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A comprehensive, cost-effective dissolved gas monitoring strategy

Stephan Brauer Trevor Lord

Morgan Schaffer Inc. Lord Consulting

EEA Conference & Exposition 2012, 20-22 June, Auckland

ABSTRACT

This paper reviews an innovative, cost-effective approach for deploying on-line dissolved gas

monitors on a population of liquid-filled transformers to achieve both comprehensive fault

detection and well-informed maintenance decisions when a fault is detected. Under this

approach, fault-detection monitors are installed on the majority of units, with alarm limits

optimized for each unit based on historical dissolved-gas levels. The fault-detection monitors

are designed and installed in such a manner that if an anomalous gassing condition is

detected, the fault-detection monitor can be readily interchanged with a multi-gas monitor to follow the fault evolution in real-time using complete dissolved gas analysis. New

measurement technology also allows this concept to be applied to tap changers using the

latest Duval Triangle for LTC units. The approach is a natural complement to routine oil

sampling and laboratory analysis, as part of a comprehensive transformer asset management

program. Requirements for accuracy, reliability and measurement ranges are reviewed. Field

experience with suitable monitors is presented using illustrative case studies.

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INTRODUCTION

Dissolved gas analysis (DGA) is widely accepted to be one of the most effective tools

available for assessing the operational health of large, liquid-filled transformers [1,2]. With a

history of more than 40 years of oil-syringe sampling and laboratory measurements, DGA

methods continue to evolve as new technology solutions emerge. Increasingly, DGA

measurements are being conducted within the transformer yard, using portable analysers and

on-line monitors. On-line DGA has come to play a central role in optimizing operations and

asset management [3] within the electrical power industry.

Historically, two categories of on-line dissolved gas monitors have been established. The first

are fault-detection monitors designed to sense primarily hydrogen as the key gas associated

with all transformer fault modes resulting in oil-degradation. These monitors may also

measure dissolved carbon monoxide associated primarily with the degradation of cellulose

insulation [2]. In the second category are multi-gas monitors that measure most or all of the gases of a typical DGA laboratory. The emergence of monitors that measure 3-5 gases has

since blurred this distinction, offering new price/performance combinations to the industry.

Also, considerable progress has been made in improving the accuracy and reliability available

from on-line dissolved gas monitors. Dissolved moisture measurement has become a standard

feature of most DGA monitors.

In this paper, we focus on an approach to DGA monitoring that seeks to provide asset

managers with the greatest ability to detect and diagnose transformer faults across a

transformer population, for a given total cost of monitor ownership. Under this approach, we

use the historical categorization mentioned above. Fault-detection monitors are installed on

many units, in a manner that offers the highest assurance of fault detection with a minimum

of false alarms and monitor service events. Each fault-detection monitor is designed and

installed in such a fashion that if an anomalous gassing condition is detected, it can be readily

interchanged with a multi-gas monitor. The latter allows the fault evolution to be studied in

detail using complete dissolved gas analysis, such that well informed decisions can be taken

to manage the fault condition. Design and installation features that facilitate the interchange

of monitors are described. Also, performance requirements and cost of ownership are

discussed for DGA monitors that best serve this monitoring model.

ON-LINE DISSOLVED GAS MONITORING

The fundamental requirement of a fault-detection monitor is the ability to unambiguously

report an alarm condition when a key gas, normally hydrogen, has reached an anomalous

level. To accomplish this assuredly and without false alarms, the monitor must be built

around a dissolved-gas-measurement system that is stable and dependable over many years of

field service. Monitors that deliver accurate dissolved gas concentrations are preferred for

several reasons. First, a measurement system which is consistently accurate, as benchmarked

to a qualified DGA laboratory, generally meets the requirement for good stability. Also,

absolute accuracy implies good gas-selectivity, so that changing levels of potential

interference gases do not compromise the key gas reading. Accurate and selective fault-

detection monitors offer the additional advantage that historical laboratory DGA data from

each specific transformer (or factory acceptance data in the case of new transformers) can be

used to set optimal and justifiable gas alarm thresholds to protect each unit. This key step in

the commissioning of a monitor is often completed using excessively wide margins, or using

values drawn from published standards which may not be optimal for the unit. Accurate

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monitors allow transformer asset managers to establish consistent policies for setting alarm

levels based on well-established DGA baselines, and to have these policies endorsed by their

management and insurance companies. Finally, accurate and selective monitors allow

comparison with routine annual laboratory DGA results, in order to validate the performance

of the monitor periodically throughout its working lifetime. Independent studies of monitor

accuracy are ongoing [4].

