Guide for the operation of self contained fluid filled cable systems

652
Guide for the operation of self contained
fluid filled cable systems
Working Group
B1.37
March 2016

GUIDE FOR THE OPERATION
OF SELF CONTAINED
FLUID FILLED CABLE SYSTEMS
WG B1.37

Members
C. Peacock, Convenor (AU),
S. Chinosi (IT), M. Choquette (CA), D. Van Houwelingen (NL), B. Mampaey (BE),
K. Ronningen (NO), K. Leeburn (ZA), R. Joyce (NZ), M. Fairhurst (GB), J‐M. Dulchain (FR),
P. Deus (BR), H. Suen (CA), M.D. López Menchero Cordoba (ES), N. Singh (US),
S. Kobayashi (replaced Y. Morishita) (JP), K. Ma (AU)
Copyright © 2016
“All rights to this Technical Brochure are retained by CIGRE. It is strictly prohibited to reproduce or provide this publication
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publication may be reproduced or utilized without permission from CIGRE”.
Disclaimer notice
“CIGRE gives no warranty or assurance about the contents of this publication, nor does it accept any responsibility, as to the
accuracy or exhaustiveness of the information. All implied warranties and conditions are excluded to the maximum extent
permitted by law”.
ISBN: 978-2-85873-355-2

Guide for the Operation of Self Contained Fluid Filled Cable Systems
3
Guide for the Operation of
Self Contained Fluid Filled
Cable Systems
Table of Contents
EXECUTIVE SUMMARY..................................................................................................................................4
Chapter 1 Introduction...................................................................................................................................... 5
1.1 Examples of Self Contained Fluid Filled (SCFF) Cable .........................................................................6
Chapter 2 Background...................................................................................................................................... 7
2.1. Hydraulic Aspects....................................................................................................................................8
Chapter 3 Operational Availability and Constraints, ..................................................................................... 16
Chapter 4 Maintenance for SCFF Cables....................................................................................................... 17
4.1 Land SCFF Cables.................................................................................................................................17
4.2 SCFF Submarine Cable Maintenance....................................................................................................23
Chapter 5 Leak Location Techniques............................................................................................................. 25
5.1 Leak Location Techniques for Land Cables ..........................................................................................25
5.2 Leak Location Techniques for Submarine Cables.................................................................................27
Chapter 6 SCFF Cable System Repairs.......................................................................................................... 28
6.1 Pre-repair Works Specific to SCFF Cables ...........................................................................................30
6.2 Repairs to SCFF Submarine Cables.......................................................................................................33
6.3 After Repair Tests for SCFF Cables......................................................................................................40
Chapter 7 Refurbishment and Modifications for Improved Performance...................................................... 43
7.1 Remote Fluid Pressure Monitoring........................................................................................................43
7.2 Minimise Cable Fluid Leaks..................................................................................................................43
7.3 Refurbish Cable System Design and Components ................................................................................43
7.4 Review of Cable Route Parameters Affecting Performance..................................................................45
Chapter 8 SCFF Cable System Life Extension Strategies.............................................................................. 45
Chapter 9 Retirement Strategies..................................................................................................................... 46
9.1 Environmental Impact............................................................................................................................47
9.2 Retirement Options................................................................................................................................47
Chapter 10 Cable and Accessories Suppliers................................................................................................. 48
Chapter 11 Conclusion................................................................................................................................... 49
References / Bibliography.................................................................................................................................. 51
Annexes.............................................................................................................................................................. 53

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EXECUTIVE SUMMARY
This working group was formed following concerns raised that although a large number of fluid filled cable systems
remain in service, there is a risk that cable suppliers will no longer support the technology and the skills and
knowledge will be no longer available to maintain fluid filled cables in a servicable condition. There is no esssential
difference in how AC and DC self contained fluid filled (SCFF) cables are treated. SCFF cables experience some of
the highest electrical stresses on the system.
This brochure provides a guide of best practice for the operation of self contained fluid filled (SCFF) cables based
on the 35 survey returns received and the practical experience of WG members.
A comprehensive survey undertaken by WG B1.10 and published as TB 379 “Update of service experience of HV
underground and submarine cable systems” showed 32% of total installed cables operating above 60kV were
SCFF cables. Above 220kV 56% were SCFF cables and above 315kV 72% were SCFF cables.
As SCFF cables are a mature technology that has been widely written about, this report contains material that is
essentially a compendium of material on practices that have been previously published.
The Questionnaire returns showed all respondents expected more than 40 years of service life from their SCFF
cables, 57% expected more than 50 years and 29% of the utilities expected more than 60 years of service life.
Falling revenues and regulatory pressures put pressure on utilities to prolong the service life of in service of cable
systems
The continued service of SCFF cables depends on: effective maintenance practices, good theoretical
understanding of the technology and practical experience. However, the reality is that knowledge and experience
are diminishing and the machinery used to make cables and accessories is wearing out and unlikely to be replaced
by organisations that would prefer to replace the cable.
For SCFF cables effective maintenance practices are seen as: ensuring the cables are operating within their
design pressures. Monitoring the condition of the cable fluid and for the presence of dissolved gases. Ensuring the
outer cable serving is in good condition. That fluid leaks are detected and repaired before there is any deterioration
to the electrical insulation
The quality of the design and installation of a cable system will influence its subsequent performance and reliability.
In the case of maintenance we acknowledge what is done, how often and by who is not only dictated by best
practice but by the business model, operational structure of the network and budgetry constraints.
For those recently introduced to SCFF cables, the publication covers some of the basic technology and practices
for effectively operating these cables.
We have included a list of known suppliers of the technology as it was in our Terms of Reference. However, the
Working Group does not recommend any particular vendors, contractors or consultants. Nor does it promote or
endorse any commercial products or services of third parties.

5
Chapter 1 Introduction
The self contained fluid filled (SCFF) high voltage cables have a history of reliability and appear to
continue their service as long as possible provided they are correctly operated and maintained.
Risks include: negligence, cable suppliers no longer providing support or the skills and the
experience being no longer available to work on this technology. This assumes that in service
SCFF cables were originally correctly designed, manufactured and installed.
SCFF cables represent a significant portion of installed HV and EHV underground and submarine
cable systems. After decades of highly satisfactory service performance their basic designs are
mature and not a lot of effort is being spent in developing this cable technology.
At the 2010 SC B1 meeting in Paris it was decided to initiate Working Group B1.37 to produce a
guide for the operation of fluid filled cable systems
The terms of reference for this Working Group were as follows:
 To establish the appropriate terminology
 To collect information and experience on the operation of fluid filled cable systems, using a Questionnaire
developed by the WG. The WG should consider refurbishment strategies for the continued operation of self
contained fluid filled cable systems.
 To collate, summarise and review the information
 To produce a working group report as a brochure recommending guidelines on the best practices for the
continued operation of self contained fluid filled cable systems. The WG will address the technical aspects
on the continued operation of these cables such as: recommended maintenance, testing (routine and after
repair), refurbishment and modifications for improved performance, operational availability and constraints,
fault repairs, oil system capacity reviews, fluid monitoring and analysis, leak location techniques and a
cable and accessories suppliers list.
 If time permits the following could also be studied: extension of service life, extension strategies including
use of transition joints, cable cooling systems
In 2011 this was amended to report only on self contained fluid filled cable systems.
Previous work by the Study Committee in this area had focussed on diagnostic methods for both paper insulated
cable and extruded cable, resulting in four publications:
1) “Diagnostic methods for HV paper cable and accessories” (WG 21.05), 1998 [2]
2) “Maintenance for HV cables and accessories”, (WG B1.04), 2005 [1]
3) “Update of service experience of HV underground and submarine cable systems” TB 379, WG B1.10, 2009
4) “Remaining life management of existing AC underground lines” TB 358, WG B1.09, 2008
The guide applies to both AC and DC SCFF cable.

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1.1 Examples of Self Contained Fluid Filled (SCFF) Cable
Figure 1 A 500kV SCFF cable with compacted
circular conductor and corrugated aluminium
sheath (CAS)
Figure 2 A 400kV SCFF cable with milliken
copper conductor and corrugated aluminium
sheath
(note helical duct support)
Figure 3 A 500kV SCFF cable with 1600mm2
copper keystone conductor and lead alloy sheath
Figure 4 An example of a 500kV single core
SCFF submarine cable

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1. Central Fluid Duct
2. Conductor
3. Conductor binder and screen.
4. Insulation (fluid impregnated paper)
5. Insulation screen
6. Metallic tape binder and/or semi-conducting hygroscopic binder
7. Metallic sheath (aluminium or lead alloy)
8. Outer sheath or serving.
Figure 5 An example of a 90kV 3 core SCFF
cable (Note heavily coated armour wires,
typical for submarine cables)
Fig 6 A typical cross section of a SCFF single
core cable showing component parts
Chapter 2 Background
Self-contained fluid filled cables (SCFF) are cables in which the conductor insulation is composed of multiple layers
of paper impregnated with a low viscosity dielectric fluid encased in a metallic sheath; usually lead alloy or
aluminium. For single core cable there is generally a central hollow core that allows the dielectric fluid to move
freely in the cable. Three core cables usually have a separate helical duct or ducts bound up in the fillers with the
cores inside its metal sheath. However, some three core cables have been constructed without fillers with the
space between insulated cores allowing the fluid to flow freely within the metal sheath.
Heat and vacuum treatment during manufacturing removes air and moisture from the papers. The papers are
impregnated with a low viscosity fluid to prevent the formation of voids and the associated ionization when
energised. A metal sheath, in the form of corrugated aluminium, or lead alloy (suitably reinforced) contains the fluid
under low pressures. An extruded plastic oversheath provides corrosion protection to the sheath. The fluid must be
maintained under positive pressure at all times. During operation the cable fluid expands into sealed storage tanks
as the conductor temperature increases and flows back into the cable when the cable cools.
Three core SCFF cables are typically limited to voltages up to 150kV and 630 sq mm (1 sq in.) due to
manufacturing, cable size, drum handling and installation limitations.
Submarine cables normally require the application of further mechanical protection in the form of round or flat wire
armour, fully surrounded by synthetic bedding and serving.
Polypropylene paper laminate (PPL), sometimes referred to as PPP or PPLP depending on the country of origin,
was later developed to reduce the dielectric losses and increase the impulse strength of the cable insulation. It
consists of a film of polypropylene coated on both sides with a layer of paper, lapped in the same way as paper

