Experiences in the Condition Monitoring and Testing of Subsea

High Voltage Cables in the UK Offshore Industries

By

Lee Renforth,

Malcolm Seltzer-Grant &

Marc Foxall

HVPD Ltd Manchester, UK

2/18

Abstract

The authors present a paper detailing their experiences (over the past 5 years) from the

insulation condition monitoring of land-sea export high-voltage (HV) cables, offshore

windfarm subsea medium voltage (MV) cable arrays and oil & gas platform MV

interconnection cables. Over this period HVPD have carried out on-line condition testing of

these subsea cables using three main condition assessment techniques, namely:

1. On-line Partial Discharge (OLPD) testing, monitoring and mapping (PD site location),

2. Power Quality/Harmonics/Earth Screen Circulating Current monitoring, and,

3. Time Domain Reflectometry (TDR) cable ‘fingerprinting’ tests.

The projects reported have been carried out on a number of HV (132kV) and MV (33kV)

land-sea export cables and MV (6.6kV, 11kV and 33kV) subsea interarray and platform

interconnection cables at UK offshore windfarms and oil & gas operator platforms. These

projects were carried out further to insulation failure and subsequent earth faults on these

land-sea and subsea cables. Faults on these high criticality cables have led to unplanned

outages, downtime and lost revenue for both the windfarm and oil & gas operators. This

paper focusses on the use of two suitable techniques that can help to monitor and manage

the condition of the subsea cable networks to help reduce operating and maintenance

(O&M) costs: 1. On-Line Partial Discharge (OLPD) testing (to detect and locate pre-fault

PD and tracking activity); and 2. The use of Time Domain Reflectometery (TDR)

techniques to provide ‘fingerprint’ cable mapping measurements to quickly ‘pinpoint’ any

cable faults after they have occurred.

The causes of these subsea cable faults are numerous and include poor installation

(producing partial discharge (PD) and tracking in cable joints and terminations), inadequate

cable/cable accessories design, inadequate mechanical protection for duty in the sea

(leading to external abrasion) and mechanical wear and bending caused by movement of

subsea cables with tidal/current changes. Prior to failure, these ‘incipient’ cable insulation

faults can produce both PD activity and localised heating of the cable (depending on the

cause and location of the ‘incipient’ fault). Both of these pre-failure characteristics can be

monitored on-line with the cable remaining in-service using on-line PD and distributed

temperature sensing (DTS). Such systems can provide the network operator with a

sufficient ‘early warning’ of the incipient faults to implement condition based management

(CBM) through preventative maintenance to avoid unplanned outages.

Case studies of projects involving both on-line PD and off-line TDR measurement

techniques are also presented, including an example of PD diagnostic testing and

preventative maintenance on a 13km-long, 33kV land-sea export cable (to a UK offshore

windfarm) and the rapid TDR pinpointing of a fault on a 12km-long 6.6kV subsea cable

(between two, offshore gas platforms in the North Sea). The paper concludes with some

recommendations as to how the presently high Operation & Maintenance (O&M) costs in

the offshore renewables markets can be reduced using condition based management (CBM)

asset management techniques supported by real-time diagnostic information on the state

and condition of these critical MV and HV networks.

3/18

1. Introduction to the ‘Drivers’ for applying On-line Condition Monitoring to Land-sea and Subsea HV and MV Cables

These high value, high criticality subsea cables are clearly essential for the effective

operation of the offshore renewables and oil & gas facilities. The purpose of any on-line

condition monitoring system for such networks is to provide an advanced, ‘early warning’

against HV insulation faults in order that planned, preventative maintenance to be carried

out (during a planned maintenance outage) and to thus avert unplanned outages. It is

proposed that a large proportion of these incipient insulation faults can be detected prior to

the catastrophic failure of the insulation through an earth fault. State and condition

monitoring technologies include using early-stage detection of PD activity, power

quality/harmonic issues, circulating sheath currents and overvoltage/overcurrent events.