Reliability and accuracy are also paramount requirements for a multi-gas monitor, whether

permanently installed on a critical transformer, or used within the monitoring model

prescribed here. The complex process of diagnosing a fault condition on an in-service

transformer benefits from certainty in the dissolved gas-concentrations. As a guide to the

accuracy requirements of the monitor, it is noted that the various DGA condition assessment

tools known in the industry were developed using laboratory DGA measurements, and the

expectations of accuracy from a good DGA laboratory are documented [5].

Several factors suggest that some online multi-gas monitors have the potential to actually be

more accurate than DGA labs. Good monitors control the oil temperature during the gas-

extraction process, so the gas-solubility temperature dependence does not impact the

readings. Also, monitors that use a continuous oil-flow circuit are largely free of poor oil-

sampling techniques, oil-sample storage issues, and syringe gas-bubbles, which can be

dominant limitations to the accuracy of DGA results obtained from even the best of

laboratories. Monitors also offer favourable measurement statistics, since many readings can

be easily averaged to reduce random measurement errors. Finally, as shown in the case

studies below, operating transformers are seldom in a steady -state. Improved agreement with

lab samples can be obtained if the sampling location is on the DGA monitor, and the time of

the sample collection is recorded for comparison with the monitor readings from the same

time.

In comparing monitor and laboratory DGA measurements, it is helpful to consider the gas

extraction techniques used by each. Techniques with extraction efficiency near 100%,

including as ASTM-D3612 Method A and others [6], are fundamentally insensitive to the gas

solubilities, which are known to vary with fluid type, age, contamination, and even the nature

of the gas matrix [7, 8]. However, most labs today use more solubility-sensitive headspace

extraction techniques because they are more cost effective. Since the actual solubility of a

syringe sample is not generally known, many of these labs report dissolved gas readings

based on Ostwald solubility coefficients for mineral oil published in ASTM-D3612 [9]. If the

fluid is not mineral oil, or is aged, contaminated, or saturated with gas, the reported dissolved

gas concentrations would not be expected to agree with those measured by high-efficiency

extraction methods. Multi-gas monitors commonly use a headspace extraction technique, and

are thus subject to the same concern. Therefore, when configuring a multi-gas monitor, the

accuracy objectives should be considered. For absolute accuracy and comparison with high-

efficiency extraction methods, monitors should be configured with the Ostwald solubility

settings for the actual liquid in the transformer. On the other hand, if the objective is to have

the monitor report readings which are as similar as possible to a lab using headspace

extraction, it may be best to configure the monitor with the solubilities from ASTM-D3612.

(As for moisture-in-oil, monitors measure %RS in the oil and may convert this to water

content (in ppm) using a solubility function. For best agreement with laboratory Karl Fischer

water content, the moisture solubility coefficients for the actual liquid should be configured

in the monitor.)

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As far as we are aware, little work has been conducted to explore fault diagnostic techniques

at sub-ppm gas levels, primarily because such measurements have not historically been

available. Although industry standards suggest that 2 ppm of C2H2 can be reason for concern

in some transformers, many labs have a detection limit of 2 ppm for routine DGA analysis.

Some multi-gas monitors have detection limits of 0.2 ppm for C2H2 and other gases, offering

the potential to reveal fault behaviour at earlier stages than had previously been possible.

Utilities have been conducting laboratory DGA measurements for load-tap- changer (LTC)

transformers for many years, and improved methods for interpreting LTC faults from DGA

data have received considerable recent attention [10, 11]. We believe the monitoring model

proposed here may help extend the advantages of on-line DGA monitoring to this class of

fault-prone transformers. Dissolved fault-gas concentrations from LTC units can exceed

100,000 ppm in extreme cases [11], so monitors with high measurement top-of-range (TOR)

are warranted, both for fault-detection and for multi-gas DGA monitoring.

COST CONSIDERATIONS

Cost-benefit analysis for on-line transformer monitoring, in the broadest sense, has been

described in some detail [3]. Such models make a compelling case for on-line monitoring, the

main economic advantages arising from reduced catastrophic failures, reduced interruptions

to power generation and delivery, transformer lifetime extension, and potential gains from

sustained overloading. One conclusion is that there is economic benefit for on-line

monitoring, including on-line DGA monitoring, on most every transformer above a certain

replacement cost, the threshold being determined by the cost of the monitoring equipment. To

experience these benefits across the greatest portion of a transformer fleet, an economic DGA

monitoring solution is desirable, particularly for lower MVA asset classes. The same position

can be reached directly from the annual capital or operating budget of any transformer asset

manager. The monitoring approach offered here provides a practical solution to maximizing

asset protection within budgetary constraints.

