quieter and more efficient than their older counterparts. They also have higher through-fault strength as CAD allow for significantly higher electromagnetic forces (generated by fault currents) than that used in empirical designs.

Our strategy to replace poor performing units with new three-phase units that also improve the environmental impact because three-phase transformers have less acoustic noise emissions compared with their older single-phase equivalents. Newer transformers are also less likely to leak oil.

14

See the Power Transformers Asset Management Plan for additional details. 15

This includes replacement, enhancement, development and divestment projects in the period 2013/14 to 2019/20.




Refurbishment strategies

Transformer mid-life overhauls and refurbishment

Do not undertake mid-life transformer overhauls during the RCP2 period.

Transformer refurbishments or mid-life overhauls can be alternatives to capital replacement.

As outlined in subsection 2.2.3, we have completed a programme of major overhauls on the majority of our single-phase transformers. The main purpose of this programme was not to achieve a material extension of the nominal life expectancy of the transformer,16 but rather to reduce ongoing maintenance requirements, reduce the rate of forced and fault outages, and mitigate some potentially serious modes of failure that could cause the transformer to fail to achieve its nominal life expectancy.17 This overhaul programme is now essentially complete.

There may be further scope to undertake refurbishment work that will achieve material life-extension for some units in our ageing fleet. However, there a number of factors that need careful consideration before we can make a refurbishment decision.

The amount of extended transformer remaining life, should a refurbishment be undertaken, is very difficult to determine with confidence.

The original design of a transformer is an important factor, as the merits of refurbishment depend on the robustness of the original design. It may not be prudent to refurbish a transformer with latent design defects that could subsequently cause an unexpected failure.

Three-phase transformers are generally much bigger, contain more oil and are more difficult and costly to transport than the older single-phase units. Depending on the location of the transformer site, it may be very expensive to transport the unit to a workshop for refurbishment.

If the transformer is to be removed from site for an extended period, it will usually be necessary to provide a temporary transformer to maintain security. The costs of mobilising and installing a temporary transformer may be prohibitive.

Establishing a standardised refurbishment programme is quite difficult as our transformer fleet consists of ‘bespoke’ transformers.

Based on the considerations listed above, we have decided not to plan for any programme of workshop-based transformer overhauls or refurbishment in the RCP2 period. Remedial works will generally only be undertaken in-situ.

4.1.3 Customer Connections

In addition to enhancement and renewal works we also plan installations of transformers for new or enhanced customer points of connection. These are subject to bilateral contracting arrangements and are not, in general, funded through the regulatory regime. In this respect our customers include:

16

A material extension to original design life expectancy is a requirement, if the work is to be classified as refurbishment and treated as capex.

17 The overhaul programme delivered many improvements in performance, but was unable to address some of the

fundamental reliability risks and issues resulting from the basic design and manufacture of the units.




generation companies – those that inject energy into the Grid

distributors – those that take energy off the Grid to distribute to consumers

large industrial companies – those that take energy directly off the Grid.

Customer consultation

Communicate our transformer strategies with relevant customers to manage

life-time risk.

We have specified a number of standard transformers to be used in future replacement works. If the use of these models presents issues for customers, the impacts (such as spares holding and security requirements) will be discussed with customers during the consultation process.

4.1.4 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 integrates capex across a moving window of up to 10 years in the future. This optimisation approach seeks to ensure that works are delivered and undertaken in an efficient and timely manner. Planning of all power transformer works takes into consideration relevant site strategies, required outages and resources, and any potential synergies with other projects. In particular, when seeking to optimise power transformer works we take the following factors into account:

supply transformer replacement works are to be co-ordinated with 33 kV outdoor to indoor switchgear conversion projects where practicable

customer supply outages should be avoided/minimised (that is, provide interim supply connections while assembling/building a new transformer or build the new transformer on a greenfield location)

coordinate transformer replacement work with major customer project works

ensure network security is maintained taking into account other projects occurring at the same time as the transformer replacement (we typically use a system project overview process to identify security risks and conflicts)

coordinate other protection upgrade work with transformer protection works (this may potentially reduce outages).

Many older substations have three or more relatively low-rated power transformers in parallel. When one or more of these are due for replacement, we consider whether or not to replace them with two higher-rated power transformers.

Some transformer replacements identified as a result of the replacement strategy may be implemented:

via ‘customer-led’ supply point upgrades

in response to load growth and the need to preserve N-1 security

via approved major capital projects.




The IWP process will ensure that these various investment streams are aligned using a whole-of-site coordination and prioritisation approach.

Customer-initiated transformer replacements

Align customer-driven transformer replacements with condition-based

replacements as appropriate.

Customer-driven projects are subject to differing drivers that are not as predictable as other transformer works. To accommodate customer requirements while balancing workload for other transformer replacement projects, we will seek to align condition-based replacement works with customer-driven transformer replacements to the extent practicable.

4.1.5 Cost Estimation

Cost estimation is a key stage of the capital investment process and forms a critical input into planning and is required at various stages in the planning process. Historically, cost estimates for power transformers were developed using proprietary systems. This has now transitioned to our central cost estimation team, which uses the cost estimation tool Transpower Enterprise Estimation System (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. We aim to achieve P50 cost estimates.18 The rationale behind this aim and further detail regarding our cost estimation processes is provided in the Planning Lifecycle Strategy.

P50 project cost estimation

Scope and estimate project works to a P50 confidence level (that is, the

estimate is based on a 50% probability that the cost will not be exceeded).

Transformer installations (whether greenfield or replacement works) will have elements that are unique to each particular project. This reduces the extent to which historic project costs can be relied on to forecast future projects. Transformer projects also involve relatively large investments which if inaccurately estimated can lead to large cost overruns and delays. Therefore the cost for each transformer replacement or new transformer has been estimated individually, taking into account the specific context, risks, and requirements of the transformer and the installation site using the customised cost estimation process.19

A key requirement for an accurate customised cost estimate is to establish a site-specific scope of work. To determine the scope, a design layout drawing is developed for each project. The likely location of the replacement transformer will be determined from a desktop review of aerial photographs, site layout drawings, underground services drawings, and available cable corridors for the new low-voltage cables. This assessment provides reasonably accurate estimates for the numerous variable quantities of materials and work (such as switchyard extension area, new fencing, new bay(s), power and control cabling, outdoor junction boxes, oil containment, lighting, lightning poles, fire walls, and so on).

18

P50 means that there is a 50% probability of the actual cost being below the estimate. 19

This assessment is later refined via a Solution Study Report investigation that informs the BC3.




One key challenge for cost estimating power transformer installations are the civil and earthworks costs. There have been cases where the ground conditions were not expected to be difficult until after the service providers began excavation. This risk can be mitigated by geotechnical investigations, but cannot be removed completely. At this high-level cost estimate stage, we take into account sites with historically known problematic ground conditions and include a risk adjustment (discussed below) to mitigate the estimation risk.

Assumptions

With every new transformer installation, an appropriate size transformer is selected from a set of 18 standard transformer sizes. Each new installation is priced to include earthing transformers, neutral earthing resistors, local service transformers and auto changeover schemes. Interconnector transformers are priced with the appropriate overhead conductor and gantry quantities, while supply transformers are priced with low-voltage incomer cables and associated accessories. The hardware cost is estimated based on prices from the current transformer supply panel agreement.

Further assumptions in developing the estimates include:

works will be priced based on the new transformer being built and pre-commissioned with the existing transformer in service (that is, a new bay if required and associated primary plant)

transformer plinths/bunds will be to the current standard, and sized to take the associated system spare transformer

transformer low-voltage cables will be sized to match the full rating of the transformer (and all new cables back to the indoor switchboard or existing outdoor yard).

In addition to the primary equipment and construction costs, a number of additional factors have the potential to impact the project cost. These include:

consenting and environmental costs

underground services (which may require relocation)

number of outages expected (which may require additional outage planning and switching costs).

These issues are considered for each individual site to assess whether they need to be included.

Estimation sources

We currently use the TEES US cost estimation tool as a ‘price-book’ for individual costs and unit rates. These component costs are based on historic, specific manufacturer quotes and period supply cost data. The transformer plant and installation costs have been determined by period supply contracts currently in place and historic installation costs respectively. Historically, both these cost elements have been quite accurate. The civil and earthworks costs are currently determined by a unit rate that has been extrapolated from historic costs.

Installation costs have been informed by similar previous projects, identified risks, and updated with current budget prices from installation service providers and the specific context of each transformer site. The main assumptions used for defining the scope of the projects to estimate the costs are set out below.




Risk adjustments

Reflect identified risks in expected cost for projects.

One key determinant of accurate cost estimates for capital projects is managing scope risk. As part of its customised cost estimation process for transformers, we have developed a specific risk estimation approach. We use this approach to determine the need for and magnitude of any risk adjustments to be applied to individual cost items.

The cost items to be considered will vary by project given the specific site conditions and equipment scope. In general, the main cost items that we risk adjust for include:

cable lengths based on transformer position

geotechnical/ground condition potential need for ground improvements, piling, and so on

excavation requirements and the potential for contaminated soil.

We have developed three typical scope ranges for each individual line item. Each range has three estimates for the ‘Minimum’, ‘Most Likely’ and ‘Maximum’ value. Using these ranges, we have derived a P50 estimate using a PERT20 distribution. The adjustment is based on likely quantities, as scope has tended to be the most significant variance on this type of work and we are reasonably comfortable with potential unit rate variances.

Further information on our approach to risk estimation is included in the Planning Lifecycle Strategy.

4.2 Delivery

Once 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 transformer fleet.

4.2.1 Design

Detailed design is undertaken during the delivery phase21 of the investment process by design consultants from a pool of preferred specialist consultants. The consultants will take the following six points into consideration.

Transformers are very heavy pieces of equipment (can weigh up to 300 tons). The foundation design must therefore take into account site specific ground conditions to ensure ground settlement is not an issue. The foundation will also need to fully comply with earthquake standards appropriate to the New Zealand environment, which are higher than many other countries.