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insulated cable. It is similarly hermetically sealed and kept under positive pressure with cable fluid. However, its
technical advantage is offset by higher costs and is generally only used as an alternative to paper insulated SCFF
cables at extra high voltages.
Low pressure cable sheaths are normally made to sustain internal pressures of 5.25 bar with transients of
8 bar. For higher pressures such as for severe gradients, pressures of up to 15 bar can be used. For these
designs attention must be paid to the correct choice of the accessories, as well as the verification of the appropriate
cable reinforcement design. High pressure systems may be used for submarine systems or for high pressure fluid
filled (HPFF) pipe type cables. However, HPFF pipe type cables are not the subject of this document.
2.1. Hydraulic Aspects
The hydraulic design of a SCFF cable system is critical to its reliable operation and depends largely upon the
vertical profile of the cable installation. This is conveniently described graphically by expressing pressure in terms
of metres of fluid. The cable’s vertical profile and fluid pressures (static or transient) can be depicted on the same
diagram, the pressure at any point of the system given by the difference between the pressure line of interest and
the cable profile.
This hydraulic system design takes into account the cable route and elevation (or vertical profile), as well as the
cable fluid thermal expansions and contractions caused by cable system temperature variations. This assures that
possible over-pressures due to temperature transients do not cause mechanical damage to any part of the system:
the cable, accessories or the feeding system. It is normal for cables of longer routes or in undulating terrain to be
divided into a number of hydraulically separate sections by using stop joints, which maintain electrical continuity but
isolate adjacent hydraulic sections. The design must also ensure pressures do not fall under well-defined values so
positive pressures are maintained at any time.
2.1.1. Fluid Volume Variation
Temperature variations cause changes in cable fluid volume. Minimum volume occurs at the minimum temperature
in wintertime with the cable un-energised. Maximum volume occurs at the maximum temperature (usually in
summer) under maximum load or emergency (overload) conditions. The cable fluid reservoirs, usually pressure
tanks, placed at the cable end(s) and possibly in intermediate positions must accommodate the "static" fluid volume
variation.
Feeding Pressure Systems
Feeding pressure systems, or reservoirs, can be divided into constant pressure and variable pressure systems.
Gravity Fluid Tanks
Constant pressure systems are characterised by a feeding system composed of the so called “gravity tanks”, tanks
without internal gas cells that absorb pressure variations. Since this type of feeding system was the first to come
into service, to this category belong generally very old SCFF cable systems where the original fluid was mineral oil
and cable routes were short with flat profiles. Since the tank pressure cannot vary, the tank must be installed in a
position where the tank is higher than the highest system point. The tank must contain all fluid expansion from the
cable and the accessories under maximum hot conditions and return the fluid to the system by gravity in the worst
cooling conditions whilst maintaining positive pressures. Small changes in pressure due to changes in fluid levels in
the tank are usually ignored.
Pre-Pressurised Fluid Tanks
SCFF cables in service today are most likely to use pre-pressurised tanks as their fluid reservoirs. These tanks
contain a number of sealed flexible expanding cells that contain pressurised gas, usually carbon dioxide or
nitrogen. Expansion of the cable fluid is compensated by the compression of these cells. The tank capacity and
the pressure setting must be such that the minimum static pressure is higher than the highest system point and the
maximum static pressure does not cause, unacceptable pressure values for cable and accessories at the lowest
system point. The relationship between fluid volume variations and the corresponding pressure variations of a
cable fluid reservoir, of a stated type, is obtained either by means of a suitable experimental curve or by means of
calculations according to the "perfect gas" law.

9
Figure 7 Relationship between pressure and volume contents for a typical 120 litre variable pressure tank
Figure 7 is an example of a pressure volume curve for a typical 120 litre variable pressure fluid tank. The central
curve is the actual experimental one, obtained at ambient temperature; the other two curves are derived from the
central one, on the basis of the "perfect gas" law, for the extreme seasonal ambient temperatures expected.
Positions marked 1 and 2 in figure 7 shows that a 50 litre expansion due to a change in temperature from -20°C to
+50°C will result in a static pressure change from 0.5kg/cm (5.8m of fluid) to 2.2kg/cm² (25.3m of fluid).
The cable fluid volume variation can also be calculated using the perfect gas law according to the following
formula:
where:
∆V = Fluid volume variation, in litres
P1 and P2 = absolute values of minimum and maximum pressure, in kg/cm²
T1 and T2 = absolute values of minimum and maximum ambient temperature, in Kelvin (K)
P0, V0, and T0 = initial values for the gas inside the cells of the oil tank, in kg/cm², litres and K respectively
Provided the value of P0 x V0/T0 in known for the type of oil reservoir under consideration, this formula represents a
relatively easy way to evaluate the relation between fluid volumes, pressures and temperatures.

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Static Pressure Considerations
Gradual variations in temperature result in pressure changes that equalise throughout the cable system. In this
case gravity tanks experience very little change in pressure as a result of volume variation due to temperature
changes. However, pre-pressurised feed tanks encounter significant changes in pressure with volume variations
caused by temperature changes. The minimum tank static pressure usually occurring in winter with the cable de-
energised (no dielectric losses) and the maximum tank static pressure occurring in summer with the cable under
maximum load conditions.
These two extreme static pressure conditions must be considered in conjunction with the route profile to ensure
there is no risk of excessive static pressures on the cable or a risk of under-pressure and that part of the cable
going to negative pressure.
Figure 8 shows a schematic profile of a SCFF cable under static pressure conditions. In this example, the minimum
cable pressure occurs at the feeding end termination, while the maximum static pressure occurs at 650m, where
the route profile is at its lowest elevation.
Figure 8 Schematic Profile of a SCFF Cable under Static Pressure Conditions
Transient Pressure Considerations
Sudden load (and sometimes voltage) variations cause pressure transients in the system. Under the extreme
operating conditions: the maximum transient pressure curve must not cause excessive pressures in the cable
system whilst the minimum transient pressure curve must remain at a positive pressure above the cables altimetric
profile at all points along the circuit route. Longer length cable routes and those laid in terrain with severe variations
in elevation are prone to experience higher transient pressures. It should be also noted that lower viscosity fluids
would experience lower transient pressures.
Heating Transients
The maximum positive transient pressure occurs in winter, on energisation (dielectric losses are added) and
suddenly applying maximum load, or in a sufficiently short period of time. Under these conditions, the temperature
of the conductor and other cable layers increases but not as quickly as the cable fluids. The initial rate of
temperature rise is at its maximum, generating a high transient volume expansion of the liquid, which flows through
the cable towards the pressure tanks that are at the static pressure. The fluid encounters hydraulic resistance,
which is also initially at its highest, due to the increased fluid viscosity at the lower temperature. The cable
experiences a pressure transient during this phase.

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The general expression for the pressure variation with respect to the static pressure at the feeding end, is given by:
∆p=((A∙B∙L∙u)- (A∙B∙u2/2))∙10-4
Where: ∆p = the pressure difference, in kg/cm²
A = the volume expansion per unit time per unit length, in (cu.m/sec)/m, m3/s.m or m²/s
B = the friction coefficient of the oil duct per unit length of cable, in kg.s/m6
L = the length of the hydraulic cable section, in metres.
u = the distance at any point in the cable from the feeding end, in metres.
In particular, the maximum pressure difference between the extremities of a cable, fed from one end only is:
P = (A∙B∙L2/2)∙10-4
Halving the feed length by feeding fluid from both ends results in only a quarter of the pressure.
Since at the tank the pressure is set at the static pressure, the pressure at the other side of the line (or at the centre
of it in case of feeding at both ends) must inevitably be higher and is taken into account in system design.
Figure 9 shows an example of the maximum positive pressure transient for a hydraulic section fed from one end
only. In this example, the maximum pressure by inspection or calculation occurs at 1900 metres.
Figure 9 Schematic Profile of a SCFF Cable under Maximum Heating Transient Conditions
Cooling Transients
High negative pressure transients can result in some sections of the system being below the minimum design
pressure or going further to negative pressure (partial vacuum).
The cooling transients are more complex to evaluate. The worst negative cooling transient occurs when the system
was energised with maximum load and suddenly de-energised after a particular ‘critical time’. This ‘critical time’ is
of the order of a few hours.