It should also be noted that, due to the technically challenging nature of these offshore

MV/HV cable networks, the cost of an unplanned outage as a result of an MV/HV subsea

cable fault offshore, can be anything from 10x to 100x of the cost of the same cable failure

onshore. An illustration of main MV and HV components to a medium-large (500MW)

offshore renewables generation facility are shown below in Figure 1. This shows the 33kV

inter array cables from the turbines to the offshore GIS substation and the 132kV land-sea

export cable.

Figure 1: Main MV and HV components in a UK 500MW offshore renewables facility

The subsea cables in both the offshore renewables and oil & gas industries have the

following common characteristics:

They require a long repair and/or replacement lead time.

The repairs are expensive to do as a cable lift/repair vessel is often required.

Unplanned outages are much more expensive than scheduled, preventative

maintenance during planned outages (typically by a factor of at least 10x).

Operators need to ensure the networks have high reliability, good maintainability

and maximum availability.

Off-shore Generation

Wave, Tidal or Wind

132/400kV Step-up

Transformer to Grid

Land-Sea 132kV Export

Cables (2 strings)

(132kV)

Land-Subsea 132kV Joint

with sensors

Sub-sea 132kV

Factory Joint

Off-shore 132kV GIS Substation

with Sensors and Monitor

On-shore HV Substation with

Sensors and Monitor

Interarray Cables

(33kV)

4/18

The advantages of carrying out on-line condition testing of in-service subsea cables are:

The diagnostic can be made without the need for an outage.

The cable is assessed under normal (and abnormal) operating conditions.

The data can be used to support Condition Based Maintenance (CBM) to predict

and prevent failures by the detection of ‘incipient’ cable faults.

The techniques ensure the continuous, reliable operation of the cable networks.

The specific ‘drivers’ for the adoption of condition monitoring technology and condition-

based maintenance for each of the renewables and the oil & gas industries are given below.

1.1 Specific ‘Drivers’ for the Offshore Renewables Industry

In October 2012, the UK has around 2GW of installed offshore wind generation capacity in

place, this being the largest capacity of any country in the world. Plans are in place to

increase this present capacity in the UK tenfold (up to 20GW) by 2020, including a raft of

large-size ‘Stage 3’ projects presently in the planning phase (this includes the proposed

9GW wind farm at Dogger Bank in the North Sea).

The first round of small-scale (30-100MW) offshore windfarm ‘demonstrator’ sites were

installed between 2006-2010, typically consisting of 10 to 30 Turbines, located relatively

close to shore (<15km), with 33kV interarray and land-sea export cables. The second

round of medium size, (300-500MW) offshore installations that are presently being

commissioned or built are larger and consist of 33kV interarray cable networks and 132kV

land-sea export cables with large, 132kV GIS Substation ‘collector’ hubs. A photo of a

‘Round 1’ 90MW capacity offshore windfarm is shown below in Figure 2 along with an

illustration of a wind turbine array to a 132kV ‘collector’ substation.

Figure 2: UK Offshore Windfarms

Left – ‘Round 1’ 90MW Offshore Windfarm

Right - Illustration of a wind turbine array to a 132kV ‘collector’ substation

Today, it can be noted that offshore wind generation is presently the most expensive of the

various renewable energy options, at a predicted total cost of £130/MWh over the expected

20-year lifetime of the assets. It is interesting also to note that the lowest-cost renewable

5/18

energy option at the present time is actually onshore wind generation (at around

£75/MWh). However, as there has been significant opposition in the UK to many onshore

windfarm project proposals in the past (possibly due to a “not in my backyard” viewpoint),

a decision has been made to push ahead with offshore wind as the UK’s core renewable

energy source. This move towards large-scale offshore wind generation represents an

extreme technical challenge to engineers presently designing and operating the ‘Round 1’

and ‘Round 2’ MV and HV networks, as discussed in this paper, with even greater

challenges ahead with long-length HVDC interconnection cables and HV AC/DC

conversion technology being required offshore for the larger, more remote ‘Round 3’

offshore windfarms.