It is critical that every effort is made to ensure that designs respond fully to the environmental conditions, to avoid problems (such as corrosion) that can lead to oil leaks, increased maintenance costs and premature end of life (or even failure).

20

Programme Evaluation and Review Technique – see the Planning Lifecycle Strategy for a discussion on how this has been used.

21 While design activities are undertaken during the Planning Lifecycle, the majority of detailed design takes place as part

of the Delivery Lifecycle.




An assessment is required of the need for firewalls to be erected around transformers where there is a fire risk to personnel and adjacent plant and buildings.22

We keep spare transformers in terms of the foundation design and primary connections.

We use standard transformer installation designs.

Existing or new underground structures (such as cable tunnels and drainage) are reinforced where transformer access is required over the underground structure.

Transformer specification

Standardise transformer specification to limit the diversity in the fleet.

Major power transformers are bespoke items, and there are typically only a few units manufactured for each design. The wide diversity in the existing fleet is a significant driver of increased maintenance cost and risk.

New transformers will be specified based on standard designs and footprints wherever practical, and use standard components such as tap changers and bushings. Although competition for the supply of transformers is required to maintain commercial tension, all reasonable efforts must be made to limit diversity during the design process. Table 9 lists the standard design ratings that we have adopted.

Function Voltage Ratio MVA Rating

Interconnecting 220/110/11 kV 250 150 100

220/66/11 kV 250 180

Supply 220/33 kV 120

(see note below) 220/11 kV *

110/33 kV 120 75/85 60 40

110/11 kV 20 10

66/11 kV 40

*Mainly for special industrial customers, rated as required

Table 9: Design Ratings – Power Transformers

Standard ratings were considered for all supply transformers, but because of customer requirements and the low number of likely purchases we deemed it impractical to set standard ratings for all future power transformers.

No standard 110/11 kV supply transformers over 20 MVA have been detailed because transformers rated above this rating are customer specific due to such factors as fault-level limitations within the customers networks.

Firewalls between existing power transformers

Where practicable, retrofit fire walls between closely spaced power

transformers rated 20 MVA or more with a criticality rating of ‘high’.

22

See Service Advisory TP.DS 61.06 SA1 – Firewalls for outdoor power transformers, dated 2 September 2011.




We will retrofit firewall protection on some existing at-risk single-phase and three-phase transformer installations. This requires a highly detailed examination of the physical spacing in air between units, the foundation pad oil bunding of each unit, the common oil piping shared between units, the shared oil interception facilities and the various shared power cable trenches that may allow burning oil to flow from one unit to another in the event of a single unit catching fire.

However, at some sites, the transformers are spaced so closely to each other, or to other equipment, that it is difficult or impractical to install firewalls.

Fifteen sites with 43 existing transformer banks must have fire walls fitted. This work is due to be completed during the RCP1 period.

Transformer site design

Future proof transformer site designs and layouts.

We will future proof transformer site designs and layouts by proactively considering likely future requirements and current requirements. This may involve:

ensuring the transformer bunded area has sufficient space to account for:

o future strategic spares and future larger transformers

o future firewalls that may be required

site oil interception and containment systems are sufficient to contain oil for future transformers.

On-line dissolved gas analysis monitoring

Provide online dissolved gas analysis monitoring equipment for all new

transformers with a criticality rating of ‘high’.

Experience in New Zealand and elsewhere has shown two main benefits of providing online dissolved gas analysis.

Online dissolved gas monitors can trigger a removal of a transformer in distress from service before major failure occurs. There are clear operational and safety benefits in being able to plan for urgent removal, rather than have a sudden forced outage occur.

In some cases, destructive power faults within the transformers may be avoided.

There are a number of points to consider before installing online dissolved gas monitoring on the fleet. An online monitor can provide advanced warning of serious internal deterioration. However, this warning may not necessarily provide a significant reduction in the ultimate costs of the fault. Following the indication of serious internal defects emerging, costly contingency measures, such as installing strategic spares, may still be required to restore security.

Overall, there is limited value from widespread installation of online monitors to existing transformers. Therefore, the installation of online monitors will be limited to all high-criticality transformers and problematic transformers as required.




4.2.2 Procurement

For more details of our general approach to procurement, see ‘The Sourcing, Supply & Contracts Approach (2011)’ and the Delivery Lifecycle Strategy.

Procurement issues relevant to the power transformer fleet during the RCP2 period are set out below.

Procurement risk

Mitigate risk in procurement through the detailed technical and economic

analysis of the tender and contract documentation.

The analysis of major power transformer failures over the past 30 years clearly indicates that the root cause of failure is latent design and/or manufacturing errors. Theses failures have generally occurred during the mid-life of the transformer. So it is essential that we take all practical steps to mitigate risks at the procurement stage.

Power transformers cannot be considered as ‘ex-catalogue’ items. They are bespoke and therefore considerable risk can arise with each design. The materials and manufacturing methods used to build the transformer are also continuously evolving so that the manufacturer can reduce or minimise costs – this builds in additional manufacturing risk with every new power transformer purchased.

The present risk management practice for power transformers includes:

purchase only from three pre-qualified power transformer suppliers with a proven track record

perform a design review at the manufacturer’s premises after award of a contract (see specific strategy below)

perform qualified inspection during key manufacturing stages and final factory acceptance testing of the power transformer

continually review and periodically audit the performance of the pre-qualified suppliers

continuously review the performance of the consultants and inspectors hired to assist with the design review, manufacturing inspections and witnessing of final factory acceptance testing.

All these risk mitigation activities should continue. The benefits of these activities include:

reduced risk of factory test failures and delays prior to delivery to the site

reduced risk of premature failures on site

reduced maintenance requirements as the transformer ages

better performance during emergency overload conditions and system faults

higher asset utilisation potential over the life of the transformer.




Component designs

Standardise component specification to limit diversity in the fleet.

Based on our historic failures and experience, there is a need to further specify the design for individual components in a transformer. Transformer bushings and tap changers are the main cause of transformer forced and fault outages. These two main components are standardised for new transformer specifications and the rationale is described below:

Bushings

As identified in subsection 2.2.3, resin bonded paper bushings are not reliable and have a high failure rate. This type of bushing is no longer used in modern transformer design. Resin impregnated (RIP) bushings with silicone sheds were introduced in the early 2000s.

A RIP bushing uses resin impregnated paper as solid insulation and contains no oil. It therefore presents a greatly reduced fire risk compared with previous oil filled technology. The reliability of RIP bushings is good, based on international experience and our own short experience, and they have recently been adopted as our standard requirement.

As described in subsection 2.2.1, bushings made of porcelain have a risk of ejecting sharp pieces of porcelain in the event of a bushing failure. Our standard specification now requires bushings using RIP and with silicone sheds.

Tap changers

As described in subsection 2.3.4, tap changer diversity is an issue in terms of requiring a vast knowledge base for tap changer maintenance. The strategy to address this risk on all new power transformers we have purchased is to accept a small number of standard type tap changers from only the two best manufacturers in the world. These two manufacturers also have a worldwide ability to service and repair their tap changers with their own skilled personnel in the event of a failure at site.

Other components

Other transformer componentry we are standardising on are online DGA monitoring equipment and using a particular manufacturer of high-quality oil pumps. The supporting rationale is noted below.

We have standardised online DGA monitoring equipment (including SCADA and communications hardware) to reduce complications associated with different makes and types.

We have standardised on a particular manufacturer of high-quality oil pumps for all our modern power transformers, because of the need for high reliability. Although oil pumps are generally very reliable, standardisation will improve interchangeability in the event of a fault.

Detailed design reviews

Ensure that design reviews are undertaken during design and manufacturing

processes.

Power transformers for transmission applications cannot be considered as ‘ex-catalogue’ items. They are customised, and therefore considerable risk can arise with each new design. Even with a proven design, risk can arise in the manufacturing process if there are




unacceptable departures from the design, or unsatisfactory materials are employed. Design reviews make a significant contribution to managing the risk of major failure. Benefits of design reviews include:

minimising the risk and subsequent cost of electrical failures, either in factory testing (leading to rework and delivery delays), or more seriously, major failures at site, possibly leading to loss of supply to end consumers

minimising accelerated degradation of oil and insulation, and reducing future maintenance and repair costs

allowing future operational overloading to be undertaken with confidence, and providing maximum utilisation of the asset with minimal risk of premature failures and problems resulting from such use.

4.2.3 Construction

The construction phase of an asset’s lifecycle is a significant determinant of quality and is characterised by particular safety risks. So our project management of construction projects is very important, and given substantial support and focus. To support the reduction of construction risks, we maintain a ‘lessons learned’ register for all construction projects that is fed back into how we manage future projects.

During the construction phase, it is standard practice for our project team to hold regular meetings with the service provider (together with the design team as appropriate) to address any construction issues and risks. Some of these issues and risks may need to be considered before actual construction begins and are addressed as part of the initial workshops. These workshops identify issues and risks associated with constructability, environmental, Safety by Design, operation and any required outages.

These construction issues and risks will need to be covered off on a site-specific, basis but in general may consider the following:

transformer delivery to site – for example, temporarily widening roads for the transformer trailer when you need to ensure roads and bridges can handle axle load of transformer and truck, and checking clearances to transmission lines and road access from port to substation

construction access

construction security – for example, temporary construction fences may need to be erected to prevent theft of materials and equipment

excavation – confirming that existing foundation capacities are not compromised by the new excavation, and taking extra care when excavating around areas where underground services are suspected to be not shown on maps or drawings

proximity to live equipment during construction

contingency planning is done throughout the whole construction process

extreme weather conditions

outage planning.

4.2.4 Commissioning

Commissioning is the process of bringing new or reinstalled equipment under the system controller’s normal real-time operational control of the power system. A commissioning plan




is prepared well in advance to draw together all the necessary resources and ensure the system operator’s needs are met. Pre-commissioning checks and commissioning supervision will help maintain a high success rate at commissioning.

Commissioning will often involve outages or system constraints to allow the project to be brought online. This will be followed by further testing to check whether the completed project is operating correctly.

Pre-commissioning testing

Test transformers prior to commissioning to ensure outage durations and

system implications are minimised.