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Figure 10 shows an example of an SCFF cable under various cooling transient conditions. The cooling transient
from the hot condition has little risk of causing an under-pressure due to the high initial tank static pressure. At the
minimum static pressure there is no cooling transient since the cable is already at its coolest. As the cable system
starts the transition from cold to hot (during energising with maximum load) the potential cooling transient
increases. There comes a ‘critical time’ when the combination of increased potential cooling transient and only a
moderate increase in static pressure results in the largest possible negative pressure transient. In this example the
minimum pressure in the cable occurs at 1350m.
Figure 10 Schematic Profile of a SCFF Cable under Cooling Transient Conditions
Multiple Hydraulic Sections
When a circuit is long or has significant variations in height along the route, stop joints are installed that separate
the cable route into hydraulic sections while maintaining electrical continuity. This allows the cable system to
operate within its design limitations, The stop joints may be connected to tanks providing the feed points to each
hydraulic section or separate feed points at joints along the hydraulic can be installed to suit the route profile. This
mitigates the risk of excessive static and transient pressures.
Figure 11 shows an example of the same SCFF cable system with stop and feed joints. The contour is identical to
the earlier examples. Feint lines reference the transient pressures. Detailed annotation has been omitted from the
diagram to reduce clutter.
A stop joint has been added (arbitrarily) at 500m. The feed tank at 0m caters for the fluid volume variation for the 0
to 500m section. Since this tank feeds a shorter section, the maximum tank static pressure is lower than before.
The shorter section length also reduces the maximum transient pressure. This pressure difference is 1/16 of the
original example. The maximum cable pressure occurring at 500m is 35.5m of fluid under maximum static pressure
conditions. The transient pressure is less (32.3m of fluid).
A feed tank has been added at the 2000m end of the circuit. A feed joint has been added (arbitrarily) at 1350m.
The tanks at these two feed points cater for the fluid volume variations for the 500 to 2000m section. This also
results in a lower maximum tank static pressure than before. The maximum cable pressure occurring at 650m is
32.5m of fluid under maximum static pressure conditions. The maximum transient pressure also occurs at 550m
but is less (30m of fluid). The minimum cable pressure is at 1350m and equals the minimum tank static pressure.
The very lower transient pressures on the 1350 to 2000m section is due to an effective fluid section length of only
325m (two end tanks feeding a 650m section)

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Figure 11 Schematic Profile Showing the Pressure Profile with Stop and Feed Joints Installed
2.1.2 Submarine Cables
SCFF submarine cables are designed electrically as underground cables, but are specially designed mechanically
to handle the large axial stresses experienced during installation, and to overcome the hydraulic challenges that
are special for submarine cables.
Both aluminium and copper conductors have been used. Different lead alloys have been used for submarine cable
sheaths. Submarine cables have strong longitudinal armour with different armour designs existing. The simplest
form comprises of one layer of round steel wires that introduces a torque in the cable when axial tension is applied.
The hydraulic aspects have to be considered in a slightly different way than is used for land based cables.
Submarine cables are often characterised by having circuit lengths much longer than those considered for land
installations with no possibility of interrupting the hydraulic circuit along the route. This has resulted in single core
cables with large oil ducts, up to 40 mm diameter, and the use of extra low viscosity fluid (3 - 5 centistokes at
20°C.)
Submarine fluid filled cables have been in service for more than 60 years, with cables installed in the 1950’s still in
use. Submarine cables were originally used to cross watercourses that were too wide to cross with overhead lines.
Cable lengths were limited by manufacturing equipment. However, this limitation was overcome by introducing
factory joints. The need for longer and larger cables also resulted in submarine cable factories being built close to
the sea with their own loading facilities to minimise problems with the transport of very long lengths from factory to
a laying vessel.
Traditionally, cables were laid directly on the sea bottom without additional protection. But at the shore landings
(splash zones) the cables were protected by different means, typically down to 10m water depths, in order to
minimize or eliminate wear and tear, and also minimize corrosion problems especially to the armouring. Types of
protection include trenching where there are trenchable conditions, or placing mechanical structures over the cable
where trenching is not possible. Since 1990’s it has become more and more common to protect the entire cable
length, preferably by trenching. If trenching is not possible, other protection methods are used, such as rock
dumping or covering by use of mattresses of different kind. Refer to TB 398 for further information.
The fluid feeding system design for a submarine cable can be pressure tanks for short and shallow crossings,
similar to land based cables. Longer deeper crossings use pumping plants installed at one or both ends of the

14
crossing. Submarine cables up to and including 170 kV have often been manufactured as three-core cables, while
SCFF cables for higher voltages always are single core cables. With the development of conductors with large oil
ducts and the use of extra low viscosity fluid, cable lengths up to 60 km between pumping plants have been
installed.
Some cable installations have additional corrosion protection systems. This can be a passive system, such as
adding anodes to selected parts of the cable. Active systems, such as suppressed current systems are also added
to some cables.
2.1.2.1 Feeding Pressure Systems for Submarine Cables
Submarine cables are normally characterised by having circuit lengths much longer than those considered for land
installations with no possibility of interrupting the hydraulic circuit along the route. This may require the hydraulic
section to be long and deep, requiring special feeding systems such as pumping plants. Pumping plants for SCFF
submarine cables were introduced around 1980, when the technology used for HPFF pipe type cables was
adapted for the low viscosity cable fluids used in SCFF cables. Depending on the feeding pressure required, the
design is evaluated to consider the use of pumping plant installed in one pumping station with a crossover device
at the opposite end, or the use of pumping stations at both ends.
In terms of transient pressure variations, in addition to the verifications considered for land applications, the
“apparent profile” of the route must also be taken into account due to the difference between oil and water
densities, applied to the water depth at any point. This generates a further pressure profile, which should not
experience negative pressures at any point of the route.
The mechanical considerations already discussed for land cable applications are emphasised for submarine
applications, due to the higher system working pressures.
A further design requirement for a SCFF submarine cable is to maintain a positive fluid flow out of the cable in
order to prevent water ingress until the damage can be sealed and a cable repair implemented.
Single core submarine cable systems differ from land SCFF systems where each phase of the circuit is
hydraulically separated from the others in order to avoid loss of fluid from the two undamaged phases. In
submarine systems the normal practice is to interconnect the hydraulic circuit of the entire system to allow for
feeding a leak by pumping fluid through the two healthy cables. For a cable system with one pumping station and
one crossover device/manifold, when a fault occurs at the cable end close to the crossover device location, the
pumping plant feeds the leak from one end and through the two undamaged cables through the crossover device
at the opposite end.
For three phase cables it is advisable to have feeds at both ends.
2.1.3 Submarine Cable Pumping Plant
A submarine pumping plant consists basically of a large vacuum sealed fluid storage tank, vacuum pumps, fluid
pumps, valves and measuring devices. See figure 12 for a representative outline (with project specific capacities
shown). The plant also incorporates a regulation system that maintains the fluid pressure in each cable between
pre-set values based on fluid flow calculations. The system includes alarms that are activated by abnormal
conditions. This can be set for values of high or low pressure or a fluid level in the tank, indicating a fluid leak.
A series of flow limiting valves are installed at the pumping plants and at the crossover devices to limit fluid loss
resulting from a cable fault. This system is designed to ensure enough fluid flows out of the cable duct to prevent
water ingress at the point farthest from the feed point.
The typical fluid feeding system design for a submarine cable takes into account the worst feeding condition,
normally represented by a cable cut at the farthest end from a feeding point, and considers the cable fluid viscosity
and cable load.
At the maximum operating temperature a large volume of cable fluid moves from the cable into the pumping plant
tanks. When a cable failure occurs the heating transient ceases and the cooling transient starts. At low ambient
temperatures the cable cooling is rapid, requiring a large volume of fluid movement from the storage tanks into the

15
cable to compensate for the contraction of fluid within the cable and any loss of fluid from the point of failure. At the
low ambient temperatures, the tank fluid viscosity is relatively high; consequently the hydraulic resistance is high for
the cable fluid that is now forced towards the fault location.
The cable fluid feeding system design for a SCFF submarine cable with pumping plants must take into account the
worst case feeding condition. This occurs when the circuit is energised onto full load and during the heating
transient a failure causing a severe leak occurs at the furthest point of the line from the pumping plant. In that
condition, the fluid initially expands from the cables into the tank/s during the heating phase (so the conductor and
fluid have still not reached their maximum operating temperatures) and the fluid exits the cable at the leak location
during the cooling phase. Since this fault time is quite close to the energising time, the cable fluid is still cold and
consequently its viscosity is high, requiring a sufficiently high pressure to feed the fault location. This condition
determines the value of the pressure necessary to feed the cable with a positive pressure with respect to the water
pressure at the remotest possible fault point.
For a cable system with a pumping plant at each end the worst case will be a severed cable close to one pumping
plant. In the case of a cable system with one pumping plant and a crossover device, it will be a severed cable
close to the pumping plant with a fluid feed through one or two healthy cables to the crossover device and returning
through the section of cable connected to the crossover.
Figure 13 shows a schematic for an example of a very long submarine connection with pumping plants at
each end of the submarine crossing.
Figure 12 An Example of a Pumping Plant Schematic
(project specific capacities and equipment shown)