Table 1: Two DGA monitoring scenarios for a population of 10 transformers.

Assumptions Fault detector Multi-gas

Purchase price 10,000 $ 35,000 $ Relative dollars units,

Consumables at installation 1,000 $ where the cost of a

Installation labour and materials 1,000 $ 1,250 $ fault detection

Acquisition cost 11,000 $ 37,250 $ monitor is $10,000

Routine annual inspection 500 $ 500 $

Routine annual consumables 1,000 $

Annual cost of false alarms 100 $ 100 $

Allocation for repairs 100 $ 500 $

Annual operating cost 700 $ 2,100 $

Scenarios Lifetime costs

Lifetime (years) 15 Acquisition Operating Total

Multigas only (monitors) 10 372,500 $ 315,000 $ 687,500 $

Fault-detect & Multi-gas (monitors) 10 1 147,250 $ 136,500 $ 283,750 $

Difference 225,250 $ 178,500 $ 403,750 $

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Table 1 presents two simple DGA monitoring scenarios with similar levels of transformer

protection for a population of 10 transformers. We have chosen to use relative dollar units,

where the cost of a fault-detection DGA monitor meeting the criteria described above is

$10,000. The more complex measurement systems within multi-gas DGA monitors make

them typically 3-4 times more costly to purchase. The costs of operating online monitors

include annual inspections, routine maintenance, repairs, and, in the case of multi-gas

monitors that satisfy assumptions above, the cost of replacing consumables. (We have

assumed an average cost per year although the replacement interval for consumables is two

years on some multi-gas monitors.) The cost of addressing false alarms has been assumed

small due to the choice of accurate and reliable monitors. This simple model reveals the main

cost advantages of the proposed monitoring approach. For the same level of transformer

protection, monitor acquisition costs and lifetime ownership costs are much reduced.

INTERCHANGABLE MONITORS

Calisto products [12] are designed to facilitate the interchange of fault detection and multi-

gas monitors. Most importantly, these monitors meet the performance requirements outlined

above. Common operating features that facilitate comparison of the DGA results between

these monitors include 1) an oil circulating pump, 2) temperature conditioning of the oil at

the extraction stage and the gas measurement system, 3) the same user-interface software

with local or network database, 4) a front-panel display with 3-button navigation, and 5) an

oil-sampling port to allow oil-syringe samples to be drawn for comparison with DGA lab

measurements.

With appropriate planning of the installation site, the process of interchanging a fault-

detection model with a multi-gas model is straightforward, and can be performed without

taking the transformer out of service. As shown in Figure 1, both monitor types have similar

physical dimensions and share common mounting-hole patterns and shock-mounts. The oil

inlet and outlet ports have the same fittings and similar locations, being only 11 cm (4.5

inches) further apart on the multi-gas models. Internal to these units are oil valves that

minimize oil spillage during a swap. Optional external oil valves can also be installed near

the connections to the unit to similarly limit oil spills from the oil lines when a unit is

disconnected. We have conducted laboratory measurements to quantify the reaction of C2H2

dissolved in mineral oil with 3/8 copper tubing at elevated oil temperatures. Our measurements indicate that the reaction is sufficiently slow as to be negligible with the oil-

flow rates typical of these monitors. It is nevertheless recommended to use stainless steel oil

lines of solid tubing, braided hose, or a combination of these, to alleviate any doubt about

possible reaction of C2H2 in copper lines.

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Figure 1: Installation of interchangable fault-detection (left) and multi-gas DGA monitors

(right).

The electrical connections to these monitors have also been designed to anticipate the

interchange of different models. A removable plate on the bottom of the enclosure can be

modified to suit the users preferred conduit termination, and this plate is identical on all

models, minimizing the re-work required to make water-tight electrical feed-throughs when

units are interchanged. The models also use the same electrical connectors and terminal strips

for digital communications, analogue inputs/outputs, and relay outputs.

FIELD STUDIES

Figure 2 shows data recorded by a fault-detection monitor installed on a 700 MVA free-

breathing autotransformer located in Norway. The unit has been running with the same

mineral oil since 1978, which has been regenerated once. The H2 level 1 alarm was set to 50

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ppm, and the CO level 1 alarm at 1000 ppm. The case is uncommon in that a CO alarm was

reported (on 12/07/2011), and only subsequently were smaller increases in H2 and WC

discovered. The manufacturer indicated that this transformer design includes sections of thin

copper foil covered with paper for electrostatic screening of the outer legs. Repairs on similar

units have shown that eddy-current heating of the foil can create localized hot regions which

may burn the paper creating CO and CO2, and generate small amounts of other fault gases. The unit remains in service with close attention to the DGA monitor readings and alarms.