Completion of all pre-operational tests of the transformer, accessories, and in particular the cooling system, is essential as these items are critical components that allow the transformer to operate correctly and safely while in service. The main items to be checked prior to livening include:

main transformer diagnostic tests: ratio tests, bushing power factor tests etc. completed as per the manufacturers requirements and the service specification SS.04.60

transformer accessories checked and functional tests completed: checking of Bucholz relay, pressure relief device, and so on

cooling system operation: fans/pumps operate in ‘manual’ and ‘auto’

electronic Winding Temperature Indicator (WTI): settings applied and WTI tested to confirm correct winding temperature calculations and correctly starting/stopping the fans/pumps.

visual checks: sight checks of equipment (such as ensuring radiator valves are open, and there are no oil leaks).

4.3 Operation

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 transformer assets.

4.3.1 Outage Planning

Power system outages for scheduled maintenance, unscheduled maintenance, and replacements must be planned meticulously to minimise disruption to customers.

Outage planning – power transformers

Plan and manage outages in a way that creates a safe environment for

employees while minimising the disruption for customers.

We coordinate with key stakeholders to ensure that any unavoidable system disruption and outages are notified well in advance so affected parties can prepare. This aligns with our service performance objectives.




Mobile substations

Ensure mobile substation at N security sites can be deployed in a timely

manner.

The majority of sites are designed with N-1 security, and this allows outages to be arranged for maintenance with reasonable flexibility. However, we also have a number of small capacity N security sites.

Outage planning at the N security sites is often highly constrained, because an outage leads to an interruption of supply to customers. To minimise impact on customers, maintenance must be completed in a very short timeframe. This often results in only priority maintenance being completed, and carries the risk of jobs being rushed.

Most N security sites have a primary operating voltage of 110 kV, but some sites operate at N security at 220 kV, 66 kV and 33 kV.

To mitigate the difficulties of maintenance and replacement works at N security sites, we have designed and built a 110/33-22-11 kV, 15 MVA mobile substation. This provides an alternative means of supply that will allow for extended outages at the 110 kV primary voltage N security sites.

Efficient placement and connection of the mobile substation requires enabling works at some sites.

Subject to case-by-case agreement with the customer, we will undertake enabling works at 110 kV N security sites to allow prompt deployment of the mobile substation.

4.3.2 Contingency Planning

The transmission network provides a critical infrastructure service for New Zealand. Failure of the transmission service leads to an immediate impact on end consumers and can result in large costs of disruption to economic and social activity. Some transmission asset failures can present serious safety hazards for employees and members of the public, or result in environmental damage. So it is essential that we have plans in place for responding promptly and effectively to transmission system incidents and emergency situations.

Contingency planning for power transformers focuses on reviewing and maintaining the holdings of spares and to ensure an adequate level of emergency preparedness.

No provision in the power transformer spares strategy is made for:

simultaneous failures of multiple transformers at one or more sites

generic problems or unexpected increases in future failure rates.

Simultaneous failures of multiple transformers at one or more sites may happen during infrequent but major events such as an earthquake or similar natural disaster. This is of particular concern with banks of single-phase transformers as the spares are mostly installed on-site, such that a major natural disaster could compromise the spares and the operational units. Yet transformers are installed with seismic restraints that are designed for local site conditions.

The priority for urgent response following a major catastrophe will be limited to immediately restoring sufficient power for emergency services until such time an investigation has been carried out to prioritise further areas for supply restoration.




Security of supply restoration

Restore security of supply within one calendar month of a major failure

occurring.

Our objective for contingency planning is to be able to restore full security of supply within one calendar month of the major failure of a power transformer.

We have a number of new three-phase spare transformers, dedicated spare transformers for single-phase banks, and other used transformers that are potentially available as spares. However, transporting and installing a spare transformer at sites not designed for the spare transformer may present challenges because of the bespoke nature of most transformer installations. The 1-month restoration target may be difficult to achieve at sites that require a new foundation, controls, or bus work.

To ensure that the contingency planning target can be achieved, deployment plans are required that set out the process and resources required to mobilise and install a spare transformer. The highest priority requirements are for deployment plans for the dedicated three-phase strategic spare transformers.

We will complete the preparation of deployment plans on a site-by-site basis, prioritised by criticality.

Strategic spare transformers

Maintain a fleet of strategic spare transformers to provide coverage for the

three-phase transformer fleet.

We carry a range of strategic spare transformers to allow us to restore system security following major failures. A summary of the strategic spares is given in Table 4 on page 11.

The ratings and numbers of strategic spare three-phase power transformers are based on 18 standard transformer designs. It is expected that approximately 70% of transformers procured over the next 10 years will be standard transformers (subject to customer requirements). The fleet of strategic three-phase spares now provides coverage for 98% of our entire present and expected future three-phase transformer fleet. Some key issues associated with the management of the spare transformers include:

as the fleet becomes more standardised, over the long term the need for diverse spares will reduce

spares will be distributed based on the types and numbers of the transformers in the region

strategic three-phase transformer spares will be stored at transformer parks located at Bunnythorpe and Islington

other three-phase transformer spares will be stored at warehouses at Otahuhu, Bunnythorpe and Addington

site specific single and three-phase transformer spares will be stored on site.

The emergency installation of three-phase spare transformers at existing sites is not necessarily straightforward because of the wide diversity of existing installation designs. A move to standardise the transformer foundation pads to facilitate easy replacement is being considered.




New transformer installations will be designed so that the corresponding strategic spare unit can fit onto the transformers replacement foundation pad if the need arises.

The make, type and ratings of on-load tap changers are extremely diverse and we have implemented a policy to standardise tap changers. As the numbers grow, we will consider purchasing a spare unit for the common types.

Replacement of strategic spares

Recover or initiate replacement of strategic spare within 2 years of

deployment.

When a strategic spare transformer is deployed, there is a significant increase in the risk profile associated with all remaining transformers that were previously covered by the deployed spare. The risk cover for the remaining power transformers should be restored as soon as is reasonably practicable. Strategic spares will either be recovered within 2 years (via repair or replacement of the original failed transformer), or, alternatively, we will procure a replacement strategic spare.

4.4 Maintenance

We and our service providers carry out ongoing works to maintain assets in an appropriate condition and to ensure that they operate as required. The maintenance undertaken seeks to proactively manage failure risk as well as responding to actual failures as these occur. Our approach to maintenance and the activities we undertake are described in detail in the Maintenance Lifecycle Strategy.

We classify maintenance tasks into the following categories:

preventive maintenance

- condition assessments

- servicing

corrective maintenance

- fault response

- repairs

maintenance projects.

The following discussion focuses on maintenance activities and associated strategies specific to the power transformer fleet.

4.5 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 feedback of information into the overall asset management system. Being the most common physical interaction with assets, it is also a potential source of safety incidents and human error. The main activities undertaken are listed below.




Inspections: non-intrusive checks to confirm safety and integrity of assets, assess fitness for service, and identify follow up work.

Condition Assessments: activities performed to monitor asset condition or predict the remaining life of the asset.

Servicing: routine tasks performed on the asset to ensure asset condition is maintained at an acceptable level.

We intend to implement the following preventive maintenance on our power transformer fleet in support of our objectives stated in chapter 3.

The detailed maintenance tasks and schedules for power transformers are set out in Service Specification SS 02.30.

Specific maintenance strategies

Include specific maintenance procedures in the maintenance documentation.

Our maintenance documentation is based on overseas standards and our own experience. An outline of our standard service requirements is set out below:

Bushings

Oil-filled bushings aged 35 years or more are to be inspected yearly to see that the oil level is within the operating range. The service provider shall also check the following, which shall be repaired if required:

oil quality

oil seals

oil sight glasses on oil filled bushings

internal dielectric strength on all types of bushings

condition of the exterior sheds on all types of bushings.

Bushing oil levels have been found to be below the operating range and not noticed because of oil staining on the white background of the oil level sight glass. A more thorough inspection will discern the difference between the oil level and the oil stain.

Bushing maintenance is required because the oil quality in oil filled bushings deteriorates due to weather-related ageing of oil seals resulting in moisture ingress. The internal dielectric strength of all types of bushings deteriorates due to moisture ingress, thermal stress, electrical stress and age-related weakening of internal insulation materials. Tests of the dielectric properties of bushings are undertaken every 4 years, to identify internal deterioration. The dielectric condition of older bushings is a particular area of focus.

On-load tap changers

The on-load tap changers are to be serviced in line with our specified requirements that supersede the manufacturer’s original recommended intervals and operations.

Our maintenance intervals have been selected to suit our own operational conditions. Our strategy is to ensure that all internal maintenance and servicing of tap changers is carried out by certified and fully trained personnel. The following aspects will be checked, and repaired if necessary:

tap changer contacts




drive mechanism

control cubicle

oil quality.

A certified and fully trained maintainer will service the tap changer completely, in line with the manufacturers recommended procedures, and will modify or replace components identified as suspect by the manufacturer.

The new vacuum contact type tap changers are low maintenance and very reliable, and although more costly when compared with other tap changers should be considered for high-operation situations.

Windings

Sweep frequency response analysis tests are carried out on all new transformers purchased (as from 2009), at a mid-life inspection, and/or after being subjected to a major through-fault, to determine if there has been a significant movement of the windings that may lead to failure.

Transformer oil

The need to maintain oil quality in power transformers is outlined in subsection 2.3.4.

Oil within all power transformers is tested at least annually and more regularly on poor performing transformers where there are deteriorating trends of DGA tests results or oil electrical parameter test results.

A full review of all oil condition in power transformers is completed on an annual basis to determine requirements for refurbishing or replacing oil.

Ancillary components

The ancillary components – particularly the monitors, indicators and protective devices – deteriorate relatively rapidly compared to the power transformer, and consequently are replaced once or twice in the life of the transformer. Modern transformers with forced cooling run considerably hotter than older air-cooled units. It is important that the temperature monitors and indicators, fans, pumps, and oil switches operate correctly, otherwise the transformer will overheat, causing considerable degradation of the insulation with subsequent loss of life. Mal-operation of ancillary equipment can also cause false tripping.