16
`
Chapter 3 Operational Availability and Constraints,
From an operational point of view, SCFF cables often give a warning when something goes wrong before the
actual breakdown of the system. By means of the permanent or regular pressure monitoring of the fluid pressures
in the system a problem can be found and actions can be taken to avoid the breakdown of the system.
In case of severe external damages the alarm will almost immediately be followed by the breakdown of the system.
From an operational viewpoint SCFF cables historically have a lower availability than XLPE cables due to their
higher maintenance requirements, susceptibility to leaks and their longer repair times. The total repair time is
dependent on the time needed for:
 The type of repair
 Time to localise the fault and re-establishing healthy cable
 The availability of spare parts and experienced technicians and
 The time required for the repair, including the fluid treatment, the re-establishing pressurisation of the cable
system and the additional tests required.
For a SCFF cable it can take several months before the cable system can be operational, particularly if contingency
planning has not been undertaken. This can have a significant impact for the grid operator who may have to secure
the grid by rearranging load flows. These failures can also lead to other planned outages for maintenance or
projects being rescheduled to a later date.
For grid operators it is very important that a cable can be energised as quickly as possible after a breakdown. To
achieve this, spare parts, cable fluid and experienced technicians must be readily available. Provided grid owners
are prepared to meet the cost, new technology is available that can reduce the time needed for leak location (see
chapter 6).
Figure 13 An Example of a SCFF Submarine Cable Circuit with Pumping Plant
(project specific equipment and values shown)

17
Chapter 4 Maintenance for SCFF Cables
Maintenance of SCFF cables is primarily concerned with preserving the integrity and satisfactory performance of
the hydraulic system to maintain a full and effective impregnation of the cable system.
4.1 Land SCFF Cables
Information recommended for effective maintenance includes:
 The cable system’s design specification and as installed information, including a general description of the
cable system as installed and its component parts.
 Cable route plans complete with joint locations, distances, trench and other cross sections and any major
infrastructure crossings.
 Cable route profile showing a schematic of the cable system with its hydraulic elevation profile, joint locations
and types, tank locations with types and settings. Sheath bonding arrangements for single core cables.
 Detail drawings of all joints, sealing ends, pressure tanks, link boxes and other accessories.
 Jointing instructions in the appropriate language. These should include information on fluid management and
flows required for each stage.
 Instructions in carrying out effective repairs on the metal sheath and outer serving
 A list of specialised tools required for working on various accessories.
 Manufacturing and installation test reports including thermal resistivity readings of any design backfill and any
readings taken along the excavated route.
 A technical schedule for the power cable and any pilot cables with cross sections of the SCFF cables make
up showing diameters of the components and details of the components.
 Pressure tank information including volumes cell pressure, cell gas and pressure/volume (P/V)
characteristics.
 Tables of design minimum and maximum pressures for each feed/monitoring location, operating pressures,
high, low and any differential alarm settings. Tables should include fluid pressure and temperature reference
points.
 Type and characteristics of the cable fluid including a graph of viscosity and density against fluid
temperature.
 Details and characteristics of all components used including drawing details, work instructions and safety
data sheets.
 Recommended spares, storage and inspection information.
 Any recommended maintenance and testing procedures.
 A drawing and instruction list
 Detailed records of maintenance and in-service performance including all relevant test reports.
Although the Questionnaire included maintenance tasks common to all cable types we have omitted them from our
analysis to concentrate on those specific to the effective operation of SCFF cables. Essential to this are:
 The effective monitoring of cable pressures
 The hydraulic system performing as intended
 An effective barrier to contain the cable fluid
 The quality of the cable fluid
Figure 14 shows the relative priority placed on maintenance task by those who returned completed
Questionnaires. The histogram shows the physical condition of accessible tanks and an effective fluid
monitoring system were the priority to the majority of respondents.

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Figure 14 Maintenance tasks specific to SCFF cables as a percentage of Questionnaire replies
4.1.1 Fluid Pressure Monitoring
4.1.1.1Fluid Pressure Readings and Inspections
For SCFF cables without remote monitoring, routine reading of fluid pressure gauges is recommended as a check
that the system is operating within its designed pressure limits.
66% of the Questionnaire returns carried out readings and inspections of pressure gauges. The interval between
readings in the Questionnaire returns varied between daily and 6 monthly. How critical the circuit is and the
number of monitoring devices on each hydraulic section should determine reading intervals. For example, cable
circuits with only one monitoring device per hydraulic section should be checked more often than locations where
back-up monitoring is fitted.
Manual gauge reading requiring access into enclosed vaults under roadways may require approval to alter traffic
flows and other additional expenses incurred to safely enter these confined spaces. Reading gauges from outside
the enclosure with remote HD cameras or other means may reduce the effort and risks involved. Installing a remote
fluid monitoring system that allows continuous monitoring would remove this hazard.
4.1.1.2Pressure Gauge Accuracy and Pressure Alarm Checks
Periodic testing must be carried out on the pressure monitoring system to ensure gauges, transducers for remote
monitoring and the pressure alarms are working and the alarms are being received at a central control point. The
Questionnaire returns showed 69% undertook gauge accuracy and alarm checks and this was most commonly
carried out annually.
Inspecting the condition of gauges is recommended, ensuring no moisture entry or internal corrosion. The gauge
accuracy should be against a calibrated gauge connected into the same pipework in parallel with the gauge,
usually at the fluid sampling point. Normal working pressures and low alarm pressures settings can be checked for
accuracy against the test gauge.
To ensure the contacts operate at the correct pressures and a signal is received at the central control point: release
the cable fluid pressure slowly off each pressure monitoring device (gauge or transducer) observing the reading at

19
which the contacts operate and that a single is received at the control point.
If the pressure monitoring equipment is in acceptable condition and is operating correctly, restore the system to its
normal operating mode. If not repair or replace any defective items, this may require the cable to be taken out of
service.
It is imperative that after working with control valves at tank locations the valves are restored to their normal
operating position. Not doing this may result in stopping fluid flows between the cable and tanks and parts of the
hydraulic section falling below minimum pressure or over pressurising, resulting in a failure.
4.1.2 Cable Fluid Testing
This section describes the tests normally used to check that the quality of the cable fluid impregnant is within the
limits specified by the cable suppliers or standards set by the utility. Remarkably only 43% of the Questionnaire
respondents carried out any fluid testing on a routine basis and only 34% carried out a series of tests. The
minimum recommended tests for cable fluid samples are: dissolved gas analysis, dielectric dissipation factor, water
content, electric strength and a DC restivity test.
Routine testing is carried out on fluid samples taken from feed joints or sealing ends and the feed tanks. To ensure
that the cable fluid tested is representative of the fluid in the cable or tank, a volume of cable fluid estimated to be
in at least the pipe connections between the accessory and sampling point is first drained off and collected as
waste. Correct sampling and labelling of samples are extremely important as they contribute to the accuracy of
laboratory testing. The laboratory results are used to determine the need for any corrective actions that may require
expensive work and long outages. The returns showed that some utilities with a large number of SCFF circuits
varied their testing periods indicating it formed part of a condition based maintenance system.
Refer to Annexe 3 for recommended sampling techniques. The Questionnaire returns showed that 57% of the
respondents taking fluid samples did so with the cables in service. This could depend upon pipework
configurations, sampling techniques, the utilities policies or risk profiles.
The cable fluid sample tests carried out during routine maintenance are normally also carried out on a hydraulic
section’s fluid prior to and after cable repairs.
The five tests commonly carried out by chemical laboratories to determine the quality of SCFF cable fluid samples
are described below and it is recommended they form the basis for a condition based maintenance regime. There
was a high degree of variability in the returns received for cable fluid testing. The periodicity for recommended tests
typically varied between 1 and 9 years with the majority testing at 3 to 5 year intervals. Some participants in the
survey may be able to reduce their maintenance costs by increasing the sampling periods if testing is giving
consistent results.
The returns also showed that some utilities with a large number of SCFF circuits varied their testing periods
depending upon results indicating a condition based maintenance system. SCFF owners should consider adopting
a condition based maintenance system, and vary sampling periods based on the results of previous tests.
4.1.2.1Dissolved Gas Analysis or Gas Chromatographic Analysis
Abnormal thermal and electrical stresses cause breakdown in the insulating fluid and paper of a cable, generating
gases that dissolve into the cable fluid. This can result from overloading, hot spots, movement in the cable, arcing
or partial discharges from electrical stresses and voids. An indication of developing problems and condition of the
paper insulation can be given by analysing these gases in fluid samples taken from a cable. These conditions can
occur at the same time adding complexity to an analysis. Gases of interest are: hydrogen (H2), oxygen (O2),
nitrogen (N2), methane (CH4), ethane (C2H6), ethylene (C2H4), acetylene (C2H2), carbon monoxide (CO) and carbon
dioxide (CO2).
A dissolved gas analysis (DGA) test is basically looking for the presence of these gases, amounts and the rate at
which they are produced. Gases present from the breakdown of cable fluid are hydrogen and hydrocarbons whilst
breakdown of the paper insulation produces excessive amounts of carbon dioxide, carbon monoxide or oxygen.
The presence of acetylene with methane and hydrogen suggests partial discharge or arcing.

