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Using Dissolved Gas Analysis to DetectActive Faults in
Oil-Insulated ElectricalEquipmentLance R. Lewand, Doble Engineering
Company Tags: oil analysis
The analysis of gases from petroleum products has been performed
for decades using gas chromatography.However, this technique was
not applied specifically to transformer mineral oil until the late
1960s/early 1970sand is now commonly called dissolved gas-in-oil
analysis (DGA). Some of the early developers of thetechnique were
Dr. James Morgan of Morgan Schaffer Systems, Canada, and
researchers J.E. Dind, R.Daust and J. Regis from the Canadian
utility Hydro-Quebec.1
Because the technique was so successful and provided a wealth of
diagnostic information to detect incipientfaults, other
laboratories such as Doble Engineering in Massachusetts began
utilizing the technique shortlythereafter. DGA has now become a
standard in the utility industry throughout the world and is
considered tobe the most important oil test for insulating liquids
in electrical apparatus. More importantly, an oil sample canbe
taken at anytime from most equipment without having to take it out
of service, allowing a window insidethe electrical apparatus that
helps with diagnosing and trouble-shooting potential problems.
Insulating fluid analysis is performed using an array of
physical, chemical and electrical tests. Physical testsinclude
analysis for interfacial tension, pour point, relative density,
viscosity, color and others. Tests such aswater content,
neutralization number, oxidation inhibitor and polychlorinated
biphenyls (PCBs) are consideredchemical tests. Electrical tests
consist of analyses for dielectric breakdown voltage and power
factor. Thereare many other tests that can be performed but these
are the main ones executed on a routine basis. Mosttests performed
in North America are based on ASTM test methods. In Europe and
other parts of the world,similar test methods come under the
auspices of the International Electrotechnical Committee TC10.
Because oil and solid insulation degrade with service in
electric apparatus, periodic sampling and testing arenecessary to
ensure that deterioration is detected before it becomes excessive.
The rate at which theinsulating materials degrade depends on
several factors, such as the type of oil preservation system
(amountof oxygen present), operating temperature, water content of
the insulation, and the amounts and types ofcontaminants. The
frequency at which testing is conducted varies with the test,
importance of the equipment,whether an incipient-fault condition is
known to be present or a problem exists, and when a family
oftransformers has been identified as having a history of
problems.
The tests mentioned above provide information on the oil quality
itself but fail to provide in-depth diagnosticinformation on the
operating condition or health of the electric apparatus. In
addition, because mosttransformers in the United States are
considered to be sealed systems (equipped with preservation
systemsthat retard the ingress of moisture and oxygen), oil
degradation can occur quite slowly over many years.Many of the
transformers in the United States that have been in-service for
more than 30 years still contain oilthat is in good condition.
There is one test however, also performed on the insulating oil of
the transformer,which provides a means for diagnosing the operating
condition of the electrical apparatus, namely DGA.
Dissolved Gas-in-Oil AnalysisDissolved gas-in-oil analysis,
performed in accordance with ASTM D3612 or IEC 60567, is by far the
mostfrequently requested diagnostic test and the single most
important test performed on transformer oil. As theinsulating
materials of an electrical apparatus, such as a transformer, break
down from excessive thermal orelectrical stress, gaseous byproducts
form. The byproducts are characteristic of the type of
incipient-faultcondition, the materials involved and the severity
of the condition. Indeed, it is the ability to detect such avariety
of problems that makes this test such a powerful tool for detecting
incipient-fault conditions and forroot-cause investigations after
failures have occurred. Dissolved gases are detectable in low
concentrations(ppm level), which usually permit early intervention
before failure of the electrical apparatus occurs, and allowfor
planned maintenance.
The DGA technique involves extracting or stripping the gases
from the oiland injecting them into a gas chromatograph (GC).
Detection of gasconcentrations usually involves the use of a flame
ionization detector (FID)
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and a thermal conductivity detector (TCD). Most systems also
employ amethanizer, which converts any carbon monoxide and carbon
dioxidepresent into methane so that it can be burned and detected
on the FID, avery sensitive sensor.
Removing the gas from the oil is one of the more difficult and
criticalportions of the procedure. The original method, now ASTM
D3612A,required that the oil be subjected to a high vacuum in an
elaborate glass-sealed system to remove most of the gas from the
oil. The gas was then
collected and measured in a graduated tube by breaking the
vacuum with a mercury piston. The gas wasremoved from the graduated
column through a septum with a gas-tight syringe and immediately
injected intoa GC. In the present modern day laboratory, however,
mercury is not a favorite material of chemists. For thisreason, two
additional extraction techniques have been developed to eliminate
mercury.
