POWER April 2017 - 33

OPERATIONS & MAINTENANCE
1. Switchgear accident due to partial
discharge (PD). Switchgear failures
can cause substantial damage to equipment
and pose a serious hazard to plant personnel.
Courtesy: Emerson Automation Solutions
All manual inspections require trained
technicians and specialized test equipment,
which is why they are often performed by an
outside service provider. Meanwhile, electrical
problems occurring after an inspection
can go undetected until the next inspection,
which could be a year or more away. During
that time, small problems can become large
ones, potentially leading to a complete failure
of the asset(s) and resulting in a power
shutdown.
breakdown will initiate across the defect,
causing a partial arc between conductors at
different potentials. This effect is known as
a partial discharge. The breakdown causes a
small but sudden rise in current accompanied
by a current pulse, as well as electromagnetic
(radio or light), acoustic, and ozone emissions.
Left unattended, this condition can
cause the switchgear to explode (Figure 1).
High Humidity. Moisture in switchgear
equipment can create shorts or be absorbed
by the insulators, leading to insulation breakdown.
Humidity also causes metallic corrosion
and can lead to elevated heating, partial
discharge, surface tracking, and the potential
for shorts and flashover.
Inspecting Assets Manually
Electrical asset monitoring is most often
achieved through periodic manual inspections
during an outage. These inspections
look for obvious problems such as physical
damage, frayed connectors, degraded insulation,
and evidence of overheated components.
Electrical measurements can also be
conducted while power is off. Insulation resistance
in the panel enclosure, bus bars, circuit
breakers, and other components can be
checked by applying voltage with calibrated
AC and DC hipot test sets. These tests will
also check contact resistance to confirm bus
bar joints are connected properly.
Manual inspections can also be conducted
while power is on using infrared (IR) equipment.
Periodic IR monitoring techniques
require a tempered glass window to be installed
in the asset, a relatively expensive IR
camera, and a trained technician. One significant
limitation of this type of inspection
is that personnel cannot perform monitoring
procedures behind bus insulators or in assets
that cannot be reached, such as isophase bus
ducts, because line-of-sight is required with
IR technology. Moreover, IR technology is a
measure of emissivity, as opposed to an actual
point-of-contact temperature.
April 2017 | POWER
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A better solution is to employ continuous
condition-based monitoring. This allows utility
companies to collect data generated during
the asset's normal operating conditions,
thereby providing awareness to problems
in real time. Monitoring and trending data
of electrical stresses, vibration, insulation
breakdown, and environmental influences
during full load also provides new insights
into the health of the assets. By using this
data in conjunction with other asset parameters,
such as operating voltages and currents,
plant operators can plan proactive maintenance
and avoid catastrophic failure.
Temperature Monitoring
Temperature monitoring is a primary method
for detecting corrosion, wear, loose connections,
and other problems associated with
the asset's conductors, such as bus bars and
cables. One challenge in implementing continuous
temperature monitoring of critical
connection points in air-insulated assets is
that the sensors must maintain the impulse
withstand voltage, also known as basic impulse
level (BIL). Consequently, conductors
at different potentials must have a minimal
distance between each other to prevent
breakdown to ensure the impulse rating. Another
key challenge involves how to power
the sensors to avoid regular maintenance requirements.
Specific
to the BIL concern, the IEEE
Standards Association's C37.20.3 ( " Standard
for Metal-Enclosed Interrupter Switchgear,
Section 5.2 " ) states that switchgear rated
with a maximum voltage of 15 kV must have
an impulse voltage of 95 kV. This relates to
a distance (in air) of about 160 millimeters.
It means that the most common types of direct
contact temperature monitoring systems,
such as thermocouples and RTDs, cannot be
used. That leaves only noninvasive systems,
such as fiber optics, continuous IR sensing,
and wireless direct contact sensors, as monitoring
options.
Wireless passive sensor systems provide
real-time continuous monitoring via direct
connection to critical measurement points.
These systems are easy to install, require no
maintenance or yearly calibration, and have
a life expectancy comparable to the assets
themselves. These sensors employ surface
acoustic wave (SAW) technology (Figure 2).
Compared to other noninvasive sensors,
passive SAW temperature sensors have no
physical connection to a control device, do
not require batteries, and do not require lineof-sight
for measurements.
Monitoring Partial Discharge
The most commonly used PD detection instruments
directly measure the current and
voltage spikes with high-frequency current
transformers or high-voltage capacitive couplers
as outlined in the International Electrotechnical
Commission's IEC 60270 standard:
" Partial Discharge Measurements. "
This method has several strengths, including
the ability to analyze pulse shapes and
to assemble a graph of the discharge events
relative to the phase of the power line waveform.
These systems are very expensive and
require trained technicians to analyze the
data, and do not lend themselves to permanent,
continuous monitoring installations to
cover the complete power delivery system.
Many utilities are currently evaluating
partial discharge detection methods outlined
in accordance with IEC 62478, a prospective
standard for acoustic and electromagnetic
2. SAW sensors. The three cylindrical orange surface acoustic wave (SAW) sensors in the
middle of this photo are continuously transmitting temperature data via wireless connectivity.
Courtesy: Emerson Automation Solutions

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POWER April 2017

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