20
Large quantities of hydrogen and methane and the presence of ethylene and ethane suggest thermal breakdown in
the fluid.
If small quantities of acetylene were also present then a low level electrical discharge is a likely cause.
Arcing produces relatively significant quantities of hydrogen and acetylene with the presence of methane and
ethylene. Significant quantiies of acetylene, hydrogen methane and ethylene may require the dissection of joints
and terminations to investigate the cause of the gas generation.
The presence of carbon monoxide,carbon dioxide and oxygen with any of these combinations can indicate a
decomposition of the paper insulation or high conductor temperatures from overloading or hot spots.
Quantities of nitrogen and oxygen may result from poor quality fluid or poor sampling techniques.
IEEE Guidelines1 for dissolved gas levels in SCFF cable fluids are shown in table 1:
Dissolved Gas
Normal concentration for cable
system of age (ppm):
Moderate
concern
(ppm)
Major
concern
(ppm)<5 yrs 5-20 yrs >20 yrs
N2 50 75 100 >300 >500
O2 25 50 70 >100 >300
CO2 20 50 75 >150 >300
CO 10 20 50 >100 >200
H2 50 75 100 >200 >400
CH4 5 15 30 >50 >100
C2 H6 10 20 40 >75 >150
C2 H4 0 5 10 >25 >75
C2 H2 0 0 0 >10 >25
Total Concentration of
Gases
50 100 200 >400 >800
Table 1 Concentrations of Dissolved Gases in SCFF Cable Fluid
As sampling points are not always at the location of a potential problem and could be some distance away, less
gas content does not always mean there isn’t a problem. Indicative levels of acetylene may show there is a defect.
The composition of the hydraulic section needs to be considered. Fortunately sampling points are normally located
at the higher electrically stressed components: sealing ends, stop joints and feed joints.
IEC 605992 deals with in service mineral oil insulated electrical equipment. In its Table 2 are basic gas ratios that
are indicative of the type of problem that could be generating the gases. In Annexe 5 of that publication also warns
of the difficulty of applying DGA to SCFF cables due to the lack of a representative fluid sample, additionally the
fluid mixture may be an unknown composition of fluids. Gases mixtures generated by mineral oils and synthetic
fluids differ and their absorption rates under electrical stress are not the same.
All routine test results give a baseline for further monitoring and trend analysis. Refer to Annexe 3 for typical
methods of sampling cable fluid for testing.
For further information refer to TB 627 “Condition Assessment for Fluid Filled Insulation in AC Cables”, also
references 1, 30, 31,32 and 33 in the References / Bibliography.
1 IEEE 1406-2004 - Guide To Use Of Gas In Fluid Analysis For Electric Power Cable Systems
2 IEC 60599 Ed 2.1 2007-05 Mineral oil-impregnated electrical equipment in service – Guide to the interpretation of dissolved and free gases analysis

21
The usual corrective action for high levels of dissolved gases is to take the cable out of service either straight away
or on a planned outage, depending on the relative risk indicated by the gas concentrations when compared with
historic records. The fluid in the cable duct of the section can then be replaced with new cable fluid, preferably
linear alkyl benzene (LAB) or treated degasified cable fluid, that has been processed through a fluid treatment
plant. When design pressures have been re-established a wait of 48 hours is normal practice before taking another
DGA sample for analysis. Repeat the process until the test results show acceptable concentrations of dissolved
gases. Depending on the analysis the disolved gas levels may be re-tested after a period in service or at the next
planned maintenance. Continued poor readings or a rapid increase in levels normally require physical intervention.
The Questionnaire returns show this test was carried out by 43% of participants at intervals between one and nine
years with an average value of around three years. The returns showed that some utilities with a large number of
SCFF circuits varied their testing periods indicating it formed part of a condition based maintenance system.
4.1.2.2Dielectric Dissipation Factor or Loss Angle Test
The dielectric dissipation factor (DDF) is given by the tangent of the angle between applied voltage and resulting
current differs from ninety degrees, when the untainted cable fluid is a pure capacitor. Any reduction is a measure
of the contaminants in the cable fluid and its deterioration. Tests are normally carried out at 30oC and 90 oC. For
further information refer to IEC60247 “Insulating liquids - Measurement of Relative Permittivity, Dielectric
Dissipation Factor (tan δ) and D.C. Resistivity”. An indicative acceptable value for older cables would be 0.01 or
less at 90oC.
4.1.2.3Water Content
This test is undertaken to measure of the water content of a cable fluid sample in parts per million (ppm).
Laboratory testing using the Karl Fischer titration is the most common method used. For further information refer to
IEC 60814 “Insulating liquids - Oil-impregnated Paper and Pressboard - Determination of Water by Automatic
Coulometric Karl Fischer Titration”. Typical values should be less than 20ppm. The test was performed by 34% of
respondents.
4.1.2.4Electric Strength Test
This test determines the voltage gradient at which breakdown occurs under test conditions. It is recommended as it
gives an indication of the presence of contaminants in the cable fluid. The test didn’t rate highly in the
Questionnaire returns with only 17% claiming they conducted this test. For further information refer to IEC 60156
“Insulating Liquids - Determination of the Breakdown Voltage at Power Frequency”. An inducative acceptable value
for older cables would be not less than 25kV across a 2.5mm gap. The test was performed by 17% of respondents.
4.1.2.5DC Resistivity Test
Normally carried out in conjunction with DDF testing, this test also indicates the presence of contaminants and
deterioration by-products in the cable fluid. Measured in Gohm.metres it is the ratio of the direct potential gradient
to the current density at a given time under test conditions. Only 11 % of Questionnaire replies claimed they
undertook this test on a periodic basis. For further information also refer to IEC60247. An indicative mimimum
acceptable value would be 100 Gohm.m at 90oC. Only 11% of respondents said they carried out this test.
Other tests that can be conducted on a cable fluid sample are:
4.1.2.6Acidity Test
Carried out to assess the degree of acidity of a cable fluid by measuring its neutralisation value. For further
information refer to the relevant part of IEC 62021 “Insulating liquids - Determination of acidity”. Again only 11% of
the returns indicated the use of this test.
4.1.2.7Particle Count
This test should be performed as a routine test after jointing. Also where concerns exist that there may be
impurities in accessories from previous jointing. Examples of this can be a build up of copper swarf in a sealing
end. If there is a concern, monitoring and comparing outcomes with previous results is advised to detect any trend.
For further information refer to IEC 60970 “Insulating liquids – Methods for counting and sizing particles” An

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acceptable upper limit for one utility in the 2-5 micron range was 50,000 per 100ml of sample fluid.
4.1.2.8Cable Fluid Mix
Intended to monitor the mix of insulating fluids in the cable where a different fluid has been added to the system,
e.g. where synthetic cable fluid has been added into a cable originally supplied with mineral oil. It assists in
predicting the fluid mix and likely change in properties. Item 33 in the Bibliography suggests that blend systems
exhibit a combination of properties that renders them superior to either mineral oil or synthetic cable fluid alone.
According to one utility the synthetic fluid content should exceed 35% of the mix for land SCFF cables. For
submarine cables using pumping plant to maintain cable pressures, the mixing of cable fluids with different
expansion coefficients and viscosities is not recommended.
4 .1 3 Pressure-Volume Test on Feed Tanks
Pre-pressured tanks in a SCFF cable system maintain the internal cable system pressures within the design limits.
A periodic pressure-volume (PV) test on the feed tanks ensures pressure cells have not lost their gases. The
Questionnaire replies indicated that 40% of participants carried out this test on feed tanks.
4.1.4 Sheath and Cross Bonding Tests
4.1.4.1Over Sheath Integrity Tests
Described in the Questionnaire as Anticorrosion Sheath Tests and also know as Insulation Resistance (IR) Tests.
This test is recommended for direct buried and duct installed SCFF cables as serving faults on a cable can lead to
corrosion of the metal sheath exposed to water or local ground conditions, eventually with the sheath being
compromised, resulting in a fluid leak. Aluminium sheaths are particularly at risk. Fluid leaks pollute the local
environment, putting the utility at possible risk of contravening regulations and potentially prosecution by the
authorities charged with protecting the environmental.
Severe serving or oversheath faults can also present problems to the cross and single point bonding of single core
cable systems affecting the rating of the circuit and possibly its performance under fault conditions.
Multiple serving faults on a cable section are difficult to pinpoint due to the multiple parallel current paths to earth.
High voltage DC is applied across the cable serving between the metallic sheath and earth, testing the physical
integrity of the outer sheath. For established land cables and depending upon the serving (or oversheath) material,
an applied voltage of at least 2.5kVdc for one minute is recommended. Readings above 1 Mohm are generally
satisfactory for older cables. Lower values of IR indicate at least one incipient serving fault. Serving faults are most
common at joints where movement can result in cracks in the coffin insulation compound, providing a path for
water penetration to the joint’s metallic casing with a minor risk of corrosion to the metallic sleeve. However, there
is no point in doing this test if you are not going to locate and repair the serving faults. The Questionnaire returns
showed that this test was carried out by 40% of participants on a 3 year average.
Other tests that are normally conducted on SCFF cables that apply to HV cables in general:
4.1.4.2Sheath Resistance Tests
Measure the dc resistance of the metallic sheath and connections to compare the results with the manufacturer’s
sheath resistance usually expressed in ohms/km in the cable specification.
4.1.4.3Sheath Cross Bonding Continuity Tests
For single core cable systems with cross bonded sheaths, tests on out of service cable sheaths are performed to
verify the integrity of the cross bonding system. The tests ensure circulating sheath currents generated by induced
voltages at full load do not adversely affect the cable rating.
This test involves injection of a three phase current into the cores of the cable and measuring the voltages and
currents induced into the sheaths at each cross bonding point along a complete cross bonding section. Sheath
currents and voltages are measured at each cross bonding point, earth point and termination. The cross bonding
connections shall be re-arranged to prove an incorrect connection, and checked again after restoring the correct
connection.