ASTM D3612B is called the direct injection technique. In this
method, the stripping of gases from the oil andthe gas analysis
takes place inside the GC. Originally developed in the mid-1980s
for this application, theprocess involves injecting the oil into a
sample loop in the GC. When the GC run is initiated, the sample
looptransfers the oil through a series of valves into a stripper
column. The stripper column is composed of metalspheres in one end
in which the oil overlays the surface of the spheres to increase
the surface area. Carriergas is passed over the spheres and
extracts dissolved gases from the oil, which then pass through a
seriesof columns and on through the detectors. The oil is
back-flushed and purged from the system before the nextsample is
introduced.
The newest method, ASTM D3612C, was approved about a year ago
and is called the headspace method.Headspace technology was used
for DGA analysis for almost a decade. However, it was never
developedinto a robust, reliable standard method until several
years ago when Jocelyn Jalbert of Hydro-Quebecdeveloped a headspace
method using a Hewlett Packard (now Agilent Technologies)
instrument.2 Thetechnique involves injecting an exact volume of oil
into a purged and pressurized headspace vial. The gas inthe oil is
then allowed to develop an equilibrium with the vial headspace
under shaking and heatingconditions. After a predetermined sample
extraction time, the autosampler removes a portion of the gas
fromthe vial headspace and injects it into the GC. The advantage of
this method is that it can be automated andreduces the risk of
operator error from excessive handling of the sample during
preparation and injection.
Of course, each method has its advantages and disadvantages.
Method A (ASTM D3612A) is by far thelongest-standing technique and
is still widely used today and offers accurate, reliable sample
preparation iffollowed rigorously. However, the alternative
methods, which are more easily automated, are gainingacceptance as
they are shown to be reliable. None of the extraction techniques
completely removes all thegases from the oil. This is due to the
solubility coefficient of each gas, which must be accounted for in
thefinal concentration determination. Laboratories must also work
with commercial suppliers to develop gas andgas-in-oil standards or
they must prepare standards themselves, because these are not
currently availablefrom national standardization bodies such as the
NIST. Repeatability and accuracy are also of the utmostimportance
as small changes, even several ppm in some cases, can mean the
difference between an activeincipient fault condition that requires
immediate attention or one that is stable and requires no
attention.
Just like with industrial oil analysis, good sampling practice
is important for obtaining accurate DGA data. Keygases such as
hydrogen and carbon monoxide could easily be lost from a sample
because of their lowsolubilities in oil. In order to minimize the
loss of gases, ASTM D3613 requires samples to be taken
usinggas-tight glass syringes or metal bulbs; these are available
from several suppliers or from commercialtransformer oil analysis
labs.
Gases Detected and Their RelevanceTypical gases generated from
mineral oil/ cellulose (paper and pressboard) insulated
transformers include:
Hydrogen, H2Methane, CH4Ethane, C2H6Ethylene, C2H4Acetylene,
C2H2Carbon Monoxide, COCarbon Dioxide, CO2
Additionally, oxygen and nitrogen are always present, their
concentrations vary with the type of preservationsystem used on the
transformer. Also, gases such as propane, butane, butene and others
can be formed aswell, but their use for diagnostic purposes is not
widespread. The concentration of the different gasesprovides
information about the type of incipient-fault condition present as
well as the severity. For example,four broad categories of fault
conditions have been described and characterized in Table 13.
Electrical discharges or inadequate cooling of the paper
insulation cause it to overheat, generating carbonoxide gases.
Examination of the relative composition or ratios of gases present
can provide furtherrefinement of the diagnosis. This typically
involves using either Rogers ratio or Dornenberg ratios.
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Buyers GuideOil Analysis Laboratories
Oil Analysis Instruments
Oil Sampling Hardware
PollHow often is oil analysisperformed on equipment atyour
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The severity of an incipient-fault condition is ascertained by
the total amount of combustible gases present(CO, H2, C2H2, C2H4,
C2H6, CH4) and their rate of generation. Generally, transformers
will retain a large
portion of the gases generated and therefore produce a
cumulative history of the insulating materialsdegradation. This is
an important tool for detecting and trending incipient problems.
However, it also meansthat care is needed in interpreting values
for a first-time analysis on service-aged transformers (more
thanseveral years old), which could contain residual gases from
previous events.
