Fluid-filled Underground Transmission Cable Condition
Harry ORTON, Lisa OGAWA, PhD David ARNOLD,
Orton Consulting Engineers BC Hydro, Vancouver, Canada EPCOR, Edmonton, Alberta
International, Vancouver, (Formerly with Powertech) Canada
firstname.lastname@example.org email@example.com firstname.lastname@example.org
1.0 Abstract: Many underground power satisfaction that the correct decision has
cable users are faced with aging fluid-filled been made.
transmission cables that have exceeded their 3.0 On-site Inspections: On-site inspections
design life of 30-40 years. Major and begin with routine visual observations by the
possibly costly decisions have to be made same personnel overtime so that any
whether to replace or to continue to use the differences become obvious. Good records
existing cable system . including photographs of situations that need
This paper presents a condition assessment attention or further investigation are kept.
strategy focused on fluid-filled cables that Cables, terminations, splices, accessories,
involves a combination of visual fluid lines, tanks and link boxes are
observations through on-site inspections, examined closely. Details of any
laboratory diagnostics, on-site diagnostics, discoloration, fluid leaks, (see Figure 1),
operation reports and data trending. corroded components, damaged, loose or
2.0 Introduction: The objective of distorted components are recorded.
condition assessment is to prevent
unacceptable consequences such as reduced
performance, to insure high system
reliability and long service cable life and to
prevent customer outages. The ideal
situation is to use suitable diagnostics to
locate potential problems before failure and
hence reduce replacement costs and target
replacement money. Effective condition
assessment must be able to identify the
stress factors, whether environmental,
electrical, mechanical or chemical that may
cause degradation. Furthermore it is
important to identify the degradation
mechanism and the consequences and so Figure 1. 275 kV SCFF Cable SF6
take timely corrective action. Termination with Fluid Leak.
Once a thorough condition assessment has
been completed, replacement or continued Visual inspections will look for choking at
utilization decisions can be made with the cable cleats and supports, unusual snaking of
cables, pungent smells or odors, surface
cracking, ionization or corona discharge, complete understanding of the cable
surface tracking, carbonization or soot, condition. Laboratory diagnostics include
shrink back, blanching or crazing of the chemical, electrical, mechanical and
outer sheathing. metallurgical evaluations. These diagnostics
In addition, an on-site inspection will check are mostly destructive, as small samples
fluid pressures, alarm power supply plus must be removed from the cable being
ensure that SVL’s are MOV’s, not carbon assessed. Chemical diagnostics include
block air-gap type. Surge diverter counters Degree of Polymerization (DP), DGA and
should be in place to record the number of moisture content. Of these DGA is not
events that actually occur at a specific destruction and can be carried out while the
location. cable is still in service. See Table 2 for Key
Regular patrols along cable routes should be Gas Indicators.
carried out to prevent “dig-ins” and an
advertising campaign “call before you dig”
should be implemented.
Figure 3. Electrical Test Electrodes for
Figure 2. 275 kV SCFF Cable Right-of-
way Electrical tests include ACBD dielectric
Visit creek and river crossings after heavy strength of paper samples, loss angle, radial
rains and major storms. Examine rights-of- dissipation factor, capacitance, permittivity
ways for large tree growth that may reduce (Figure 3) and thermal stability. Aging of
soil moisture content and increase thermal short cable lengths of approximately 9-10
resistivity (Figure 2). All spares should be metres can provide insight into the present
located and include a spare cable length plus condition of a cable. See Figure 4 and Table
adequate fluid and at least two repair joints 1. Mechanical tests such as elongation-at-
and one termination. Perishables should be break, tensile strength and burst test carried
replaced and all tools, crimps, dies, pumps out on paper samples removed from a cable
etc should be located. If the spares are not repair or diversion can establish the
available then cable replacement may be mechanical deterioration of the papers in a
necessary. Arrangements must be made for fluid cable. Furthermore, the metallic sheath
cable jointers to do repair work at short condition can be determined by using
notice. metallurgical diagnostics such as Eddy
4.0 Laboratory Diagnostics: A Current and a dye penetrant technique. X-
multidiscipline approach can provide a ray diffraction can be used to assess
corrosion byproducts. See Table 3.
Figure 4. Short Length 9 m HPFF Cable
5.0 On-site Diagnostics: The first and Figure 5. Removing Paper samples for
possibly the cheapest approach is Infrared Laboratory Evaluation
Thermography on cable accessories, and the As well documented in the literature, there
second is Acoustic Emission. But with both are two major types of insulation
diagnostics it is necessary to have physical degradation: discrete or incremental, at
access to the joints and terminations. So voids or cavities resulting in electrical trees
only the terminations of direct buried cable and PD (Partial Discharge) and average or
systems can examined without additional overall degradation or material aging
effort. Sheath current measurements can “Global” without PD.
provide details on out-of-balance ac Table 2. DGA and Key Gas Indicators.
currents, ineffective cross-bonding and
corrosion currents, both ac and dc. Key Gas Indicator Underlying Cause
Table 1. Absolute Dissipation Factor of 9 m Cable Hydrogen Partial Discharge
Sample at 150 psi, Before and After AC
Withstand Test at 58 kV for 6 hours.