Figure 2: Development of a fault involving both oil and celulose insulation, recorded by a

fault-detection monitor.

When catastrophic failures occur on monitored transformers, post-mortem analysis often

shows that a rising H2 signature was recorded. For most of these failures there is adequate

time for intervention, but the H2 rise is not followed by operator action because the alarm

thresholds were not optimally set, or the alarm is considered erroneous. An example is

depicted in Figure 3 where, in early summer, a gassing fault accelerated with the increase in

peak daily load, but was not detected because the H2 alarm thresholds were not optimized

based on the low historic H2 level.

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Figure 3: Development of a catastrophic fault involving both oil and celulose insulation,

recorded by a fault-detection monitor.

When a fault-detection monitor is installed, mechanical, plumbing and electrical provisions

can be prepared to allow a multi-gas monitor to be installed in parallel, should it become

necessary. An example of such an installation is presented in Figure 4, which shows a fault-

detection monitor (left) and full DGA multi-gas monitor (right), installed on the same

transformer.

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Figure 4: Fault-detection and multi-gas monitors installed in Malaysia with stainless-steel

oil lines and custom-made sun shields.

Figure 5: On-line DGA data showing moisture and gassing behaviour that varies with load.

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Figure 5 presents data from a multi-gas monitor on a 20 MVA free-breathing transformer

filled with mineral oil, which was put into service in the USA in 1969. The monitor reported

a high average moisture level near 33 ppm water content (WC) or 49 %RS@25C. Daily

transformer load cycles generated daily cycles in WC of about 2-4 ppm peak-to-peak as

moisture was driven out of the cellulose insulation and into the oil with higher core

temperature. The data also shows small daily variations of fault-gases (2-3% peak-to-peak)

which correlate to the moisture. Note that sub-ppm changes were resolved for C2H4 and CH4.

Duval triangle analysis using the average values of CH4, C2H2 and C2H4 indicates a D1 fault

type (low energy discharges). The observation that each of these three gases rose and fell in

unison suggests that the D1 fault was load-dependent, a plausible behaviour. The same

pattern is discernible in the H2 data, but none of the other gas readings, adding weight to this

interpretation. The small slow downward trend of fault gases may have been related to

seasonal changes in load and ambient temperature in this late-summer data. Historic

laboratory DGA data were in agreement with the monitor data. This example shows how

time-resolved DGA measurements can offer insight into the complex dynamic behaviour of

an energized transformer.

Figure 6: Multi-gas DGA monitoring of a defective new transformer.

Figure 6 is data taken within the first days of service of a new 900 MVA transformer filled

with mineral oil, installed in the USA. A multi-gas monitor was installed on the unit and put

into service before the transformer was energized on 14/10/2011. Within a few hours of

operation, the transformer began to exhibit significant fault gassing. The monitor readings

rose steadily over 24 hours, and the transformer was de-energized late on 15/10/2011, after

which the gas levels quickly stabilized. Laboratory DGA samples confirmed the

concentrations reported by the monitor. Duval triangle analysis suggests a T3 fault (thermal

fault > 700C), which could have quickly escalated to a catastrophic failure. The

comparatively-constant CO readings suggest the cellulose insulation was not directly

involved. The transformer was returned to the manufacturer for root cause analysis and repair

under warranty.

CONCLUSIONS

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Accurate multi-gas online DGA monitors can provide valuable insight into the complex

dynamics of gassing behavior associated with transformer faults. The advantages of such

tools can be extended across a population of transformers economically through the strategic

deployment of interchangeable fault-detection detectors of high accuracy and reliability.

REFERENCES

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3. IEEE Draft Guide for Application of Monitoring Liquid-Immersed Transformers and Components, IEEE Draft Standard C57.143-2006.

4. Report from CIGRE WG47, in development. 5. M. Duval, J. Dukarm, Improving the Reliability of Transformer Gas-in-Oil

Analysis, IEEE Electrical Insulation Magazine, vol. 21, no. 4, pp. 21-27, 2005. 6. M. Duval, New Techniques for Dissolved Gas-in-Oil Analysis, IEEE Electrical

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12. Morgan Schaffer Inc., 8300 St-Patrick Street, Suite 150, LaSalle, Qubec, Canada.