From a network operation perspective, it can also be noted that these larger, ‘Round 3’

offshore windfarms will operate various types of non-linear, HV power electronic

equipment including flexible AC/DC transmission devices, new HVDC subsea

interconnections and inverter-interfaced distributed generation/storage systems. These are

already being connected onto existing networks and will only become more pronounced

into the future, requiring a substantive change in the way the networks will have to operate.

The offshore renewables industry has already stated that they now require more proactive

on-line monitoring and predictive tools to allow their asset and operations managers to

better schedule maintenance, detect issues early and reduce (or ideally look to eliminate)

unplanned outages altogether.

The importance of the offshore wind generation sector can be illustrated by the fact that the

UK has now fully committed to offshore wind energy as the main source of renewables

energy to meet targets set-out in the Kyoto Protocol and the European Plan on Climate

Drive i.e. that 20% of the EU’s energy consumption will come from renewable sources by

2020 with a corresponding reduction of greenhouse gas emissions by 20% also by 2020.

However, whilst a commitment to offshore wind has been made by the UK Government,

the Government’s own Department of Environmental and Climate Change (DECC) have

identified that a reduction in the high operating and maintenance (O&M) costs of the

offshore windfarms is essential to drive down costs, to make this renewable energy more

affordable to the nation. In fact DECC have put a target of reducing the total cost of

offshore wind generation by 25%, from the present estimated cost (using an example of a

500MW offshore windfarm) of around £130/MWh to £100/MWh, by 2020. This will be

quite an engineering and asset management challenge!

It is the opinion of the authors that, these cost reductions will only be achievable through a

radical rethink on present asset management practice, with a move towards condition-based

management (CBM) essential. Furthermore, it is also argued that for effective CBM to be

implemented, detailed, real-time (continuous) diagnostic intelligence and data on both the

state and the condition of the MV and HV subsea cable networks is also of essential

importance. Through discussions with offshore renewables clients over several years of test

projects, it has become clear that the reliability of their 33kV and 132kV land-sea export

cable links are their biggest cause for concern. This is partly due to the higher-than-

expected number of insulation faults which occurred on the Round 1 ‘Demonstrator’ wind

farm land-sea cable installations (which were installed between 2006-2010) and also due to

the ‘criticality’ of these cable links, where there are normally two cable ‘strings’/circuits).

6/18

1.2 MV and HV Cable Failure Rate Data for Offshore Wind Farm Networks

Whilst typical, average failure rate figures for land-based, UK distribution utility MV cable

networks are around 2-3 faults per 100km per annum, the failure rates of some of the

recently installed UK offshore cable networks have been much higher, at between 5-8

faults per 100km per annum in many cases. The reasons for this higher failure rate are

explained below.

‘Infant Mortality’ - from the experience of HVPD, built-up from over 5 years of on-line

testing offshore and subsea cable networks and 15 years of on-line testing of land-based

MV and HV cable networks [1], a large percentage of in-service cable faults occur within

the first 3 years of service life. It is also known that these failures typically occur at the

cable accessories (cable joints and terminations) and are normally caused as a result of

incorrect installation of these accessories (which are ‘made-up’ on site). In Reliability

Centred Maintenance (RCM) parlance, these ‘early-life’ failures are referred to as the

‘Infant Mortality Phase’ from the RCM ‘Bathtub Curve’, as they occur within the initial

stages of service life. This is illustrated below in Figure 3.

Figure 3: RCM ‘Bathtub Curve’ Showing the 3 Main Phases

Mechanical and Environmental Effects from the Sea – it is also thought that another

reason for the higher failure rate of subsea cables is due to the additional mechanical and

vibration effects of subsea cables moving with the tides and currents (which lead to

mechanical damage at joints and subsea connectors which leads to tracking and then

insulation failure from the inside of the cable). Another common cause of failures is

external abrasion of the outer jacket of the cables on the seabed (which lead to sheath faults

from the outside of the cable). These factors, in conjunction with the infant mortality issues

discussed above means that the subsea cable networks have a higher failure rate than their

land-based equivalents and thus they have a much higher ‘criticality’ as a result.

