A major challenge
to transformer engineers of power utilities and major industries is the
management of an ageing transformer fleet. Predicting transformer failure is as
unpredictable as that of predicting share prices in the market. This makes it
difficult to effectively plan mitigation strategies to reduce the impact of
such failures. The other challenge is replacing assets too soon without getting
the maximum benefit out of its useful life.
The following
paper defines an asset management strategy for Power Utilities on how to manage
power transformers. This becomes extremely important, especially for the
effective management of an ageing fleet of transformers. Failure of critical
transformers can leave a utility crippled with resultant production costs up to
ten times the capital cost of equipment. The aim of this paper is to clearly
map out a process to establish a risk profile of the transformer fleet and a
strategy on how to mitigate such risk by incorporating effective condition
monitoring techniques, design and investment strategies for the utility.
Power transformers are one of the key components of a
power circuit, especially for power utilities and heavy industries. The high
capital costs involved in the purchase of a transformer means that for the best
investment the replacement should be differed as late as possible or to the
optimum point.
Do you ask the following questions?
- How is my transformer fleet doing?
- Do I need to plan for refurbishment?
- When will a transformer fail?
- What is the risk of failure?
- Which are my high risk transformers and how does one mitigate the risk?
- How does one determine the optimum replacement point of a transformer?
Managing your transformer fleet properly and knowing
the condition of your transformers will help immensely in getting to the answers
of the above questions. It is of utmost importance to have a structured
approach to solving these problems. Time and human resources are limited and
every transformer cannot get the same attention. It is up to the transformer
engineer to formulate a system to effectively identify problem transformers for
focussed attention.
When one starts
out with a large transformer fleet it can be an overwhelming task to identify
which transformers need special attention or replacement. A transformer fleet at
a power utility serve many applications and have varying levels of importance. The
following factors play and important role in focussing the attention. These are
rating, voltage levels, importance, redundancy, spares, and similar type in
fleet. The first task of a transformer engineer is to record as much
information on the transformer fleet as possible. Start with recording all
details on the name plate of the transformer. This information must be stored
in a database and forms the basis for analysis.
For , starting
from a transformer fleet of 70 transformers, Figure 1 below gives an immediate
picture of where most of the transformers are. The key transformers are the
higher rated Generator Step-Up (GSU) and Station transformers.
Figure 1
Age
Profile
Transformers
no matter how well they run have a limited design life. Establish an age
profile of the transformer fleet. Record the year of manufacture and take this
as the reference age. Calculate the present age of the transformers and plot on
a graph to give a quick picture of the age profile for the current transformer
fleet.
Figure 2
Profile the Transformer Importance
It is very
important to establish what percentage of the transformer fleet are critical
transformers and the impact of these transformers. Establish how many of the
same type of transformers are available and number of spares. Of importance is
the MVA rating, low and high voltage levels and percentage impedance. Focus
must be given to the high impact transformers. For Power Utilities, these are
usually GSU and station transformers and to some extent unit transformers.
The basic
approach to condition based assessment is to use the oil as the primary
indicator of the internal condition of the transformer. Condition based
assessment allows the transformer engineer to identify what is happening inside
the transformer without the risk of going into the transformer. Insulation life
is a function of thermal ageing of the system. It is reasonable to expect that
the transformer insulation systems will last the expected 30-40 years at full
load if the system is maintained in a good condition. Failure or end of life
occurs as the result of a variety of mechanisms including poor oil preservation
systems. Thus, it is necessary to examine the causes of deterioration of the
paper and oil properties. This is based on dissolved gas analysis (DGA) and
electrical testing.
Young
identified the following as being some of the monitoring offered by the
industry; winding and oil temperatures, internal partial discharge, oil
moisture content, on-line DGA, tap changer monitoring, oil and air flow,
external hotspots by infra red photography, pump and fan motor bearing wear [1].
Ranking the
transformer according to health criteria would assist in refining the focus
transformers. Transformer ageing is caused primarily from three effects. These
are hydrolysis, pyrolysis and oxidation [2, 3]. It follows from here that the
levels of moisture, temperature and oxygen must be controlled to within limits.
Studies on Furan
compounds have provided some correlation to the degree of polymerisation and
the mechanical strength of the paper insulation [4-6]. Due to paper insulation having
a direct correlation to the life of a transformer, Furan results could give a
rough idea of the condition of the paper without having to get a paper sample.
This crude method can be used as a high level guide on the paper insulation
ageing of the transformer. This method is however limited by the replacement or
processing of the oil.