The correct operation of these devices is checked during the 4-yearly inspections of the transformer. The scope includes checks on oil temperature indicators, Buchholz relays, surge devices, flow switches, relays, wiring, cubicles, and online monitors.

Power transformer spares

On-site and strategic-power transformer spares are maintained regularly to the same standard as in-service transformers.

Safety during maintenance

Consider safety risks and mitigations when planning and carrying out

maintenance.

Maintaining power transformers involves a number of risks. The main risks and risk mitigations to consider when planning and carrying out maintenance are:




protective gear is to be worn when working with large quantities of oil

work at heights is a safety issue for transformers, because maintenance and repair works are often carried out at the top of the transformer, a substantial height above the ground. This risk has been reduced by installing fall arrest systems on all transformers. The risk will be further reduced in the RCP2 period with increased training and auditing of the use of the fall arrest systems when working on transformers.

Corrosion assessment

Detect corrosion before it deteriorates to the point where oil leaks may occur

and corrosion is too deep to repair.

Corrosion is a significant problem with many power transformers. Painted metal surfaces deteriorate due to weather conditions, and as a result of salt deposits and industrial pollution. Gaskets providing oil seals between bolted joints wear out due to thermal ageing and weather conditions.

Corrosion is an ongoing problem that varies with paint systems, climatic and regional conditions.

We plan to improve the maintenance process by taking photographs of corrosion at the yearly inspections and providing these together with a condition report for recording in our maintenance management system. This will allow the corrosion to be assessed and repaired at an appropriate time.

The photographs will show the extent and depth of corrosion, and together with our service provider we will use these photographs to help determine when and how the transformer is to be repaired.

4.5.1 Corrective Maintenance

Corrective maintenance includes unforeseen activities to restore an asset to service, make it safe or secure, prevent imminent failure and address defects. It includes the required follow-up action, even if this is scheduled some time after the initial need for action is identified. These jobs are identified as a result of a fault or in the course of preventive work such as inspections. Corrective works may be urgent, and not completed for a prolonged period, may reduce network reliability.

Corrective maintenance has historically been categorised as repairs and fault (response) activities. Repairs include the correction of defects identified during preventive maintenance, and other additional predictive works driven by known model type issues and investigations.23 Timely repairs reduce the risk of failure, improve redundancy and remove system constraints by maximising the availability of assets. Activities include:

Fault restoration: unscheduled work in response to repair a fault in equipment that has safety, environmental or operational implications, including urgent dispatch to collect more information

Repairs: unforeseen tasks necessary to repair damage, prevent failure or rapid degradation of equipment

23

Where the number of potential repairs is deemed sufficiently high, a Maintenance Project will be instigated to undertake the repairs works.




Reactive Inspections: patrols or inspections used to check for public safety risks or conditions not directly related to the fault in the event of failure.

Repairs

Transformer repairs include the correction of defects identified during preventive maintenance or fault response and additional predictive works driven by failure mode and effect analysis and investigations. High-quality repairs reduce the risk of future failure for in-service assets; for out-of-service assets they improve redundancy and remove system constraints by allowing the assets back into service.

We will make repairs to power transformers where a defect has been identified that could potentially result in a failure, or when a failure has occurred. In both cases, the repairs are carried out to support our service performance objectives. The general strategies for repairs on power transformers are outlined in the rest of this subsection.

Corrosion control

Carry out corrosion control on transformers to mitigate corrosion-related

risks.

The paint and galvanising systems applied to power transformers are specified to be suitable for severe environmental conditions, but cannot fully prevent deterioration or corrosion developing over time. General deterioration of the protective coatings typically necessitates repainting of a transformer two or three times in its lifetime.

The radiators in modern transformers are made of 1.6mm-thick galvanised mild steel and corrosion of these will rapidly cause oil leaks. The corrosion also weakens the steel and in the event of a rapid oil pressure rise, due to a through fault or oil pump starting, may burst causing a major oil leak.

The original protective coatings of small ancillary equipment such as monitors are often not in line with our current requirements. Significant corrosion can lead to risks of fault and forced outages. Deterioration of ancillary equipment is usually addressed by replacement rather than by painting.

We have identified a number of transformers as having corrosion problems requiring repair. It is expected that at least five transformers a year will require corrosion control work.

Transformer component replacement or refurbishment

Replace poor condition and obsolete components.

During the life of the transformer the ancillary equipment degrades more quickly than the main parts of the transformer. In most cases it is better to replace the ancillary equipment rather than to repair it. The ancillary components to be repaired or replaced include:

control systems and instrumentation

porcelain bushings.

Control systems and Instrumentation

Control and instrumentation systems on a transformer typically require replacement within the lifecycle of the main transformer. The scope of this equipment includes:




oil temperature indicators

Buchholz relays

surge devices

flow switches

relays

wiring

cubicles

online monitors.

Our standard control systems include modern winding temperature indicators that are now based on numerical processors. This type of monitor has been installed since 2000, and we forecast a requirement to begin replacing them at the end of their expected lives from around 2020.

Some transformers with older types of winding temperature indicator are still in service. Currently, we expect to replace at least one winding temperature indicator system each year. This work will be funded from the routine maintenance allowance.

Porcelain bushings

Bushings typically have a shorter service life expectancy than that of the main transformer.

Failures of transformer bushings present a serious safety risk because most bushings are porcelain types. Explosive failure can result in sharp shards of porcelain being propelled a considerable distance into the surrounding environment.

In 2011 we introduced a new standard specification for composite bushings, to eliminate the risks associated with porcelain. Our policy is now to replace all defective bushings with the new standard composite bushing, unless there is an identical and serviceable spare available.

Yet replacing a bushing can be a complex task if no spare bushing of matching dimensions is available. Retrofitting a modern equivalent bushing into an existing transformer may require building and fitting a new bushing turret, and considering carefully internal clearances within the transformer tank.

Oil treatment

Undertake oil treatment on transformers that give unsatisfactory oil tests

results.

We will maintain oil condition of the fleet by refurbishing or replacing oil as required. Oil in poor condition may be treated in-situ or replaced with new oil or regenerated oil. Regenerated oil is used oil that has been treated with a catalyst to restore it to a condition that meets the IEC standard for unused oil.

The forecast expenditure is approximately $300,000 each year. This work will be funded from the routine maintenance allowance.




Critical transformers with high levels of corrosive sulphur in oil

Replace the oil in three critical transformers already identified with high

levels of corrosive sulphur, and assess the extent of the problem in other

potentially at-risk transformers.

The risk associated with corrosive sulphur in oil is outlined in subsection 2.3.4. The risk cannot be completely eliminated without totally replacing the transformers or their windings.

Options for partially mitigating the risk include replacing the oil, or processing the oil and adding ‘metal passivators’. Early indications from international experience with the passivation technique suggest that it is not effective. So we consider that, for now, replacing the oil is the only appropriate solution.

Our strategy is that the oil in three transformers already identified with high levels of corrosive sulphur will be replaced with regenerated oil between 2015 and 2017. These transformers are at relatively high risk because they either have been highly loaded or have the ability to be highly loaded (one of the pre-conditions of failure resulting from corrosive sulphur). The transformers are:

Penrose T11 (220/33 kV, 200 MVA, manufactured in 1999)

Otahuhu T3 (220/110/11 kV, 250 MVA, manufactured in 2003)

Otahuhu T5 (220/110/11 kV, 250 MVA, manufactured in 2000).

We will replace approximately 190,000 litres of oil. We will also carry out further tests to establish the levels of corrosive sulphur in oil of all three-phase transformers purchased between 1995 and 2008. These tests will be carried out on 60 transformers, and we estimate that approximately 30 transformers will require a second test.

Online dissolved gas monitors

Retrofit online dissolved gas monitors on existing three-phase transformers

with gassing problems.

Transformers are DGA tested yearly and more frequently if excessive gassing is occurring. Fitting online dissolved gas analysis monitors can help us understand how gassing transformers are performing, and assist in any decision to remove the transformer from service before it fails.

We have identified a total of 34 three-phase transformers that have excessive gassing: 28 are from the population manufactured before 1992. Two of the more recent units have been fitted with online gas monitors, leaving potentially 32 transformers that may warrant the installation of online dissolved gas monitors.

We plan to install online DGA monitors on the following four transformers over the RCP2 period:

TAK T5

TAK T8

TKU T21

TKU T22.




These four transformers have been selected because of excessive gassing and their high criticality. The remaining 28 transformers will be monitored by more frequent DGA tests.

4.5.2 Maintenance Projects

As discussed in subsection 2.2.5, 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.

We do not currently intend to undertake maintenance projects for the power transformer fleet during the RCP2 period.

4.6 Disposal and Divestment

The disposal and divestment lifecycle phase includes the process from when planning for disposal of an asset begins through to the point where we no longer own the asset.

Asset disposal includes the decommissioning of the asset, after which it may be sold as a functioning asset, sold as scrap, disposed of to a waste management facility, or re-used by us elsewhere as an in-service asset or a spare. Asset divestment involves the sale of the asset in situ. Divestment often involves the sale of assets to customers, including electricity distribution businesses and large electricity users.

4.6.1 Disposal

The implementation of asset disposal also 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.

Decommissioning and disposal process

Follow an appropriate disposal process where re-use is not appropriate.

Requirements for recovery and recycling/disposal work include safe work and site management processes and appropriate probity and environmental responsibility of scrap disposal processes.

Some decommissioned transformers are retained as spares for specific sites where there are concerns about the condition of the existing units and they are not adequately covered by general spares.

Yet most older transformers are scrapped and the oil sold for regeneration. The components are mostly obsolete and have deteriorated to the point where they cannot be re-used.

The metal such as steel and copper is recovered, smelted and re-used.

Because of environmental risk issues, the oil is sold to a licensed oil dealer for regeneration and re-use, as it is a valuable and diminishing product. The re-generated oil meets the International Electrotechnical Commission’s requirements for unused insulating oil and is considerably cheaper than unused oil.




4.6.2 Divestment

Implementation of divestment is primarily the change of ownership, although we must also remain aware of any safety and environmental issues and technical impacts on the Grid such as a change in constraints and flexibility of Grid operation.