The Case Study 1 example in this paper provides an example of how on-line partial

discharge (OLPD) testing, monitoring and mapping can be used to direct a planned

maintenance intervention on a 33kV land-sea export cable to an offshore wind farm.

Failu

re R

ate

Time

Phase 2:

Steady State

Failure

Phase 3:

End of Life

‘Wear-out’

Phase 1:

Infant

Mortality

RCM ‘Bathtub Curve’

3 Years 20-50 Years

7/18

1.3 Specific Drivers for the Offshore Oil & Gas Operators

As per the offshore renewables industry, the oil & gas operators are driven by avoiding

unplanned outages and downtime which is the strongest financial driver for this industry.

Oil and gas production and processing facilities have MV networks which support critical

processes with potentially very large losses to business for unplanned outages. Studies on

offshore petrochemical production MV networks show that the main cost driver which

dominates is to avoid any unplanned outages. This is simply due the cost of an interruption

to the production process being normally much higher than the capital replacement/repair

cost of any cable/plant/machine in the network.

As a result of this, Oil & Gas operators have little difficulty in being able to justify the cost

of regular PD diagnostic measurements or complete-system, permanent PD monitoring

installations of their in-service cables, switchgear and rotating HV machines [2]. An

example of a user-screen from a permanent PD monitoring system for an Oil & Gas

Operator’s MV Network is shown below in Figure 4.

Figure 4: User-screen from PD monitoring system for Oil & Gas Operator’s MV Network

The Case Study 2 example in this paper provides an example of a cable failure (caused by

mechanical abrasion) on a 12km-long, 6.6kV feeder cable from a main gas production

platform to a satellite platform in The North Sea.

8/18

1.4 The Weak Points within the Subsea MV and HV Cable Networks

In-service cable failure experiences from the authors have shown that the most likely points

of failure of the subsea cables are at the cable accessories i.e. the cable joints and

terminations. The weak points for a land-sea export cable are illustrated below in Figure 5.

Figure 5: The ‘Weak Points’ in a MV/HV Land-Sea Export Cable

The Causes of Subsea MV and HV Cable Faults

As discussed already in this paper, the causes of these various cable insulation faults are

numerous and include the following list that form the acronym ‘TEAM’:

Thermal – ‘thermal runaway’ problems can be suffered in the cable in cases where the

design or installation of cross-bonding or earthing bonds (at cable joints) is not carried out

correctly.

Electrical - the number one cause of faults occurring within the first 3 years of service (the

‘infant mortality phase’ is incorrect installation and/or poor workmanship of the cable

accessories (which produces internal PD activity, tracking and then full insulation

breakdown in cable joints and cable terminations).

Ambient – in this case this refers to the effects mechanical wear and tear bending caused by

movement of the subsea cables with tidal and current changes in the sea. Subsea cables can

become buried underneath the seabed and then uncovered with the tide/current changes

Mechanical - for subsea cables many failures can be attributed to inadequate mechanical

protection of the cables for duty in the sea (leading to external abrasion and subsequent

failure). In can be noted that many cables in the offshore Oil & Gas industry are protected

by pipeline systems to provide mechanical protection to the cable.

Under designed Cable Components and Installations - many cases subsea cable systems

fail due to ‘under designed’ cable components which can fail due to a combination of the

above underlying ‘TEAM’ stresses.

Prior to failure, many ‘incipient’ cable insulation faults produce PD activity which can be

detected and located (‘mapped’) on-line, with the cable remaining in service, to enable the

owner to carry out preventative maintenance to avoid unplanned outages.

Land Termination

(Indoor/Outdoor)

Subsea Termination

(Indoor)

Land-Subsea

Cable JointLand

Cable Joint

Land Cable Subsea Cable

9/18

Figure 6: Some Examples of Insulation Faults in a Medium Voltage Land-Sea Export Cables

2.0 Sensing Techniques and Measurement Systems

2.1 On-line Sensor Attachment

In order to detect PD activity on-line, non-intrusive sensors are utilised. The preferred

sensors used for on-line PD detection in MV/HV cable networks are wideband, high

frequency current transformers (HFCT’s) to detect PD in the cables and switchgear and

transient earth voltage sensors (TEV) for detection of electromagnetic radiation from

‘local’ PD activity nearby the sensor from sources in the cable termination or switchgear.