23
The procedure is repeated for each complete cross bonding section of the cable run.
Current and voltage measurements are scaled up to the rated load current of the cable circuit. Voltage values at
isolated (not solidly earthed) cross bonding points should be less than the rated load current scaled voltages of the
installation design. Scaled voltage and current values for each cross bonding point should be retained for record
purposes and reported to those responsible for cable ratings.
4.1.4.4Sheath Voltage Limiter (SVL) Tests
For single core cable systems with specially-bonded cable sheaths only. There are various types of SVLs, also
known as cable covering protection units (CCPUs), supplied with sheath bonded cable systems. With non-linear
voltage/current characteristics, they connect the metallic cable sheaths to earth limiting the transient voltage rises
under fault conditions to avoid puncturing the cable servings and flash-overs across the sectionalising insulator of
joints..
The SVLs should be tested in accordance with the manufacturer’s recommendations to ensure their compliance
with their original characteristics.
4.1.4.5Earthing Resistance
Earthing resistance testing at all points to earth to make sure the values are within acceptable levels, normally less
than 10 ohms.
4.1.5 Cable Route Patrols
As with most high voltage cables installed in public streets and places a patrol of the route should find excavation
activity that could affect the cables performance. Patrols are essential for direct buried SCFF cables as even the
slightest damage to the cable over sheath can result in corrosion of the sheath and eventually a fluid leak. The
frequency of the patrols varied in the Questionnaire returns received but should depend on how critical the circuit is
to system reliability, some critical circuits may be patrolled daily.
The periods recorded in Questionnaire returns varied between daily and annually with an average around three
months. In our opinion infrequent patrolling may not effectively prevent third party damage.
It is recommended that the disturbance of design backfills around cable circuits and the build up of ground over the
cables should be included in the patrol criteria. Directional drilling activity within the vicinity of direct buried cables
should be investigated as direct laid cables normally only have protection or warning covers installed in the backfill
over the cables.
4.1.6 Sample Testing
To get an idea of how the cable is ageing it is recommended that anytime the cable is cut into (if possible) a 300
mm sample of cable is taken to assess ageing and degradation of the paper insulation by laboratory testing the
degree of polymerization of paper samples. For lead sheath cable the condition of the lead should also be
assessed.
For any excavation activity on the cables, soil samples and design backfill samples should be taken and tested to
establish whether thermal resistivity (TR) values are consistent with those used to calculate the cable rating. Where
increased TR readings over the original design values are found, an assessment of the cable rating is
recommended.
4.2 SCFF Submarine Cable Maintenance
The maintenance program for SCFF submarine cables should be designed based on the following:
 the cable design
 the type of fluid feeding system used (pressure tanks or pumping station)
 any data covering cable route and cable position
 the type and dimension of cable protection, if any (i.e. trenching, mechanical protection by mattresses,
concrete covers, rock dumping or the like) as installed

24
 the corrosion protection system, if applicable
 assumptions of the as installed cable system.
4.2.1 SCFF Submarine Cable Maintenance Strategy
It is assumed that for all fluid filled submarine cable systems there is at least an abnormal pressure alarm
connected to a manned control centre for the grid.
The most common periodic maintenance procedures for submarine fluid-filled cables are:
1) Monitoring the hydraulic system. This includes site inspections at regular intervals of the physical
fluid feeding system at each end of a submarine cable installation.
2) Cable surveys at regular intervals to:
a. check that the input data and assumptions used for the cable system design are still valid
(cable position, burial depth etc.)
b. check that there is no mechanical damage that might cause cable breakdown.
4.2.1.1Monitoring the Fluid Pressurising System
Pressurising systems should be continuously monitored. The simplest system is pressure gauges giving alarm at
preset low pressure readings. Check that alarms are being received at a central monitoring point.
High-pressure tank batteries should be inspected on a regular basis to make sure that each tank is functioning
correctly. Samplng and testing the tank fluid for dissolved gases is also recommended.
The Questionnaire replies showed that the majority of utilities continouslly monitor pressure readings on submaire
circuits. In addition, inspections on site that check and calibrate pressure gauges and test alarms are also
performed. Annual pressure gauge calibration and alarm testing on a monthly basis are recommended. The most
common test of fluid samples is dissolved gas analysis (DGA) This is recommended to be performed annually, but
no longer than three years between tests.
Other tests recommended on samples of cable fluid are: dielectric breakdown test, DC resistivity test and
dissipation factor/dielectric loss. Pumping station maintenance should be performed according to the supplier’s
maintenance manual.
4.2.1.2Route Surveys
A route survey at regular intervals is recommended, depending on the knowledge of conditions along the route. A
specialist survey company with the technology available to do the job properly should be hired to undertake the
survey, using a survey vessel with the necessary equipment for the survey: both ship-mounted survey equipment
and equipment mounted on remotely operated vehicles (ROV’s). Experience has shown that heavy-duty survey
vessels used in the offshore oil industry give the best overall result at the lowest overall cost, as the time required
by these vessels to complete the survey will be relatively short, breakdown of equipment is less, waiting on weather
is less, quality of results are good and results are usually processed in parallel with the survey itself. Day rates for
the spread tend to be high, but the total bill tends to be lower than cheaper systems that need longer times to
complete a survey.
4.2.1.2.1 Survey Data Collected
The survey data collected and maintained is usually:
 Bathymetry and the actual position of the cable if the existing data is not of good quality.
 Cable burial depth/coverage.
 A record of a visual inspection of the route, where possible.
 A history of works and activities performed in the vicinity of the cable system (new feeders, pipelines,
crossings etc.).

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4.2.1.2.2 Reasons for Checking the Burial Depth or Coverage over the Cables
Depending on bottom conditions, over time the cable might sink into the mud or currents may disturb the original
coverage. Natural deposits from the sea may add to the cover over the cable. Unintended coverage of the cable
could also be caused by minor mudslides from fishing activity or unauthorised material dumping along the cable
route. If additional coverage increases for a major part of the cable length, the cable system rating and hydraulic
parameters will have to be recalculated. Although the thermal capacity may not be exceeded, the hydraulic system
parameters will change as the maximum cable temperature increases. This could be problematic, especially where
the cable is pressurised by pressure tanks.
4.2.1.2.3 Visual inspection
Depending on the depth, a visual inspection may be performed by divers or by ROV. The inspection should
concentrate on looking for indications something has hit the seabed around the cable. Where the cable is visible
look for: possible damage caused by small anchors, chains or other hard bodies that might have hit the cable. The
inspection should also look for signs of: underwater landslides or other traces of seabed movement, corrosion or
organism attacks especially in the splash zone or shallow waters. Cable suspended above the seabed in tidal
areas is at risk of damage from strumming, caused by cross currents flowing around the cable.
Chapter 5 Leak Location Techniques
Before undertaking a leak location on a cable section it is prudent to perform a simple test to determine whether the
leak is in the cable or the feed tanks. This can be done to a temperature stabilised cable at the alarm location by
isolating the cable from all other feed points and cables, connecting a digital manometer to the cable at the
manifold feed point and close the valve connecting the tanks to the cable and manometer. A drop in the
manometer reading indicates the leak is in the cable. If the reading remains steady then the tanks and connecting
pipework should first be checked.
5.1 Leak Location Techniques for Land Cables
Pinpointing the location of leaks in SCFF cables installed in tunnels or pit and duct infrastructure can be done by
inspections in the tunnel or pits. For SCFF cable with buried joints, a relatively simple method of detecting future
leaks at joints is to create a retention area around the joints whenever a joint bay is excavated. This can be done
with sealed plastic sheeting and bunded walls and by providing an inspection pipe from the low point to a ground
level inspection cover.
5.1.1 Freezing
This method freezes a short length of cable fluid so the cable needs to be de-energized. Suitable precautions need
to be taken to ensure the safety of people conducting the freeze and to ensure the frozen cable does not move and
damage the cable.
A small length of cable is uncovered, usually mid point in the leaking cable section. In some cases pressure drops
at each end of the section may give a better indication of where else to place the first freezing point.
The cable serving (or jacket) at the freeze point needn’t be removed but should be protected from thermal shock by
two half lapped layers of sealing tapes. A petrolatum impregnated fabric tape has traditionally been applied.
A suitable container is placed around the taped area of the cable and sealed onto the cable. Liquid nitrogen is then
carefully poured into the container with extreme care taken to avoid human contact or movement of the cable either
side of the freeze until the cable returns to normal ambient temperatures. When the freeze has taken, monitoring
the pressure drop at each end of the hydraulic circuit where the freeze is located gives an indication of which
section is leaking. A number of excavations are usually required before a leak is located, especially for cable
sheath leaks. The liquid nitrogen freeze can cause damage to the serving and the metallic cable sheath. After
removal of the freeze the serving should be checked to see if a repair is required to the outer serving. The cable
should not be disturbed until the cable has returned to a normalised temperature.