Asset transfers

Rationalise assets at the boundary through asset transfers to customers.

We are proceeding to transfer a number of assets at the fringes of the existing Grid to our distribution business customers. This process is described fully in the Disposal and Divestment Lifecycle Strategy.

The current plan for asset transfers will result in the power transformer assets noted in Table 10 being transferred to customers in the RCP1 and RCP2 period.

Voltage 33 kV 66 kV 110 kV

Number 1 16 13

Table 10: Number of transformers being divested across RCP1 and RCP2 periods

The total number of transformer banks to be transferred represents 8% of the total transformer fleet as at June 2013. Yet the impact on lower voltage transformers in the fleet is significant. The transformers operating at 66 kV that are included in the asset transfers represent 35% of that portion of the present fleet. In addition to some direct savings in transformer maintenance costs, the asset transfer programme will remove some makes and models of equipment from the fleet, and allow some rationalisation of spares and maintenance procedures.

4.7 Asset Management Capability

This section describes the specific strategies for obtaining and maintaining capability in managing and handling power transformers. These strategies provide medium-term to long-term guidance and direction to ensure that asset managers and their staff have the required capabilities in regard to fleet management.

We require our 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. This will ensure satisfactory and safe functioning of the network while minimising whole-of-life costs.

The capability strategies are described under the following headings:

Risk Management

Asset Knowledge

Training and Competence.

4.7.1 Risk Management

Our approach to risk management is central to our asset management decision making as we weigh up the various costs and benefits of options such as replacement timing. We are developing asset health and criticality models to improve and integrate our risk-based asset




management. The strategies below discuss how we plan to progress this in regards to the power transformer fleet.

Power transformers asset health model

Refine the power transformers asset health model.

Over RCP2 we will work to improve the power transformers asset health model to provide better forecasts of future replacement requirements and to inform replacement prioritisation. This may include:

Applying a robust and systematic scoring system to the entire fleet based on condition testing such as SFRA, DGA, Furans and/or oil moisture content testing

being aware or notified of significant new risk issues, and incorporating these into the asset health model (that is, utility peer alerts to specific design defects with certain transformer makes/models)

tap changer operation counts – forecast expected tap changer end of life based on manufacturer recommended operation count limit and historic records of operations

external condition modelling – model steel degradation based on corrosion zones and frequency of maintenance/painting

developing hazard functions for particular characteristics that affect asset health

reviewing our model against international guidelines for asset health (CIGRE study group is currently preparing a guideline for use).

4.7.2 Asset Knowledge

Robust asset knowledge is critical to good decision making for asset management. Asset knowledge comes from a variety of sources, including overseas experiences, experience from assets on our network, theoretical modelling, and information from the manufacturers. This asset knowledge must be captured and recorded in such a way that it can be conveniently accessed when future asset management decisions are made. A key part of improving our asset knowledge is the commissioning of the new Asset Management Information System (AMIS).

Knowledge of transformers

Improve the knowledge of existing transformers through accurate recording

and frequent maintenance of asset information.

Transformer asset knowledge is paramount in determining asset health, fault analysis, end of life predictions and replacement decisions. As mentioned in subsection 2.3.4, transformer asset knowledge is currently decentralised and while the information we currently have is generally sufficient, there are efficiencies and improvements to be found.

The recent implementation of our new asset management information system (MAXIMO) enables a number of business improvements in data gathering, storage and retrieval processes. As part of these business improvement processes, we have prepared standard maintenance procedures that will allow for more accurate recording and frequent maintenance of asset information.




For power transformers, we intend to further improve our asset knowledge by recording the following information into a centralised database:

external condition assessments – including any corrosion, bushing damage, leaking terminals on pressure relays and oil leaks with photographic records during each assessment

main tank oil test results – including oil quality test reports, furans, corrosive sulphur, oxidation stability tests and inhibitor tests

tap changer oil tests

tap changer operation counts – record operation counts at each station inspection

SFRA test results (following system through-faults)

electrical test results – winding tests, bushing tests, tap changer tests and control system tests

all maintenance fault repairs and test records – including tap changer (off-load and on-load tap changers), winding faults, internal lead faults, CT faults, bushing faults, control system faults and system through-faults.

photographic evidence of the on-load tap changer drive cubicles and diverter switches to be recorded in the database during maintenance.

As mentioned in subsection 4.5.1, the transformers with gassing issues have already been identified and online DGA monitors will be installed on four of these transformers. The existing online DGA monitors are connected to the SCADA system the data is easily retrievable.

4.7.3 Training and Competence

Our overarching strategy for maintaining and improving worker competence can be summarised as follows:

all persons (our employees, service providers and sub-contractors) working on our assets must be properly trained and currently competent for the tasks they undertake

all maintenance service providers must comply with the competency criteria set out in the relevant Service Specification.

employers must manage the currency of competencies of their workers for the work they undertake to the appropriate requirements of the relevant Service Specification.

We have three service specifications that define the competency requirements for working on power transformers:

TP.SS 06.23 Minimum competencies for power system equipment operation

TP.SS 06.21 Minimum competencies for substations maintenance and testing

TP.SS 06.25 Minimum requirements for Transpower field work.

We must maintain a minimum baseline of skilled workforce: engineers and site works operators who understand the physical assets.




Capability for major repairs

Ensure a continued capability within New Zealand for major repairs of power

transformers.

One of the benefits of the historic programme of transformer overhauls was that it provided three workshops and trained staff to undertake investigation of transformer faults and carry out major repairs. The overhaul programme has now come to an end, and some of the skilled personnel involved in this work are no longer available. This has affected our ability to undertake major invasive repairs of power transformers in New Zealand.

The history of transformer faults and failures shows that some serious internal defects in transformers are economic to repair. Recent examples of economic repair of serious internal defects include the Clyde 3-phase 220/33 kV transformer, and a Waitaki single-phase 220/110 kV interconnecting transformer.

We need to preserve a credible capability in New Zealand to undertake major internal repairs of power transformers, where this is economic. This capability is required based on:

the expected future failure rate from internal causes

the likelihood that a proportion of internal faults will be economically viable to repair

the potential for some invasive repairs to be conducted on site, providing that appropriately skilled personnel are available

the likelihood that some invasive repairs will require the transformer to be relocated from site to a controlled workshop environment

the high cost of replacement transformers

the lead time for replacing major power transformers.

A number of three-phase units with elevated gassing may require invasive inspection and repair in future. We also expect that some future transformer winding failures may be economic to repair locally, compared with replacing the transformer or sending it overseas for repair.

Maintaining some form of transformer major repair capability in New Zealand will, under appropriate circumstances:

enable timely and cost-effective repairs on site (where feasible)

reduce the need to deploy strategic spares to restore security

reduce the period of time that strategic spares are deployed at sites

reduce the need for faulty transformers to be replaced, or to be sent overseas for repair.

We will review our ongoing requirements, and define the minimum baseline capability that we require in future for undertaking invasive repairs.

Tap Changer training

Establish specific targeted training for tap changer maintenance and repair.

We will run tap changer training for those service providers who work on tap changers.




Tap changer maintenance has a particularly high rate of HEIs after tap changers are reassembled incorrectly. By focusing on such common errors, training is likely to substantially improve performance.

4.8 Summary of RCP2 Fleet Strategies

Our individual strategies for the fleet of power transformer assets are summarised below for each lifecycle stage.

Planning

Enhancement and

Development

Ensure that the transformer fleet is managed to ensure compliance with Grid reliability standards in

support of our objectives and procure and install new transformers to enable system growth.

Replacement and

Refurbishment

Replace single-phase and three-phase transformers with more reliable new three-phase units based on

failure risk.

Do not undertake mid-life transformer overhauls and during the RCP2 period.

Communicate our transformer strategies with relevant customers to manage life-time risk.

Integrated Works

Planning Align customer driven transformer replacements with condition-based policy replacements as appropriate.

Cost Estimation

Scope and estimate project works to a P50 confidence level (that is, the estimate is based on a 50%

probability that the cost will not be exceeded).

Reflect identified risks in expected cost for projects.

Delivery

Design

Standardise transformer specification to limit the diversity in the fleet.

Where practicable, retrofit fire walls between closely spaced power transformers rated 20 MVA or more

with a criticality rating of ‘high’.

Future proof transformer site designs and layouts.

Provide online dissolved gas analysis monitoring equipment for all new transformers with a criticality

rating of ‘high’.

Procurement

Mitigate risk in procurement through the detailed technical and economic analysis of the tender and

contract documentation.

Standardise component specification to limit diversity in the fleet.

Ensure that design reviews are undertaken during design and manufacturing processes.

Commissioning Test transformers prior to commissioning to ensure outage durations and system implications are

minimised.

Operation

Outage Planning

Plan and manage outages in a way that creates a safe environment for employees while minimising the

disruption for customers.

Ensure mobile substation at N security sites can be deployed in a timely manner.

Contingency

Planning

Restore security of supply within one calendar month of a major failure occurring.

Maintain a fleet of strategic spare transformers to provide coverage for the three-phase transformer fleet.

Recover or initiate replacement of strategic spare within 2 years of deployment.




Maintenance

Preventive

Maintenance

Include specific maintenance procedures in the maintenance documentation.

Consider safety risks and mitigations when planning and carrying out maintenance.

Detect corrosion before it deteriorates to the point where oil leaks may occur and corrosion is too deep to

repair.

Corrective

Maintenance

Carry out corrosion control on transformers to mitigate corrosion-related risks.

Replace poor condition and obsolete components.

Undertake oil treatment on transformers that give unsatisfactory oil tests results.

Replace the oil in three critical transformers already identified with high levels of corrosive sulphur, and

assess the extent of the problem in other potentially at-risk transformers.

Retrofit online dissolved gas monitors on existing three-phase transformers with gassing problems.

Disposal and Divestment

Asset Disposals Follow an appropriate disposal process where re-use is not appropriate.

Divestments Rationalise assets at the boundary through asset transfers to customers.

Capability

Risk Management Refine the power transformers asset health model.