Some gas generation is expected from normal aging of the
transformer insulation. Therefore it is important todifferentiate
between normal and excessive gassing rates. Normal aging or gas
generation varies withtransformer design, loading and type of
insulating materials. Routinely, general gassing rates for
alltransformers are used to define abnormal behavior. Specific
information for a family of transformers can beused when sufficient
dissolved gas-in-oil data are available.
Acetylene is considered to be the most significant gas
generated. An enormous amount of energy is requiredto produce
acetylene, which is formed from the breakdown of oil at
temperatures in excess of 700C.Excessively high overheating of the
oil will produce the gas in low concentrations; however,
higherconcentrations are typically symptomatic of sustained arcing,
a more serious operational issue that can causea transformer
failure if left unchecked.
DGA is used not only as a diagnostic tool but also to stem
apparatus failure. Failure of a large powertransformer not only
results in the loss of very expensive equipment (costs can exceed
one million U.S.dollars) but it can cause significant collateral
damage as well. Revenue losses due to customers outagesmay be the
least worrisome consequence of a failure. Replacement of that
transformer can take up to a yearif the failure is not catastrophic
and can result in tremendous revenue losses and fines. If the
failure iscatastrophic, then additional loses could be realized,
such as adjacent transformers, environmental problemsfrom the
release of oil, which could be as much as 20,000 gallons, and the
resulting fire that must becontained and smothered, all of which
are a utilitys worst nightmare. In order to avoid such a failure,
thesample frequency of most large power transformers is between one
and three years. However, samplingfrequencies will increase as an
incipient fault is detected and monitored. Often times sampling
frequenciesare dictated by insurance requirements, which often
stipulate that annual transformer oil analysis must beconducted to
ensure continued coverage.
The following examples are extreme but serve to illustrate how
the dissolved gas-in-oil test can be used tohighlight active
problems.
EXAMPLE 14The utility suspected that the magnetic shunt pads
attached to the inside of this transformer tank had comeloose and
were either touching the core (layered steel structure around which
the copper winding is installed)or were coming very close. The
result was intermittent unintentional core grounding and stray flux
causinglocalized overheating of the oil.
EXAMPLE 25 It was suspected that a single line to ground
through-fault caused the failure of thistransformer. The fault was
of enough energy to destroy one of the windings. Acetylene was a
predominant
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gas possibly indicating that arcing may have occurred. The
acetyleneto-ethylene ratio indicated the problemcould be either
high temperature overheating of the oil, arcing or both. The
problem was likely in the windingbecause it involved cellulosic
materials, as witnessed by the comparatively high carbon monoxide
and carbondioxide concentrations.
EXAMPLE 35 A technician noticed that this transformer was
enveloped in a cloud of steam during arainstorm. This prompted an
investigation where it was found that the temperature indicator
pegged. It wasestimated that the temperature in the unit had been
greater than 200C. It was discovered also that the unitbecame
highly overloaded during some switching functions due to current
imbalances in the three phases.The condition probably existed on
and off for two years. An internal investigation found the
cellulosic paperused as an insulant was brittle and crumbly. Again,
the key gas indicators for this condition were carbonmonoxide and
carbon dioxide.
Oil testing is an important part of a utilitys electric
apparatus condition assessment. As these cases illustrate,dissolved
gas-in-oil analysis is the most important diagnostic test for
detecting a wide range of problems.
References
Dind, J.E., Daoust, R., Regis, J. and Morgan, J., (1971).
Analysis of Gases Dissolved in TransformerOils, Progress Report.
Minutes of the Thirty-Eighth Annual International Conference of
Doble Clients.Sec. 6-1101.
1.
Jalbert, J., Gilbert, R. and Brillante, S., (1995). Dissolved
Gas Analysis of Transformer Insulating Oilsby Headspace/Capillary
Gas Chromatography. Hewlett Packard Application Note. pp.
228-310.
2.
Griffin, P.J., (1998). Criteria for the Interpretation of Data
for Dissolved Gases in Oil from Transformers(A Review). ASTM
Special Technical Publication 998.
3.
Lewand, L.R. and Griffin, P.J., (2000). The Effective Use of
Laboratory Analysis of Insulating Oil as aMaintenance Tool.
Proceedings of the Sixty-Seventh Annual International Conference of
DobleClients. Sec. 5-8.
4.
Griffin, P. J. and Lewand, L.R., (1995). A Practical Guide for
Evaluating the Condition of CellulosicInsulation in Transformers.
Proceedings of the Sixty-Second Annual International Conference of
DobleClients. Sec. 5-6.
5.
Practicing Oil Analysis (3/2003)
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