26
5.1.2 Hydraulic Bridge Technique
This method, commonly referred to as flowboards, is used on single core cables and measures the flow of fluid
through the cable, and by knowing the length and hydraulic resistance of the cable an estimation of the leak
position can be found. The cable needs to be de-energised and readings can be affected by sunshine on cable and
accessories above ground. The test requires a healthy cable and involves measuring changes in fluid flow into a
leaking cable in response to step changes of fluid pressure. The equipment required can be built into a van and
trailer. The use of a van or a van & trailer depends upon the hydraulic technique considered most suitable. The
method has been widely used on distribution cables and transmission cables, Stable temperatures and pressures
are required to achieve consistent results.
The reliability of the hydraulic bridge technique is crucially dependent upon an accurate knowledge of the cable
hydraulic parameters e.g. oil viscosity, hydraulic resistance and the static head difference of the oil section where
leak location is required. When a leak is present some of these factors are distorted and a recent development in
one utility has been to make a record of the hydraulic parameters of a circuit when they are leak free. This
information then facilitates a more accurate leak location should a leak occur. Such work is relatively expensive but
benefits accrue for future leaks as the improved accuracy results in fewer excavations and consequently less cost,
shorter outages and reduced inconvenience to the general public.
Experience has shown its reliability for leak rates greater than 4 litres/day. A typical procedure for single core leak
location is given in Annexe 3.5.
5.1.3 PFT Technology
The latest leak location technology if performed correctly can locate fluid leaks quicker and of volumes that are
often untraceable by conventional methods. The method is based on introducing a small amount Perfluorocarbon
Tracer (PFT) liquid into the fluid of the cable. When a cable leak occurs the fluid wets the subsurface soil allowing
some evaporation of the tracer, which vents to the atmosphere close to the leak, forming a plume with the highest
concentration at the vent point (see figure 15). This tracer plume is then detectable by an air sampling mobile unit
or by sampling air along the cable route (see figure 16). Once the leak is localised, further borehole sampling may
be required to pinpoint the cable leak. To be effective and quick it requires the tagging of the cable’s insulation
fluid length with a pre-determined quantity of PFT liquid before a leak occurs and using a mobile detection unit to
detect the leak. The cable remains in service while a leak is detected. Leaks can be detected to within 1m
depending on ground conditions and the local environment.
5.1.3.1Benefits and Costs of PFT
Leak location by detecting traces of PFT in the atmosphere over the cable is an innovative technology and works
for both single and three core cable systems. It utilizes cutting edge technology adapting the most sensitive
instruments constructed. Properly applied it has the potential to improve good will with government regulators and
environment agencies.
It is cost effective when compared with freezing as it saves the cost of a freeze with a minimum of two freezes per
leak location, typically four.
Figure 16 Schematic of PFT location technique
Figure 15 Sketch of a typical PFT plume
from a SCFF cable leak

27
Improved safety compared with freezing in that no freeze pits or liquid nitrogen. Manual handling of liquid nitrogen
in open and deep excavations requires special precautions as it involves working with a liquid at extremely low
temperatures (below 77K).
Minimal excavations vastly reduce the effect on the public, road owners and also reducing the exposure and
damage to other buried services. Road closures and temporary road works can be planned and agreed with the
local authority, thus benefiting all concerned.
It works for small leaks that cannot be accurately measured for hydraulic bridge technique.
Leak location is not distorted by resistance to flows in the cable system or localised heating.
A leak location using PFT does not require the cable to be out of service to locate the leak. Freezing and
flowboards need the cable de-energised. The hydraulic bridge technique also requires additional time for the cable
temperature to stabilise, as cooling transients will distort the results.
Multiple leaks can be simultaneously located with PFT technology.
For the PFT technique to work in a timely manner: specialised mobile detection equipment is required and
experienced technicians. The fluid in hydraulic sections needs to be replaced with cable fluid pre-doped with
calculated quantities of PFT.
5.1.4 Evaluation of Location Techniques for Land Circuits
Questionnaire returns showed that 63% of respondents still patrolled a leaking hydraulic section, particularly for
larger leaks. Used by 60% of respondents, freezing was still a popular method for locating leaks, although 65% of
those using freezing also used other methods. 37% of respondents used double or single ended hydraulic bridge
methods with an average minimum leak detection rate of 6 litres per day. This only applies for single core cables.
Even small leaks left unrepaired tend to dissolve away the bitumen anti-corrosion protection on the metallic sheath
accelerating corrosion failure.
If the business case for implementing can be justified the best practice is the PFT technology. With a detection rate
of around 1 litre /day, it can be used for single and three care cables, does not require hazardous practices or
sensitive calculations and the leak can be located to within a metre with the cable energised. However, pre-doping
cables and the amount of PFT used are critical to its timely success and possible effect on cable components.
5.2 Leak Location Techniques for Submarine Cables
Leakage in a submarine cable system requires immediate action, as a fluid leakage into water systems has to be
stopped as soon as possible. Leaks are either detected by loss of fluid and/or detection of fluid spill on water
surface. Due to the cable design, a hole in the sheath causing a fluid leak can be far away from the spot where the
fluid can be observed on water surface. The serving covering the metal sheath may force the fluid to travel under
the serving to an opening where the fluid can escape into the marine environment.
In case of a leakage (no electrical breakdown in the insulation) the following steps are recommended:
 Ensure that fluid pressure can be maintained for the cable by adding extra pressure tanks or connecting
mobile pumping plants to both cable ends. It is essential to provide a positive fluid flow out of the cable to
prevent water ingress.
 Search for possible leaks in the all accessories at the cable ends, such as piping, connections, tanks etc. in
order to establish that the leak is in the submarine cable itself.
 Organise a marine spread suitable for leak detection at sea, equipped with necessary equipment for cutting
cable at sea bottom and hoisting cable ends to the surface for sealing. The vessel should also be able to
receive and store a limited amount of cable that will be recovered from the sea bottom.
 While mobilizing the marine spread, perform a desktop study using existing documentation of the cable
installed searching for locations where risk for leakage appears to be higher than average. Examples are
possible discontinuities in mechanical strength such as mechanical devices or any other items assembled on

28
the cable causing a disruption to cable armour or reinforcing tape.
 Also test by the flowboard method to see if there is an indication of relative position of leak from each cable
end.
For visual inspections, an ROV or diver survey of the leaking cable should be undertaken. It is advisable to start the
search in an area where any cable fluid is seen at the water surface. It is also recommended the sea bottom in that
area is studied to see if there are any marks that could indicate a possible collision between an object and the
leaking cable that may have caused the leak, but not an electrical breakdown. If marks are found the leak is most
probably close to the spot where the fluid leaves the cable.
If none of the above methods proves successful, searching for the leak by closing the oil flow in the oil duct should
be applied. As freezing is not an option for submarine cables, cutting and sealing is the alternative. This requires
cutting the cable on the sea bottom. Where a fault (leakage spot) is known (e.g. an electrical breakdown), cut in
healthy cable at the lower side of the fault. Where the leak location is unknown, choose a position for cutting that is
most probably at the lower side of the actual leak. Before cutting, try to establish a slight gooseneck, so that the cut
end will face downwards. Control the fluid pressure and fluid flow during the cutting process and when raising the
cable end up onto the ship’s deck. After ensuring that no water is present cap and seal the cable end. Perform a
pressure test of the sealed cable to confirm that the sealed cable is not leaking. After the pressure test, the cable
end can be lowered down to the sea bottom again and left for a cable repair at a later stage.
Return to the other cable end and hoist it onto the ship’s deck. During this operation, ensure that the cut end faces
downward and there is a positive fluid flow out of the cable. Retrieve enough cable in order to be able to cut out the
leaking cable part. Cut out the defective cable then cut where the cable is healthy and seal it, ensuring that there
has been no water ingress in the cable at the cut. Then lay this end down on the sea bottom. Experienced
personnel are necessary for cutting and sealing the cable ends. The cable is now sealed and the repair operation
can be planned with a suitable repair vessel and the necessary materials (joints and spare cable).
When the leak location cannot be clearly identified, an alternative might be to recover the entire cable length to
shore. With two turntables available, the leaking cable length can be spooled from one turntable to the other, using
the freezing technique to locate the leakage. This will limit the need for cutting the cable, thereby limiting numbers
of joints required.
Chapter 6 SCFF Cable System Repairs
The aim of the repair process is to restore to full operational condition a circuit withdrawn from service following a
failure.
Prior to commencing the repair it is necessary to consider the risk of rise in potential that can occur at the point of
work and develop procedures to protect personnel. The circumstances leading to these hazardous conditions
include:
 Working on conductors at a joint position while the remote ends of the cables being jointed are earthed at
different points with one earth system subject to an increase in potential relative to the other.
 Current flows in a parallel adjacent cable inducing a voltage in the cable being worked upon.
Historical data reported from the preventive and corrective maintenance records should be used to guide the repair
process.
Critical for SCFF cables is the management of the pressurised fluid system in the event of a leak or failure so that:
 No part of the cable system falls into negative pressure,
 External contamination of the fluid system is prevented
 Any contaminants or dissolved gases generated by a failure are contained, prevented from spreading and
removed from the cable system,
 The impact of the leak or failure on its environment is minimised (by taking steps to reduce flows as much as
practical) and
 The cable system can be repaired and restored to service.

29
A cable low pressure alarm is generally one of the first indications received that something is wrong. For a failure
this is accompanied by a protection operation, the cable signal giving an indication of which hydraulic cable section
has failed. The general steps in the case of receipt of a cable alarm for various scenarios of corrective repairs are
set out in flowcharts in Annexe 2. Treat these flowcharts as a guideline only, as local circumstances and company
procedures may result in variations to the workflow.
Land-cable SCFF cable systems have the advantage that spontaneous breakdowns are rather rare due to the
pressure monitoring system on the cable. Large losses of fluid are a general indication that the cable has been
damaged and patrolling the cable route is recommended.
Some typical examples of causes of damage are:
 Fluid leakages due to intergrannular corrosion or thermal cycling of a lead sheath or corrosion of a lead
sheath’s reinforcing tapes.
 Fluid leakages due to external damage to the oversheath and metal sheath
 Leakage or rupture of lead wipes to joints.
 Rupture of fluid connecting pipework and line insulators. Small leaks in exposed accessories and pipework
may be detected by coating the fittings in whitewash or oil absorbent material and inspecting after a period of
time.
 External damage of the cable by third parties including excavation works, directional drilling and manual
drilling.
Figure 17 Removing the bitumen encapsulation from a SCFF single core straight through joint
In 2009 Cigré published technical brochures on fault statistics for HV cable systems and third party damage to
cable systems in the following brochures:
 TB 379 “Update of Service Experience of HV Underground and Submarine Cable Systems” and
 TB 398 “Third-Party Damage to Underground and Submarine Cables”
Technical Brochure 379 provides a comparison of the repair times for extruded cable systems and SCFF cable
systems. To repair a SCFF cable systems in the time frames it is necessary that all spare parts required are readily
available. If not the repair time would be much longer, typically in the order of 6 to 12 months.