Asset knowledge Improve the knowledge of existing transformers through accurate recording and frequent maintenance of

asset information.

Training and

Competence

Ensure a continued capability within New Zealand for major repairs of power transformers.

Establish specific targeted training for tap changer maintenance and repair.




Appendices




A POWER TRANSFORMER IMAGES

Figure 13 is a photo of a typical single-phase installation.

Figure 13: Typical single-phase transformer installation

A traverser track is provided, allowing individual units to be readily moved and exchanged using a transport trolley. In the event of a major failure of a single unit, the outage time required to remove the failed unit and install the spare unit is approximately 12 hours.

Figure 14 is a photo of a typical 3-phase installation.

Figure 14: Typical 3-phase transformer installation

The physical arrangement of the transformer in this example has been optimised for the particular site or design. There are considerable differences in physical arrangement between transformers of similar rating from different manufacturers, and for different projects. There is little or no direct interchangeability.




B ADDITIONAL COSTING INFORMATION

Other equipment and works

HV AIS Surge Arresters will be installed on all new transformers.

LV AIS Surge Arresters will be installed on all new transformers that have AIS bushings.

Costs shall be included for connecting the new transformer bund to the existing oil containment/separation system. If the existing system is inadequate, then costs shall be included to bring it up to current standards.

An assessment will be made of the requirement for fire walls, and costs included.

If the transformer protection is due for replacement within 5 years of the transformer replacement, then the transformer protection will be brought forward and replaced at the same time as the transformer (and the protection costs included in the transformer customised cost estimation).

If the local service transformer(s) are located in the existing transformer bunds, costs will be included to replace them based on current standards.

If the transformer being replaced already has an NER fitted, a new NER will be installed on the new transformer.

Costs will be included to install NER’s on the transformers where they are not already installed.

If the location of the new transformer requires the existing fence to be extended and/or new access roads creating, costs will be included for the associated works.

Costs will be included for draining and removing the existing transformer, plus associated redundant primary equipment (CB/CT/DS)

Demolition costs will be included for removing the redundant transformer plinth and bund, and for reinstating gravel.

Costs will be included for transporting the old transformer and associated primary plant back to our nearest store.

Demolition costs will be included for removing the plinths from the associated redundant primary equipment (CB/CT/DS) and costs included for reinstating gravel.




C ADDITIONAL BENCHMARKING RESULTS

Average age comparisons

The following two figures taken from the ITOMS 2011 international benchmarking round compare the average age of transformer fleets. The majority of our transformers fall into the category of < 100 MVA. We are represented by the letter ‘K’.

Figure 15 indicates that the average age of our fleet of power transformers is about 10 years older than the average of all the participants in the study.

Figure 15: International Comparison < 100 MVA Transformer Age (ITOMS 2011)

Figure 16: International Comparison - 100-350 MVA Transformer Age (ITOMS 2011)

Maintenance cost comparisons

The following two figures taken from the ITOMS 2011 international benchmarking round compare the average maintenance expenditure on transformers. The scope of maintenance for the purposes of this study includes all routine diagnostic testing and servicing, and reactive work including repairs.

The results indicate that our maintenance costs are significantly higher than the average of the study participants, for both voltage classes.

Figure 17: International Comparison – 100 kV–199 kV Transformer Maintenance Costs (ITOMS 2011)




Figure 18: International Comparison – 200+ kV Transformer Maintenance Costs (ITOMS 2011)

Performance summary comparisons

ITOMS data is normalised by various factors and comparisons need to be treated with care. However, the total forced and fault outage rate of 110 kV and 220 kV transformers is considerably worse than the average of the ITOMS 2011 benchmark group.

The graphs in Figure 19 and 20 provide international comparisons of the maintenance cost and the performance of transformers.

Figure 19: 100 kV–199 kV Transformers – International Comparison

of Performance and Maintenance Cost (ITOMS 2011)




Figure 20: 200+ kV Transformers – International Comparison

of Performance and Maintenance Cost (ITOMS 2011)




D TRANSFORMER ASSET STRATEGY ECONOMIC ANALYSIS, 2010

Executive summary

This document outlines a high-level cost-benefit analysis that we have conducted to estimate the optimal retirement age of a typical 220 kV transformer and compare with a ‘run to failure’ strategy.

One important assumption in the analysis is that the range of measures described in the Asset Strategy will reduce the failure rates for new transformers. This document discusses the economic case for further reducing the overall failure rate by retiring transformers, eliminating the older units with the higher failure rates.

The costs and benefits taken into account include capital costs; maintenance costs and transmission losses, both of which are reduced for modern three-phase transformers; direct costs of major failures; and unserved energy from parallel major failures or repairable failures on the parallel branch.

Other effects are more difficult to quantify and have not been taken into account. They include reputational and environmental risks; the impact of diminished industry, business and community confidence on the national economy; the (very low) risk of fire; short outages and risks involved with off-load tap changers; and problems associated with spares for older transformers.

The analysis shows that it is better to replace a transformer at a certain age than to allow it to run to failure, even before the less easily quantified effects are considered. The predicted optimum age for replacement depends on the analysis assumptions but is around 60 years old. The NPV of costs of the replacement policy are approximately 5% lower than those of ‘run to failure’. Both these figures should be taken as conservative because the less easily quantified effects all favour replacement.

The greatest increased benefit of a replacement strategy comes from the lower probability of parallel major failures and the consequent lower probability of extensive loss of supply. Because parallel major failures would be a high impact low probability (HILP) event, both the probability and the duration of the outage are difficult to estimate, but it is reassuring to see that the predicted optimum replacement age is similar to, or slightly higher than, the regulatory life used in other jurisdictions.

D1 Introduction

The analysis is a statistical Net Present Value calculation on a typical 220 kV transformer position, with the probabilities of the transformer failure at various times taken into account.

The sections that follow are:

typical transformer assumptions – the size, loading and losses of the typical transformer

failures – a detailed discussion of the assumptions behind the major and minor failure rates

economic assumptions – the economic parameters required for the calculation

lifecycle costs – capital and maintenance costs of a typical transformer as well as salvage value

results.




D2 Typical transformer assumptions

In the study we have kept the analysis as generic as possible, focusing on a typical existing 220 kV single-phase transformer bank and its replacement with a new three-phase transformer.

D2.1 Size

The existing fleet of 220 kV single-phase transformer banks has the distribution of sizes shown in Table 11. We have used a size of 100 MVA, the median, as typical.

Size (MVA of bank) Number

50 17

60 2

100 4

120 8

160 2

200 10

210 2

Total 45

Table 11: Distribution of sizes of 220 kV single-phase bank transformers

D2.2 Loading

Most 220 kV transformers are in N-1 configurations, either multiple supply transformers at the same substation (for example, Penrose), or providing multiple entry points to a lower voltage network (for example, Halfway Bush and Roxburgh). As most of these are in N-1 pairs, rather than larger groups, the peak loading is often less than 50%. We have chosen 30% as an estimate of the peak loading.

D2.3 Losses

Transformers dissipate energy via heating of the iron core, which is approximately independent of the load (so-called ‘iron’ or ‘no load’ losses) and via heating of the copper windings, which is approximately proportional to the current squared (‘copper’ or ‘load’ losses).

Copper losses have not changed with advances in transformer technology and remain approximately 4 kW/MVA at full loading Iron losses have decreased significantly, as Figure 21 shows. From approximately 1.25 kW/MVA for single-phase transformers manufactured in the 1960s, iron losses have reduced to 0.4 kW/MVA for modern three-phase replacements.




Figure 21: Iron Losses

D3 Failures

Major (catastrophic) failures and their causes are discussed in some detail in the Asset Strategy. With the assumption that the transformer is in an N-1 configuration, a single major failure does not result in loss of supply. However, parallel major failures could have serious consequences – 100 MW or more of load unsupplied for up to a month. All resources would be mobilised to fix the problem, but in practice there might not be any solution faster than installing a spare.

Minor failures on the branch parallel to a major failure are also significant, but to a lesser extent. Parallel minor failures are extremely unlikely (assuming there is no common cause) and will be ignored.

D3.1 Time dependence

The time dependence of the major failure rate can be estimated by considering the failure history and the expected effects of new policies.

Major failures in our fleet since 1978 are listed in Appendix E of the Fleet Strategy. The historic failure rate by transformer age decade is shown in the black line in Figure 22, with the dashed lines as error bounds. The function increases with time as is expected. The error bounds are wider for older transformers as there have been fewer surviving to a greater age.

No Load Losses of Transpower Transformers

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

5.00

1940 1950 1960 1970 1980 1990 2000 2010 2020

Year of Manufacture

No

lo

ad

lo

ss

es

kW

/MV

A




Figure 22: Failure Rate

The failure rate for 220 kV transformers only is plotted as the red line in the same figure. As the red line is outside the error bounds of the black line in the first and fourth decades, we can conclude that 220 kV transformers aged 0 to 10 years and 30 to 40 years have more major failures than transformers of the same age but lower voltage. For ages 10 to 30 the position is less clear – 220 kV units perform worse than average but not significantly in a statistical sense. For ages greater than 40, there are too few data points for any inferences to be made.

In contrast to the clear distinction between 220 kV and < 220 kV transformers, there is no evidence that single-phase banks have different failure rates from three-phase transformers. Nor is there any evidence that more recently manufactured transformers perform better. So the primary motivation for replacing single-phase banks with three-phase transformers is to reduce the failure rate through operating newer transformers.

The overall average failure rate is the average of the black line, weighted by the number of transformer-years of each age in the data. It is approximately 0.4% each year.

Many of the early failures are from only a small number of types. Many may stem from the historic ‘least cost’ procurement policy in the 1960s–1980s. We expect that major failures will be rarer as a consequence of our improved specification and procurement process. The Fleet Strategy presents strategies that will be used to bring the failure rate down as much as possible.

The blue line in Figure 22 represents a failure rate per age that these strategies should produce. It asks for a considerable reduction in failures in the second and third decades.