On can
establish a rating system based on the DGA, condition of the oil and Furan
levels. Dissolved gas analysis has been extensively utilised for incipient
fault detection by the following methods; key gas analysis [7], the Dornenburg [8], Duval [9, 10],Rogers [11] gas ratio method and those
highlighted in the ANSI/IEEE standard [12]. Use limits specific for similar
transformers as each transformer would exhibit different gassing profiles
according to design and materials used. The limits can be based on hydrocarbon
gas limits and furan levels.
The total number of short-circuit and voltage surge events also
contribute to the health of the transformer. Although a transformer might have
been designed and tested to withstand mechanical stress resulting from external
faults, the latter must nevertheless be considered as an ageing factor. The
clamping force of many transformers is reduced over time due to the shrinking of
insulating material. Historical data of incidents are very important and every
time an incident occurs these must be recorded and the assessment of the
transformer revisited.
Power utility
transformer fleets have remained relatively reliable over the last decade
resulting in few alarms and focus by the engineer, however it has become
evident that most utilities are ending up with an ageing transformer fleet.
Compounded by this is the increase in demand for electricity which results is
assets being operated more at and beyond its capabilities. This has a dual
effect as assets age faster and causes the probability of failure to increase.
With the
network being further strained the probability of incidents are increasing
causing the ageing transformer fleet to be exposed to high number of through
fault conditions. Through faults are infamous for exposing ageing and weak
insulation which results in instantaneous failure of the transformer. These
failures are difficult to pick up and remain a high risk for the transformer.
It is thus quintessential to make sure that the transformer electrical
protection is reviewed and settings appropriately set to eradicate fault
conditions as soon as possible.
Lapworth and
Mcgrail have highlighted the following transformer asset management strategies;
replace on age, replace on failure and replace on condition [13]. The replace on age offers a low
risk option but this option is capital intensive and does not allow for full
utilisation of the asset. Replace on failure on the other hand makes full use
of the asset but failures are at in-opportune times with risk of damage to
neighbouring plant, forced outages with related penalties, and compromise of
safety of personnel. The third strategy is to replace the transformer when its
reliability to satisfy system requirements cannot be met anymore. This also
enables for a planned replacement which allows adequate time for quality
reviews and manufacture and better economic management.
Figure 3
highlights a typical life cycle of a power transformer with high seven
steps.
Figure 3
Step 1: Specify and Manufacture
This step is
where the detailed specification for the transformer is specified together with
the manufacture and transport of the transformer to the site. This is very
important step as it defines the operating conditions of the transformer and it
is where one has control of the internal structure of the transformer. A bad
design can mean a short lifespan of the transformer. It is highly recommended
that an intense design review is conducted as a hold point. Transport is also a
high risk process and proper quality plans and checks must be in place to
manage transport over sea and road.
Step 2: Install & Commission
This step
introduces many risks especially on the interface points of the transformer.
These must be clearly defined and comprehensive detail provided. If the
contractor is responsible for the installation of the transformer, all scope of
work must be clearly defined. The project program must include all activities
and proper records must be provided for every step in the process.
Step 3: Operate
This step
represents the flat part of the bath tub curve. It is where the transformer
operates without any major problems. Normal condition monitoring must be
carried out during this phase. This includes six monthly dissolved gas sampling
and analysis to identify incipient faults. This can also be supplemented by
on-line DGA monitoring. The oil condition must also be monitored by routine
sampling for dielectric strength, moisture and acidity. Paper condition can be
monitored crudely by taking yearly Furan sampling which can be trended to
establish breakdown rates. The furan levels are affected by oil processing and
oil replacement which makes this method is ineffective if carried out. Routine
thermal scanning of the transformer also helps in establishing localised
hotspots and problems with the cooling system. This can be done three monthly.
Step 4: Inspect & Maintain
This step
covers the normal routine inspection and maintenance of the transformer.
Routine inspections must be carried monthly especially by operating personnel.
This involves visual checks on the general condition, recording of oil and
winding maximum temperatures (reset max dial), tap changer readings and general
components like cooling and protection.
Maintenance
also plays an important role in ensuring the good operating condition of the
transformer. This includes maintenance of the tap changer, cooling fans and
pumps, tan delta testing of bushings.
Step 5: Repair
Small repairs
are necessary to maintain the transformer life. This includes repairs to oil
leaks, tap changer, fan and pump motors and rust with repainting of the tank.
Step 6: De-commission
Decommissioning
of the transformer takes place when it is replaced or when it has faulted and
cannot be reused. This includes for the proper dismantling and storage in a
temporary storage area. Arrangements must be made for the removal of the oil.
This especially becomes a challenge when the Utility undergoes a comprehensive
replacement strategy which results in hundreds of thousands of litres of
oil.