By using a combination of sensors, sensitivity to different types of PD can be obtained and

the measurements from different sensors correlated to aid in the diagnosis.

2.2 HFCT Sensors Attachment

HFCT sensors may be attached onto the cable sheath or cable with the metallic sheath

brought back through. A key requirement is the cable metallic sheath has a single

connection to ground. Both positions are illustrated in the picture in Figure 7 below.

Fig. 1: HFCT sensors attached to a 3 core 11kV cable

A: Cable with metallic sheath brought back through

B: Cable sheath connection to ground

10/18

In many cases the HFCT sensors can be installed on the cables outside of the switchgear.

In air insulated switchgear/dry type cable boxes the sensor may be installed inside the plant

but an outage is required to connect safely. Some examples of this are shown in Figure 8.

In some cases the termination may be modified to make the earthing suitable. Permanent

HFCT sensors also may also be installed inside of the cable box to ease future testing.

Fig. 8: HFCT sensor attachment options inside switchgear panels

2.3 On-line Signal Measurements

In the on-line test case the cables are not isolated from the substation and thus

measurements are particularly susceptible to noise sources that are induced onto the cable

under test. For continuous noise sources such as radio broadcast signals filtering in both

hardware and software is employed. For more stochastic (random) impulsive noise

sources, signals can be rejected based on the pulse waveshape analysis [3]. Figure 9 below

shows a single, 50Hz power cycle of data captured from a 6.3kV EPR cable [4] from a

previous on-line PD test project. All of the short duration impulsive events were analysed

and classified as PD and noise using a wave shape knowledge rule set, examples of these

waveforms extracted from the power cycle trace are shown in Figure 10. The normal

distribution of the impulsive events can be seen in Figure 11 overleaf which shows clearly

that the majority of the activity is in fact from noise sources. However by processing all

events PD data can be extracted below the noise peaks.

Time (ms)

20191817161514131211109876543210

Ch

an

1 (

V)

0.015

0.01

0.005

0

-0.005

-0.01

-0.015

Fig. 9: Power cycle of data captured on 6.3kV EPR cable

Segment Waveform

Time uSec

1086420

Vo

lts (

mV

)

15

10

5

0

-5

-10

-15

Segment Waveform

Time uSec

302520151050

Vo

lts (

mV

)

15

10

5

0

-5

-10

-15

Fig. 10: PD event (left) and noise event (right)

11/18

4 6 8 10 12 14 16 18 20

1

10

100

Co

un

ts

Peak (mV)

Noise Peak

Cable PD Peak

Fig. 11: Normal distribution of impulsive event types

2.4 On-line PD Monitoring System

The on-line PD Monitoring system utilised in the test projects houses a computer, user

display, signal digitiser and 16-channel multiplexers. Multiplexing is utilised in order to

maximise the number of cables which may be tested in a single monitoring session and

keep acquisition hardware costs down. The unit has an onboard web interface which can be

accessed on the unit or remotely via LAN or a GPRS/HSDPA modem.

As with spot measurements, data is captured power cycle duration blocks. After processing

of the data, summary statistics are generated and saved. Notably the peak: magnitude of

largest pulse detected (pC for cable PD, dB/mV for local PD/noise); count: number of

pulses of each category detected and activity: integrated sum of all pulses of that category

(pC/cycle for cable PD, mV/cycle for local PD/noise).

By trending this summary data, changes in the PD activity during the monitoring session

can be observed. For example increases in PD peak indicate the defect is getting bigger and

increases in PD count indicate defects discharging more rapidly. A typical system

installation for a 33kV or 132kV land-sea export cable for is shown below in Figure 12.