0 10 20 30 40 50 600

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

1.8

2

years

Failu

re R

ate

, %

per

annum

Failure Rate for Transformers: Entire Fleet and HV = 220 kV

History: All

History: Error Bounds

History: Error Bounds

History: HV = 220 kV

Target




The target for the fleet is 0.3% a year for major failures – a significant but not unachievable reduction.

The values on the blue line will be assumed for new transformers in the remainder of this study. Existing transformers will be assumed to follow the black line

It is more difficult to estimate failure rates for later dates, but we assume the values included in Table 12.

Tabulated in Table 12 are the corresponding values of the reliability function representing the fraction surviving to the end of each decade.

Existing Transformers New Transformers

Age (Years) Failure Rate

(% p.a.) Reliability at end

of period Failure Rate

(% p.a.) Reliability at end of

period

0-10 0.3 0.97 0.25 0.98

10-20 0.1 0.96 0.24 0.95

20-30 0.1 0.95 0.37 0.92

30-40 0.54 0.9 0.69 0.86

40-50 0.93 0.82 0.57 0.81

50-60 1.3 0.72 0.95 0.74

60-70 2.34 0.57 2.55 0.57

70-80 3.05 0.42 3.05 0.42

80-90 4.42 0.27 4.42 0.27

90-100 8.11 0.12 8.11 0.12

100-110 10.99 0.04 10.99 0.04

110-120 Large 0 Large 0

Table 12: Failure rates and reliability factors

D3.2 Replacement timing

The time to replace a transformer after major failure depends on various factors including

whether an on-site spare exists

existence and location of an off-site spare

ordering time of a new transformer

difficulty of configuring the pad and connection for a new transformer

substation access.

For this typical transformer analysis we assume 30 days are required, in line with the strategic spares programme. For a first failure of an existing single-phase bank, this could be a considerable over-estimate (if on-site spare is available) or under-estimate (if no matching spare is available at all), but we expect that it will be a reasonable estimate on average.

D3.3 Parallel major failure

As most 220 kV transformers are installed in parallel pairs, a single failure will not result in a loss of supply. Yet failure of the parallel unit, before the first can be replaced, represents a significant risk. The asset strategy notes that near-coincident failures of parallel transformers do occur. Of the 30 major failures in the history, 3 were parallel failures within a year and 1




(the failure of the two Whakatu 220/33 kV transformers 22 days apart at age 4 years in 1984), occurred within 30 days. There have also been several near misses.

From this admittedly very sparse history, we conservatively estimate the probability of the second major failure, before a spare is in place to cover for the first, at 1-in-50 major failures.

For this analysis we assume that the time with both transformers out is half the replacement time, or 15 days, and that the load lost averages 60 MW, twice the assumed single transformer load.

Parallel major failures are clearly High Impact Low Probability (HILP) events. The probabilities and costs of such events are very difficult to estimate, and a risk-neutral cost-benefit approach may not be the best method of including them. It can be argued that such an approach tends to under-value the severity of the potential events. With this caveat, we consider the values here reasonable in these circumstances

D3.4 Parallel minor failure

If a transformer is out due to a major failure, then the supply is vulnerable to the failure of any asset on the parallel branch. Based on analysis of transformer branches, we estimate the probability of branch failure at 70% each year and the average outage duration at 23 hours. The duration is from the mean of all minor outages, capped at 15 days for the average time of replacing the first transformer.

D3.5 Failures at a transformer device position

There is an important distinction between the failure rate for an individual transformer and that for a transformer device position. If the transformer installed in a position has a major failure then it must be replaced. So, through time, more than one transformer may occupy the same position. It is the costs associated with a device position that must be compared between strategies. The mathematical relationship between the individual transformer failure rate and position failure rate is discussed in Appendix D9.

D4 Economic assumptions

Valuing the cost of outages requires a value of lost load (VOLL). We use the Grid investment test24 (GIT) value of $20,000 first used in 2004 which gives $23,000 inflating to 2009 at 3%.

The discount rate for NPV calculations is 7% (real), also from the GIT. A ‘public good infrastructure’ rate of 4% is included as a sensitivity.

Valuing of losses requires a cost of the extra energy that is lost. The quantity to use is the long run marginal cost of generation, which is in the region of $80/MWh.

D5 Lifecycle costs

The cost of a new ‘typical’ transformer is estimated at $4m. Failed transformers can be sold for scrap for approximately $50,000 for each single-phase unit or $100,000 for each three-phase unit.

Maintenance costs are approximately $13,000 for each single-phase unit and $16,000 for each three-phase unit.

24

Electricity Governance Rules, Schedule F4, Grid Investment Test at http://www.electricitycommission.govt.nz/pdfs/rulesandregs/rules/rulespdf/PartFSectionIIIScheduleF4-gridinvestmenttest-17Jan08.pdf

http://www.electricitycommission.govt.nz/pdfs/rulesandregs/rules/rulespdf/PartFSectionIIIScheduleF4-gridinvestmenttest-17Jan08.pdf

http://www.electricitycommission.govt.nz/pdfs/rulesandregs/rules/rulespdf/PartFSectionIIIScheduleF4-gridinvestmenttest-17Jan08.pdf




When a major failure does occur there is the direct cost of moving equipment, draining and filling transformers, connections, and so on. A conservative estimate of the cost is $500,000.

D6 Results

The numbers below represent the average costs for the next 60 years on a per transformer position basis under the strategies of ‘run to failure’ and ‘replace at age 60’, for a transformer currently 40 years old.

‘Run to failure’ ‘Replace at age 60’

60 year cost

($,000s) 60 year NPV

($,000s) 60 year cost

($,000s) 60 year NPV

($,000s)

Capital

- policy replacement

$0

$0

$3,310

$850

- replacement after major failure

$4,560 $630 $1,270 $360

Maintenance $1,830 $510 $1,390 $460

Losses $5,440 $1,490 $4,310 $1,360

Major Failures

- direct costs

$590

$80

$160

$50

- parallel major failure $11,830 $1,640 $3,290 $920

- minor failures on parallel branch

$2,130 $300 $570 $170

Total $26,380 $4,650 $14,300 $4,170

Table 13: NPV of costs

The analysis shows that it is better to replace a transformer at a certain age than to allow it to run to failure, even before the less easily quantified effects are considered. The predicted optimum age for replacement depends on the analysis assumptions but is around 60 years old. The NPV of costs of the replacement policy are approximately 6% lower than those of ‘run to failure’.

The table shows that an expected reduction in the number of major failures, and the consequent direct costs, replacement cost and parallel failure risk, is the greatest benefit of replacement.

The failure costs in the table depend on assumed probabilities of major failure, which are greater for older transformers.

Figure 23 shows the NPV of the replacement policy as a function of the replacement age. The asymptote is the limit as the replacement age tends to infinity (that is, the NPV of ‘run to failure’).




Figure 23: NPV of costs

Replacing all transformers too early brings forward capital costs which outweigh any savings. Not replacing them at all results in more major failure events. The best compromise for this set of assumptions is replacement at 60 years of age.

D6.1 Sensitivities

We vary various parameters that could influence the result.

Sensitivity Ideal retirement age NPV saving over run to

failure ($,000s)

Base Case 60 $480

Discount rate 4% 58 $1,870

VoLL doubled 56 $1,350

Parallel Major Failure Doubled

60 $1,210

Parallel Major Failure Halved

63 $130

Table 14: Sensitivity analysis

The sign of the NPV result is robust against these sensitivities, but the magnitude does vary. The ideal retirement age is relatively stable.

NPV of Typical Transformer Position Costs vs. Replacement Age

$3,000,000

$3,200,000

$3,400,000

$3,600,000

$3,800,000

$4,000,000

$4,200,000

$4,400,000

$4,600,000

$4,800,000

$5,000,000

40 42 44 46 48 50 52 54 56 58 60 62 64 66 68 70 72 74 76 78 80 82 84 86 88 90 92 94 96 98 100

Age of Replacement of Transformers

Replace at age x

Run to failure




D6.2 Other jurisdictions

Information from other transmission owners and operators on the expectation of major failures is difficult to find. Most publicly available literature focuses on post-mortems of serious events and preventative measures. However SP AusNet25 does draw similar conclusions on replacement, with an ‘allocated technical life’ of 40 to 60 years.

D6.3 Conclusions

Within the limitations of this analysis, and in particular the difficulties of estimating failure rates, there is evidence that replacing 220 kV transformers at around 60 years of age will save around 5% of the net NPV cost-benefit of operation over running to failure. The age of replacement is robust against a range of sensitivities. The magnitude varies with the sensitivities considered here, but the net benefit is always positive

Sixty years should be regarded as an over-estimate because of the difficulty quantifying various effects not included in the analysis, all of which would favour earlier replacement, and because of the HILP events involved.

D7 Failure rate calculations

There are three equivalent ways26 of describing the time to failure of an item

Probability density functions

The probability density function (pdf) for failures, f(t), is the probability of getting a failure at time t for each transformer that starts at time 0. Every transformer eventually fails exactly once so

0

1f t dt

( 1 )

Reliability function

The reliability or survivor function, R(t),

0

1t

R t f u du ( 2 )

represents the chance of an item surviving to time t.

25

Electricity Transmission Regulatory Reset 2008/9-2013/14, Appendix E, Asset Management Strategy, SP AusNet, Melbourne, 2007, page 66.

26 M Rausand and A Høyland, System Reliability Theory: Models, Statistical Methods and Applications, Wiley, 2004,

page 15.




Failure rate

The failure rate, z(t) measures the probability of failure at time t per transformer in service at time t. It is the quantity usually measured

0

failure probability

number surviving

( )

( )

1

t

z t

f t

R t

f t

f u du

( 3 )

0

failure probability

number surviving

( )

( )

1

t

z t

f t

R t

f t

f u du

( 3 ) inverts to

0

exp

t

f t z t z u du

( 4 )

The rate is calculated using the Kaplan-Meier estimate27 of the reliability function and then

converted to the failure rate using

01

t

R t f u du ( 2 )and

0

exp

t

f t z t z u du

( 4 ). For the bounds we assume that z(t) follows a lognormal distribution with variance given by standard likelihood methods28 and take a 95% confidence interval of log(z(t)).