Step 7: Dispose
This phase of the life cycle covers the proper removal and disposal of
the transformer. Before the transformer can be scrapped a post mortem must be
carried out to gain valuable experience on the mechanism of failure and weak
areas. This is particularly important if there are similar transformers within
the fleet. The teardown can be done according to “IEEE Guide for Failure Investigation,
Documentation, and Analysis for Power Transformers and Shunt Reactors”. This
guideline provides a procedure to perform a failure analysis and is primarily
focused on power transformers used on electric utility systems where it
encourages the establishment of routine and uniform data collection procedures during
the failure analysis process [14].
Phases A & B
Phase A of the
life cycle is composed of steps 3, 4 and 5 which consist of the longer term
process of the transformer lifecycle. It is noted that over the past years due
to the reliability of transformers being relatively good most of the focus had
been on this phase of the lifecycle. This phase is the normal operating of the
asset, maintenance with timely inspections and minor repairs to improve
reliability and availability of the asset.
Phase B
however comes into play when there is a need to purchase and replace a
transformer either due to failure or planned replacement. This phase is made up
of steps 1, 2, 6 and 7. This phase can take up to two years from compiling the
specification, issuing and evaluating the tender enquiry, design, manufacture,
factory acceptance, decommissioning of the old transformer, installation and
commissioning of the new transformer and finally disposal of the old
transformer.
Of recent
years due to most of the assets reaching end of life and premature failures
transformer engineers have been focusing more on procurement, design, commissioning,
decommissioning and disposal of assets. Due to these activities not being
everyday activities the expertise for such work is limited which result in some
delays and longer down times on the plant. It is thus of utmost most importance
to have a structured approach and to document and share experiences within the
organisation on typical learning’s to improve the overall quality of the asset
management process.
An important
part of the asset management process it is to have a clear picture of the
longer term plan for each transformer. This map provides all time frames
covering present life, remaining life, life extension possibilities, system
health life and major maintenance activities. These are defined in more detail
below. This plan can then be used for the life cycle costing and financing of
the projects.
Station Life
Start the
process by first establishing the remaining life of the Utility, Power Station
or specific unit. This sets up the scene for the future decision making. Plot
this in years starting from the present year. In figure 4 an example is made
for Gariep Power Station with 2007 as the base year.
Design Life
Record the design life of the transformer. This
is usually taken according to history or trends in the transformer fleet,
industry experience or experience of similar type of transformers in the world.
For the power station transformers this was taken as 30 years. The present age
of the transformer is then subtracted from this age to estimate a crude
remaining life of the transformer. In the case of GSU transformers 1 and 2 this
was -4 years which means that the transformer should have already been
replaced. This method however does not take into account the transformer
condition and only provides a guide. The
next step is to estimate the System Analysis Life
Figure 4
System Analysis Life
After carrying
out condition monitoring on the transformer the transformer health is
established and the remaining life is refined to establish a more accurate
estimate. From the above example it is estimated that GSU transformers 1 and 2
have a remaining life of 2 and 3 years respectively after 2007. This step
brings the influence of the actual condition of the transformer into consideration
and provides a more accurate estimate.
Major Maintenance and Testing
It is
advantageous to include all major maintenance activities on the plan so that it
can be budgeted and planned for in the long term. In this example consideration
is made for oil filtering, oil replacement and tan delta testing of the
bushings.
Life
Extension Possibilities
After assessing the profile and replacement strategy
it is prudent to explore for life extension possibilities. There are no rules
to the criteria for selecting a life extension strategy but one can assess this
by evaluating the remaining life and present condition around 5-10 years before
the end of station life. It is important however to maintain a healthy
condition of the transformer from inception. Key life extension methods would
entail timely maintenance especially of the on load tap changer and bushings,
reduction of oxygen and moisture levels in the transformer, removal of sludge
and reduction of acidity levels, replacement of oil depending on condition,
reduction of hotspot temperatures by reducing frequent overloading and through
fault conditions.
Refurbishment/Replacement
This decision
must be planned at least two years before the estimated end of life of the
transformer. The decision for replacement or refurbishment becomes a business
decision and takes into account the present condition of the tank and core,
return on investment, quality of rewind companies within the country, transport
costs and potential for up rating. If transformers have aged prematurely with
inherent design defects it is possible to consider a redesign of the windings.
This option can be more cost effective than purchasing a new transformer.
Condition
monitoring techniques form an important part of the asset management
strategy. The trend is moving towards
on-line methods that are non intrusive. The advantage of this is that
information on the transformer condition is continuous and allows for early detection
of incipient faults so that planned mitigation and recovery strategies can be
put in place.