Fig. 12: On-line PD monitoring system installation on a 33kV or 132kV land-sea export cable

Offshore SubstationLand Substation

12/18

2.5 A Requirement for a Combined Power Quality, System State and Condition Monitoring System

The on-line PD monitoring system and sensors described above is a good starting point for

the insulation condition monitoring of the offshore cable networks. However, feedback

from discussions with the offshore windfarm operators is that they require a more

advanced, ‘holistic’, flexible and real-time sensing and diagnostic intelligence, capable of

correctly identifying the state, condition and performance of monitored MV/HV networks.

Such an integrated system is required for the implementation of improved and more

effective condition-based management (CBM) schemes. Essentially, this requires

combining a range of power quality and conditioning monitoring, protection and control

technologies into a ‘holistic’ multi-parameter system. Realising these functionalities in an

integrated monitoring platform will allow for a confident state/condition/performance

identification and subsequent implementation of optimal and cost-effective preventive or

corrective control CBM actions and strategies.

For the offshore MV/HV networks, power quality monitoring should be integrated with the

monitoring of partial discharge (PD), cable sheath current, weather data (i.e. wind, wave or

tidal energy resources), power flows and occurrence of overvoltage/overcurrent conditions,

with the further cross-correlation of all of these condition and state parameters, in order to

allow for the early detection, faster identification and efficient resolving of faults, failures

and other problems during the operation.

The purpose of such an integrated monitoring platform is, therefore, to provide an

advanced ‘early warning’ against HV insulation faults to enable planning of preventive or

corrective maintenance to be carried out and to avert unplanned outages. From the practical

point of view, this can be achieved through the detection of early-stage PD activity, power

quality issues (e.g. harmonics and interharmonics, unbalances, dc currents, transient

disturbances, resonances, etc.), sheath currents and overvoltage/overcurrent events.

It can be noted that, due to the technically challenging nature of offshore HV networks, the

cost of an unplanned outage as a result of a fault on an HVAC or HVDC export cable are

typically 10-fold to 100-fold the cost of the same failures in onshore HV networks. The

offshore wind farm operators thus need to consider radically better Power Quality

Monitoring (PQM) and Condition-based Maintenance (CBM) monitoring systems to help

drive down the related high maintenance and operational costs.

Finally, one important advantage of integrating system state identification functionalities

and whole-system or individual-component performance and condition monitoring into one

multi-parameterised platform is that this will allow to directly incorporate assessment of

power quality and reliability levels with the analysis of insulation condition and security-

related protection and control aspects of system operation.

13/18

3.0 Case Studies

3.1 Case Study 1: PD Monitoring on 33kV Land-Sea Export Cables Following faults at joints on the land cable section of an offshore windfarm 33kV export

cable, it was decided to perform on-line partial discharge testing and short-term (1 week)

monitoring to assess the insulation condition of 2x 33kV circuits, as illustrated below in

Fig. 13. The land section was 1.7km of 3x single core, XLPE cables and the subsea cable

section was 11.1km of 1x 3-core, XLPE subsea cable.

Fig. 13: 33kV Windfarm Export Cable

All circuits were tested from the on-shore substation. With high levels (of up to 10,000pC /

10nC) of PD measured on Circuit B, L3, as shown by Fig. 14 below.

L1 L2 L3

Cable PD

Phase of Pow er Cycle (deg)

360270180900

PD

Magnitu

de (

pC

)

0

Cable PD

Phase of Pow er Cycle (deg)

360270180900

PD

Magnitu

de (

pC

)

0

Cable PD

Phase of Pow er Cycle (deg)

360270180900

PD

Magnitu

de (

pC

) 10,000

5,000

0

-5,000

-10,000

Fig. 14: 33kV Land-Sea Export Cable Circuit B - On-line PD test phase resolved graphs

An On-line Time Domain Reflectometry (TDR) measurement was carried out to measure

the land section ‘cable return time’. Due to reflection from land-subsea joint, pulse

33kV Switching

Substation

Offshore Wind

farm

Land-Subsea

Cable Joints

Land Cables 3 x single

core

Offshore 33kV

GIS Switchgear

33kV Grid Substation

3 core Subsea

Cables

Circuit 1 Circuit 2

14/18

reflections were observed from the larger PD pulses, thereby making it possible to perform

single-ended PD mapping (site location) tests on Circuit B L3 phase.