D8 Reliability functions of subclasses

The fleet of transformers is divided in two in several ways to test which variables have a bearing on the probability of major failure. 220 kV units versus lower voltage units is discussed in the main text.

Single-phase versus three-phase

Figure 24 shows the reliability functions for the two subgroups of single-phase and three-phase transformers. Neither falls outside the bounds of the entire population estimate. The

27

E L Kaplan and P Meier, Nonparametric estimation from incomplete observations, J Amer. Statist. Assoc., 53, 457–81. 28

J Kalbfleisch and R Prentice, The Statistical Analysis of Failure Time Data, Wiley, 2002, page 17.




only exception is for three-phase transformers over 40 years old of which there are very few.

There is no evidence to suggest that three-phase transformers as a group have a different major failure rate from single-phase transformers.

Figure 24: Single-Phase versus Three-Phase reliability

0 10 20 30 40 50 600.55

0.6

0.65

0.7

0.75

0.8

0.85

0.9

0.95

1

No evidence of different failure rates, Single Phase vs. 3 Phase

Survival Function for Transformers: Single Phase vs. 3 phase

All

Bounds

Bounds

3 Phase

Single Phase




Pre-1975 versus Post-1975

To test the relationship between major failures and date of manufacture we split the fleet into two parts, those installed before1975 and those installed in 1975. The date was chosen based on evidence from Energy Australia that distribution transformers show a shift in failure rate at this date. The results are shown in Figure 25. There is no evidence that more recent manufacture makes a difference to the failure rate.

Figure 25: Pre-1975 versus Post-1975 Reliability

D9 Position failure rate

The position failure rate is most easily expressed in terms of the individual unit failure probability density function as distinct from the failure rate.

Define ( )p t as the position failure rate or pdf.29 The two are equivalent as the number

surviving is always 1 for a position. ( )p t has a term for failure of the first transformer bank;

plus a term for failure of the second transformer, which was installed new when the first failed at some previous time; plus a term for failure of the third transformer, installed new when the second failed, and so on. So, ignoring replacement times,

'

1 3 1 3 3 1

' 0 ' 0 '' 0

( ) ( ) ( ') ( ') ' ( ') ( ' '') ( '') '' '

t t t

t t t

p t f t f t t f t dt f t t f t t f t dt dt

( 5 )

29

Strictly, p(t) is not a pdf as its time integral is greater than 1, but that is not important in this context.

0 10 20 30 40 50 60

0.65

0.7

0.75

0.8

0.85

0.9

0.95

1

No evidence of different failure rates, Pre- vs. Post-1975

Survival Function for Transformers: Pre- vs. Post-1975 install

All

Bounds

Bounds

Pre 1975

Post 1975




an infinite sum of self-convolutions, where 1f t is the pdf for the existing single-phase

bank failures and 3f t is the pdf for new three-phase transformer failures.

For times less than the average life of a transformer, the series in ( 5 ) converges rapidly as many failures at the same position are unlikely. We have calculated the integrals by discretising at a resolution of one year and truncated at the second term.

If there are closed forms available for 1f t and 3

f t , then ( )p t may be calculable via

Laplace transforms as ( 5 ) and properties of the Laplace transform imply that

1

3

,,

1 ,

L f t sL p t s

L f t s

( 6 )

where 0

, st

t

L f t s f t e dt

is the Laplace transform operator. The most likely

forms for 1f t and 3f t fitted to data points are piecewise linear or a polynomial

restricted to [0, the maximum life]. In these cases ,L p t s is a complicated expression

involving exponentials and rational functions and does not obviously lead to a useful form for ( )p t .




E POWER TRANSFORMER WINDING FAILURE HISTORY

Major failures are winding failures that require the transformer to be out of service for many months or up to two years while the transformer windings are

repaired or the entire transformer is replaced.

Device Voltage Phase Type Manufacturer Manufacturing

year Failure

Year

Age when failure

occurred Failure Cause Notes

HEN T2 220/33 kV Single Supply IEL 1966 1980 14 Design/manufacturing

error

HEN T3 220/33 kV Single Supply IEL 1966 1998 32 Design/manufacturing

error

BPE T9 220/33 kV Single Supply English Electric 1954 1988 34 Design/manufacturing

error

STK T9 220/33 kV Single Supply CGE 1964 2003 39 Design/manufacturing

error

HAM T5 220/33 kV Single Supply Mitsubishi 1972 2006 34 Design/manufacturing

error

PEN T8 220/33 kV Single Supply Tyree Aus 1976 2008 32 On-load tap changer

Design/manufacturing error

WHU T3 220/33 kV Three Supply Hawker Siddeley 1976 1984 8 Design/manufacturing

error

WHU T4 220/33 kV Three Supply Hawker Siddeley 1976 1984 8 Design/manufacturing

error

WIL T3 220/33 kV Three Supply Mitsubishi 1980 2004 24 Manufacturing error

CYD T8 220/33 kV Three Supply Tyree Power 1987 2006 19 Water ingress

LTN T2 220/33 kV Three Supply Hawker Siddeley 1976 2010 34 33 kV winding

design/manufacturing error

KAW T11 220/110 kV Three Interconnector Italtrafo 1979 1988 9 Design error

KAW T12 220/110 kV Three Interconnector Italtrafo 1979 1988 9 Design error





year Failure

Year

Age when failure


MDN T2 220/110 kV Three Interconnector Savigliano 1966 2007 41 Design error

PEN T10 220/110/11

kV Single Interconnector Savigliano 1973 1981 8 Design error

OTA T1 220/110/11

kV Single Interconnector Ferranti 1962 1996 34


HWB T4R 220/110/11


HWB T4B 220/110/11


HWB T4R 220/110/11


The original unit was scrapped and spare moved into position however this unit failed too.

ISL T4 220/66/11

kV Single Interconnector Brown Boveri 1959 1981 22


BRY T5 220/66/11

kV Single Interconnector CGE Canada 1959 1984 25


BEN T2R 220/33/16


Incorrect tap changer operation

BEN T2Y 220/33/16


Incorrect tap changer operation

TMN T5 220/55 kV Three* Traction OEL 1987 1990 3 Design error

TMN T5 220/55 kV Three* Traction OEL 1987 1993 6 Design error Was repaired and failed a second time.

BPE T15 220/55 kV Three* Traction OEL 1987 1993 6 Design error

TNG T3 220/55 kV Three* Traction OEL 1987 1995 8 Design error

ARI T9 110/50 kV Single Interconnector ASEA 1952 1994 42 Design/manufacturing

error

EDG T2 110/50 kV Single Interconnector Ferranti 1953 1998 45 Operator error Earth Sticks left on 50 kV bus accidentally

HEP T2R 110/33 kV Single Supply Parsons 1969 1981 12 Design error





year Failure

Year

Age when failure


HEP T2R 110/33 kV Single Supply Parsons 1969 1985 16 Design error Was repaired and failed a second time.

HEP T2Y 110/33 kV Single Supply Parsons 1969 2003 34 Design error

MPE T2 110/33 KV Single Supply Mitsubishi 1972 1990 18 Design/manufacturing

error

KAW T1 110/11 kV Single Supply ASEA 1954 1990 36 Design/manufacturing

error

MTM T3 110/11 kV Single Supply Brush 1954 1997 43 Design/manufacturing

error

KWA T2 110/11 kV Three Supply Siemens 1996 2008 12 Manufacturing error

KWA T3 110/11 kV Three Supply Siemens 2010 2010 0 Air ingress Air ingress during oil filling

WPT T1 66/11 kV Three Supply Crompton Greaves

1954 1978 24 Design/manufacturing

error

UTK T1 66/11 kV Three Supply Metropolitan

Vickers 1952 1994 42


ADD T3 66/11 kV Single Supply ASEA 1948 1976 28 Design/manufacturing

error

ARI T10 50/11 kV Single Supply Metropolitan

Vickers 1951 1978 27


TUI T9 50/11 kV Single Supply English Electric 1952 1996 44 Design/manufacturing

error

WPW T2 11/11 kV Three Regulator English Electric 1950 1985 35 Design/manufacturing

error




F HISTORIC TRANSFORMER ‘MID-LIFE’ OVERHAULS

Since 1990, we have undertaken invasive maintenance and repairs on a large number of single-phase transformers. This programme of work began with internal repairs on single-phase interconnecting transformers at Benmore, where previous failures had indicated a systemic problem with overheating winding connection leads.

The experience gained with this work led to a wider programme of invasive maintenance and overhauls of ‘mid-life’ transformers, and three specialist service provider facilities were established to undertake this work with workshops at Henderson, Bunnythorpe and Islington.

The primary purpose of the work was to address emerging issues of corrosion and oil leaks, and to dry out the transformer and re-clamp the windings. During this work some internal defects such as burnt leads were also corrected.

The main purpose for this programme of work was to address a range of defects and improve the likelihood that the transformers would achieve their originally intended design life. This work is generally only carried out only where overhaul is economic compared with replacement, taking into account the remaining life of the transformer before overall risk factors or projected load growth would necessitate replacement.

The overhaul programme focused almost entirely on single-phase transformers. These typically presented a more pressing case than the average three-phase transformer in terms of oil condition, serious external corrosion and oil leaks. An operational spare unit is available with most single-phase transformer installations, and this usually enabled all units of a bank to be progressively overhauled by rotation of the spare unit.

In contrast, few three-phase transformers have undergone major overhaul. This is partly because of the higher priority of single-phase transformers, but also because of the unacceptable security risk created by removing the transformer from service for an extended period for major overhaul, given that strategic spares have only recently been available.

Over 300 transformers have been overhauled in the workshop based programme over the past 11 years. The total costs of mid-life overhaul projects range from $2m to $4m each year over this period.

The operational performance of overhauled transformers has been good, with only one major failure occurring following overhaul. The work scope included transport to a specialist workshop facility, followed by de-tanking, major overhaul and dryout.

By 2013, all the single-phase transformers that are the best candidates for the mid-life overhaul programme will have been completed. The remaining single-phase transformers are generally over 50 years old, and are not considered economically viable for such major investment.

acs power transformers

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