Such methods
consist of on-line DGA which consist of equipment measuring up to eight
dissolved gasses. These trends can be obtained either as 4-20mA outputs or via
communications to be linked directly onto the station SCADA system for easy
access.
On-line
measurement of oil and winding temperature consisting of 4-20mA analogue output
are now becoming the standard. These are also transmitted to the station SCADA
system. Transformer manufacturers are now starting to adopt fibre optic sensors
to get direct hotspot temperatures of the windings. These also have a 4-20mA
output for easy connection to data acquisition systems.
Online
moisture measurement is also fast becoming part of the condition monitoring
tool. These are usually being added as supplementary to the on-line DGA
equipment. These devices help to access the flow of moisture from the oil to
paper to oil and establish cyclical load dependence.
Centralised
data acquisition systems are the next phase to condition monitoring. It is
becoming more important for manufacturers of condition monitoring equipment to
focus not only on the technology of sensing key data but how this data can be
effectively transmitted and analysed. International standards like IEC 61850 are
assisting in the convergence of data processing and should be clearly
highlighted when specifying such equipment. It is important for all this
information to feed into one place where some intelligence can be built in to
form automatic analysis of data. This provides the transformer engineer with
more meaningful focussed information and saves time by alerting to abnormal
conditions.
Over the last seven
years the Power Station has been involved in numerous transformer projects.
This consisted of 3 GSU transformer rewinds and five GSU transformer purchases.
The replacement program has offered numerous opportunities for learning due to
the tight project schedules and availability of plant.
The most
important part of the replacement program is to have a clear picture of what
transformers need replacement. It is important to get all stakeholders involved
at the start of the project. These include plant operators, maintenance and
production engineers and related plant engineers. The specification and
assessment of tenders is the start of a very important process in the future
asset management of transformers. It is critical that a proper design review is
undertaken by experienced personnel. The customer must also insist on a Factory
Acceptance Test (FAT) of the transformer and ensure that the international
acceptance standard IEC76 is clearly complied with.
Transformer
interfaces are the highest risk areas. Careful attention needs to be paid to
this aspect of the design. These interfaces consist of low and high voltage
bushings connections to the plant and system busbars, cooling water interface,
electrical and control interfaces to the plant, fire protection systems.
Interface drawings play a key role to a successful transformer installation. It
is thus important to have as built drawings when issuing a tender for a new
transformer. First step is to measure and survey the site with the supplier to
make sure that all interface points are clearly noted and planned for.
The logistics
of a transformer replacement program must be taken into account in the overall
project plan. Key aspects like oil disposal if not properly planned can eat
into valuable outage time resulting in delays of the overall project schedule.
Over the
recent years a power Utility was heavily exposed to premature failures of
transformers and it was evident that a reassessment was necessary in respect of
the spares philosophy of critical Generator Step-up (GSU) transformers. It is
recommended that an assessment is carried out on the transformer fleet to
identify transformers that can be inter changed with minor modifications and
holding spare transformers between such stations or transformers.
Figure 5
The landscape is constantly
changing and focus on the transformer fleet must be continuous. Figure 5
provides a picture of how the Asset profile for the GSU transformer changes in
a span of ten years from 2002 to 2012.
Graph A provides the age profile
at the year 2002. There were 18 GSU transformers including 2 spare
transformers. There were 2 GSU transformers in the 30-40 age groups which fall
under the high risk category and 14 in the 20-30 categories which are medium to
high risk.
From the current
transformer replacement program which started in 2003 the profile has changed
to that represented in graph B. There were 2 rewinds and 3 transformer
purchases with installations up to 2007. This mitigated the risk of the 2
premature aged Palmiet GSU transformers and 4 transformers from Gariep,
Vanderkloof and Drakensberg Power Stations.
Graph C provides a snapshot of
the profile of the GSU transformers in
year 2012. Most of the high risk GSU transformers would have been replaced by
new or rewound transformers. The 7 GSU transformers in the 30-40 age groups are
the Acacia and Port Rex Gas Fired GSU transformers. Although these transformers
are in this age category they are still in a satisfactory health condition and
are not highly loaded with a low Station load Factor. There is also a spare
transformer to reduce the impact of a transformer failure.
The following
paper attempts to provide a picture of the nature of a typical transformer life
cycle and the components that go into forming a transformer asset management
strategy. There are numerous ways of achieving this and the author attempts to
provide a structured approach for asset management decision making. Transformers
are a huge investment for a Utility so it is important to balance the decision
to defer the replacement/refurbishment to as late as possible and that of
preventing a catastrophic failure.
The most
important aspect of asset management is to know as much as you can about your
assets. Then formulate techniques on achieving a focussed approach for
identifying abnormal conditions and potential transformers failures.
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