RED BLACK WHITE Carbon Monoxide/Dioxide Paper Degradation
PHASE PHASE PHASE
D.F. D.F. D.F.
Before/After Before/After Before/After Methane Overheating Problem
(E-03) (E-03) (E-03)
5 2.24/2.26 2.42/2.42 2.36/2.36
10 2.22/2.24 2.42/2.42 2.35/2.36
15 2.21/2.22 2.42/2.41 2.34/2.33 Ethane & Ethylene Overheating Involving a
20 2.20/2.21 2.42/2.41 2.33/2.32 Metal
25 2.20/2.20 2.41/2.40 2.32/2.30
Hydrogen and Other Rusting or Hydrolysis
30 2.19/2.20 2.42/2.40 2.31/2.29 Gases
35 2.19/2.19 2.41/2.39 2.30/2.27
40 2.18/2.18 2.41/2.38 2.29/2.26
Partial discharges occur in voids or cavities
in insulation or at interfaces in cables or
accessories. Mini sparks occur in voids that
emit broadband radiation 50 kHz to >500 frequency plus overvoltages are possible, if
MHz and pulse rise times of 1.0 ns. required.
Magnitudes can change with time, voltage, On the downside, the cable condition will
temperature, load and humidity (moisture in change, such as voltage, temperature and
cable), but the location stays the same. load. Off-line diagnostics include: 60 Hz ac
Attenuation along a cable, particularly at test, resonant test sets, VLF test (0.1 Hz or
higher frequencies, background noise, lower for longer cable lengths). combined ac
multiple discharge sites, cable branches as and VLF test or Complex Discharge
well as different insulation materials make Analysis (CDA), Oscillating Wave, VLF 0.1
interpretation difficult. And to date, time-to- Hz dissipation factor and PD, Isothermal
failure predictions using PD magnitude Relaxation and Return Voltage. These
alone are not possible. This makes diagnostics are summarized in Table 3.
replacement criteria difficult to justify. In On-line diagnostics look at what is there,
addition, electrical tree growth can be fast and have the advantage that no switching is
for small PD and slow for high PD or the required once the diagnostic is in place.
reverse. In addition there is a need to Trending is possible to relate insulation
distinguish between harmless and harmful condition and PD to operating conditions of
PD, plus electrical tree erosion rates of voltage, load, temperature and humidity.
materials are different. Overall or global However, it is not possible to control the test
deterioration can occur by chemical and voltage. DGA or dissipation factor can be
mechanical means as there is no water used to determine the overall or global
treeing in fluid filled cables. condition of the cable . See Figure 6 and
Figure 6. Fluid Analysis Report.
There are two approaches to on-site Figure 7. Acoustic Measurements on 110
diagnostics; off-line and on-line. Both kV SCFF Terminations
techniques must be non-destructive so as not
to reduce cable life. Off-line diagnostics are For discrete or localized deterioration;
performed with the cable de-energized so Ultrasound and PD diagnostics are
switching and grounding of the cable under employed (Figure 7). A summary of the
test is required. There will be system available methods is given in Table 3.
contingency concerns, space charge and
grounding issues to consider. But it is 6.0 Records and Trending: Access to
possible to control the test voltage and system operation records that include
switching information, major storm with improved performance. Furthermore
occurrences such as lightning or nearby both laboratory and in-situ diagnostics are
system faults is important to assess the beneficial, but improved data interpretation
potential of cable damage. Pin holes in the is necessary. And finally condition
insulation jacket can lead to major corrosion assessment must become part of any Asset
events. Keeping good base line data and Management program.
follow-up diagnostic data will aid in
Trending or how a specific parameter or 8.0 References:
condition is changing over time. Is partial  CEATI Underground Power Cable
discharge at given spot increasing or Workshop, Vancouver, Canada, June 2008.
decreasing? Is DGA content increasing over  IEEE Guidelines for Levels of Gases by
time and at what rate? [3, 4, 5] DGA
The laboratory results presented in Table 1  CIGRE 296, “Recent Developments in
combined with the analysis of Table 2 and DGA Interpretation”, Joint Task Force
the DGA gas content profile of Figure 6 can D1.01/A2.11, June 2006.
provide an insight into the cable condition.  CIGRE 228, “Service Aged Insulation
Repeating DGA over time will provide a Guidelines on Managing the Aging
trend for condition assessment. Process”, Working Group D1-11, June 2003
 CIGRE 279, “Maintenance for HV
7.0 Conclusions: Cable condition Cables and Accessories”, Working Group
assessment provides improved asset B1.04, August 2005.
reliability and increases cable service life
Table 3. Summary Table of Diagnostic Techniques
Dissection Electrical Discrete Integral Discrete and Integral
Dissipation Factor and
Contaminants, Voids, ACBD, Step PD at 50/60 Dissipation Factor
PD Inductive and
Electrical Trees, Paper Tests, Hz and PD at 0.1 Hz
Chemical, Moisture, Degree Complex Acoustic Noise
Capacitance on PD 0.1 Hz
of Polymerization Discharge Thermography
Mechanical, Tensile and PD Location Eddy Current and Dye
Dissipation Return Voltage
Elongation, Burst Test (2Uo ac res.) Penetrant
Short length tests, 9 m. Isothermal Relax.