30
Technical Brochure 398 provided a comparison based on a survey of the number of external failures for the
different types of cable systems and the calculated average yearly fault rate per 100km of installed cable system.
More details can be found in the technical brochures.
Leaks and repairs to SCFF cables require a reliable source of cable fluid. The cable fluid for hermetically sealed
fluid filled cable ideally requires the removal of dissolved gases before being pumped into the cable’s pressure
tanks. This is best done by a Fluid Treatment Plant that draws dissolved gases out of the fluid under vacuum
conditions. Two types of Fluid Treatment Plant are generally used for SCFF cable: the original two stage degasifier
with heating elements and the lately adopted single stage automatic high vacuum fluid treatment plant.
The two stage plant is capable of providing a continuous flow and relies on the operator to monitor the purity of fluid
delivered.
The newer design single stage automatic or manual plants include all treatment and quality testing needed, using
microprocessors to control:
 The purification of the fluid through filters
 Vacuum dehydration of a finely dispersed film to remove water and dissolved gases
 A record of the volume of cable fluid pumped.
The single stage plant processes volumes of fluid in batches at a rate of around 30 litres a minute and will not
dispense below the specified standard for the fluids condition.
While the original plants owned by 40% of respondents were satisfactory when used by experienced operators,
anyone thinking of purchasing treatment plant should consider the single stage automatic plant in service with 20%
of the utilities.
6.1 Pre-repair Works Specific to SCFF Cables
Generally pre-repair works to SCFF cables should concentrate on:
 Maintaining fluid levels in the cable.
 Locating the leak or fault.
 Restricting the flow of fluid from the cable into the environment.
 Repairing the cable leak or cutting out the failed component or section of cable. In the case of cutting out a
section of cable system the remaining healthy cable should be capped with end caps that allow the control
flow of fluid in the duct(s) and under the sheath.
For fault repairs:
 Get the fluid in the cable and pressure tanks back to acceptable levels of purity and absorbed gases. This will
require a full suite of fluid tests to ensure the cable fluid in the sections to be reconnected is acceptable
providing a benchmark for after repair tests.
 Set up gas traps on cable that is laid above the centre line of the joint. This will act as a fluid seal preventing
air from being sucked into sections cable subject to partial vacuum.
 For repairs to (and modification of) cable circuits, IR tests shall be performed prior to jointing each section of
cable, to ensure the existing cable is acceptable. Not recommended for submarine sections of a cable
system.
 Set up the fluid flows for the repairs. High fluid pressures at the jointing location may require freezing of the
cable on the high pressure side a short distance from the work location to control flows at workable levels.
Refer to flow charts in Annexe 2.
If reliable records of the cable cross section dimensions are not available, it may be necessary to take a short
sample of cable(s) for actual measurement so specific components, such as the conductor ferrule for the joint, can

31
be confirmed and if necessary made to suit. Cable samples are also recommended for laboratory testing the
insulation papers degree of polymerisation to assess the quality and ageing of the paper insulation.
6.1.1 Pre-Repair Fluid Analysis
6.1.1.1Particle Count
Check for presence of carbon and other solid particles from a failure (electrical only). Cut the cable back further
or/and flush if contamination is present in the cable end to be jointed. A fault in a SCFF cable system almost
invariably results in carbon contamination of the immediate area. Therefore, a carbon filter test of the fluid is
recommended prior to repairs being undertaken.
6.1.1.2Residual Gas Pressure (RGP) Test
The test is carried out at the repair site and gives an indication of the partial pressure of any gases, held in solution
in the cable fluid. If air is present there will be an increase in residual gas pressure near to the point of entry,
usually the repair site. As the level of residual gas pressure approaches the system hydrostatic pressure there is a
danger of bubbles forming. For this reason good practice calls for low values of residual gas pressure in a cable’s
fluid. The fluid will also be able to absorb gases generated by any future electrical stresses in the cable insulation
The ageing of insulation materials can release small quantities of gases that are held in solution. Overheating the
cable insulation and partial discharges generate larger amounts of gases. Cable faults and fluid leaks, where a
positive cable pressure cannot be maintained, risk introducing air into a cable. The presence of air is shown by the
presence of nitrogen and oxygen.
Refer to Annexe 3.3 for a method of measuring the RGP of a cable fluid sample.
The normal method of reducing high values of RGP in SCFF cables is by flushing. Replacing the fluid in the cable
duct and preferably under the annular sheath with degasified fluid. For a single core cable the most effective flush
is to force the new degasified fluid into the space under the sheath in direct contact with the insulation but this
would require blocking the central duct at the remote end that is not possible in an
in-service cable. In a three core cable the fluid duct is in contact with the insulation.
Flush towards the position of highest RGP or to sealing ends.
Flush a volume of fluid equal to the estimated volume of fluid in the cable duct. To minimise the flow of larger
particulate matter into stop joints, fluid movement in hydraulic sections between stop joints should not be greater
than one quarter the design maximum transient flow for the cable or 0.1 litre/min, whichever is less. Approximate
value of the design maximum transient oil flow can be calculated from:
Qtmax = 0.011∙W∙L
where: Qtmax = maximum transient oil flow (litre/min)
W = the cables single-phase full load loss (watt/metre)
L = length of the hydraulic section (km)
Fluid volumes are normally calculated on the volume of the fluid duct(s) of the affected hydraulic section. For long
sections this may take too long to replace and the experience of one utility has shown that provided the direction of
flushing is towards the position poor results, then flushing with at least 50 litres of new fluid should be adequate to
produce acceptable readings.
Leave for at least 48 hours and re-take RGP values. Repeat the process until RGP values are satisfactory.
When measured straight after flushing RGP values usually show an initial rapid improvement as the majority of the
dissolved gases are in the paper insulation, particularly the butt gaps and the fluid sampled comes from areas of
free flowing fluid, the majority of which is the replacing degasified fluid. Measured RGP values will slowly rise
following a flush as the dissolved gases slowly diffuse out of the paper insulation into the new fluid until uniformity
is reached.

32
If repeated flushing shows results in RGP values falling only slightly it may be uneconomical to continue prolonged
flushing. Depending on gases present other options may need to be investigated such as replacing sections of
cable, dismantling or replacing accessories, replacing pipework.
Although each utility may have its own acceptable limits, RGP values can be compared with the last sample results
for the hydraulic section or sampling from adjacent sections.
Ideally RGP levels should not be greater than twice the new circuit records. One cable maker recommends flushing
a hydraulic section with treated fluid if RGP levels exceed those given in Table 2.
System Voltage
(kV)
All Systems not including
stop joints (torr)
1 Core Cable Systems
including stop joints (torr)
3 Core Cable Systems including
stop joints (torr)
≤170 30 20 30
>170 20 10 -
Table 2 RGP levels for SCFF Cables recommended by a Cable Supplier
The condition of the pressure tanks should be checked and the RGP level (and power factor) of the tank fluid
should be within the acceptable limits for the cable. If the tanks fluid is worse than that of the cable the tanks may
be need to circulated with fresh fluid. In some cases a connection is available at the tanks base. Alternatively the
tanks can be repeatedly pumped with new cable fluid and drained until RGP readings are satisfactory.
An electrical failure in or near a feed joint or termination may contaminate the adjacent pressure tanks with
carbonised fluid. The preference should be to replace the tanks instead of conditioning the fluid but this can be
impractical. The gas cells in these tanks may also have been damaged by the sudden rise in pressure from an
electrical failure in or adjacent to a feed joint or termination. Pressure-volume testing of the tanks will show whether
cells are undamaged if the PV curve is within the original tank design limits. Failed tanks should be replaced.
6.1.1.3DGA and moisture
Checking for type of gases causing or resulting from the failure. Guidance to amount of flushing is required. The
condition of fluid from nearby tanks should also be checked.
6.1.1.4Flow and Impregnation Test
Flow: Check oil flows to show actual flows are greater than calculated values in the cable sections to be jointed.
Impregnation: Check for free gases in the hydraulic cable sections to be repaired. The impregnation coefficient
should be consistent with the value as originally installed or as specified by the cable maker. A typical value is
given in Section 6.3.1.2.
6.1.1.5Cable Fluid Tests of Tanks
Samples from tanks should undergo similar tests to those carried out on cable fluid. See Section 4.1.2 and 4.1.3
6.1.1.6Pressure Volume (P-V) Checks on the Fluid Tanks
Pressure tanks in a SCFF cable system ensure that the internal pressure of the cable system is maintained within
the design limits. It is recommended a P-V test be carried out in accordance with IEC 60141 that requires the
pressure to be reduced in 2 steps starting at the max pressure.
The tank is filled to the maximum safe pressure with degassed oil in order ensure integrity of the shell. Then the
pressure is reduced to the maximum working pressure, and then 2 steps down.
An electronic flow meter and pressure transducer are used which is set at the mid height of the tank.
Refer to Annexe 3.4 for more information.

Guide for the operation of self contained fluid filled cable systems

Guide for the operation of self contained fluid filled cable systems

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