PD mapping tests showed that the PD signals were locatable to one joint ( Joint 7) in circuit

B, L3 indicating a weak spot in the cable insulation at this location, as shown in Fig.15.

Fig. 15: Circuit B – L3 – PD Mapping On-line PD test phase resolved graphs

The client subsequently replaced the joint. PD monitoring after replacement, showed the

high PD activity had ceased as shown in Figure 16 below. This prompt, preventative

maintenance action enabled this weak point to be removed thereby removing the risk of

failure from this ‘incipient’ fault. The post-repair monitoring results gave confirmation that

the discharging joint had been removed and that the cable insulation was now in a healthy

state for continuous operation and low risk of an unplanned outage.

High continuous

PD before joint

replacement

Lower-level

sporadic PD

signals after joint

replacement

Fig. 16: Example of 1-week of PD monitoring activity on a 33kV land-sea export cable

Top – PD activity before cable repair and joint replacement

Bottom – PD activity after the repair

15/18

3.2 Case Study 2: An example of the high cost of a cable failure (caused by mechanical abrasion) on a 12.2km, 6.6kV subsea feeder cable from a main gas production platform to a satellite platform in the North Sea.

The main gas production platform had a 12.2km-long, 6.6kV interconnecting submarine

cable to the satellite production platform, this feed being the sole supply to all of the MV

pump motors on the satellite, as shown below in Fig. 17. An earth fault occurred on the

blue phase cable core which meant that the satellite gas platform was out of power as there

was no emergency generation on the platform. The test requirement here was to carry out a

rapid, off-line TDR (Time-Domain Reflectometry) measurement to locate the fault and

direct the cable repairs needed to re-instate the feeder at the earliest opportunity.

Fig. 17: Gas production platform interconnecting subsea 6.6kV feeder cable

The off-line TDR testing was conducted in November 2010, at both ends of the 12.2km

long cable. Past projects have shown the TDR technique to be very effective for cable

‘fingerprinting’ and fault location on very long subsea cables of 100km+ [5]. The results

from the TDR tests on all three phases are shown in Figure 18 overleaf where the blue

phase fault can be clearly seen producing a reflection in the TDR traces. This TDR

measurement showed the location of the fault to be at 0.0046% of the total cable length (of

12.2km) out from the satellite platform. Using the total cable length provided by the

production platform owner and the return speed of PD pulses along the cable (this was

calculated using an injected calibration pulse) provided a fault location of around 56m out

from the satellite platform.

From discussions with the plant owner’s engineers, this position on the cable coincided

with the entry point to the subsea cable pipe. Investigations by divers showed that the

(mechanical) stress-relieving ‘bung’ at the end of the end the pipe had become dislodged

and that the cable had failed by abrasion with the mouth of the subsea due to mechanical

movement of the cable (due to current changes) with respect to the fixed pipe. This

movement had caused additional mechanical abrasion and stress at this point and with time

which led to the failure and the earth fault. The cable fault was repaired with new cable

joints and on-line partial discharge (OLPD) tests were then carried out at both ends of the

cable circuit after the repair and re-energisation to ensure that the new cable joints had been

installed correctly. These tests showed the re-instated cable was discharge-free.

Main Gas

Production

Platform

Satellite

Production

Platform

6.6kV Subsea Cable (12.2km)

Fault Location -

56m from Satellite

Platform

16/18

TDR Red Phase – Injection at Satellite Platform Available Waveform Display

Chan 1 Curs 1 Curs 2

Time (uSec)

20191817161514131211109876543210

Chan 1

1.5

1

0.5

0

-0.5

-1

-1.5

TDR Yellow Phase – Injection at Satellite Platform Available Waveform Display

Chan 1 Curs 1 Curs 2

Time (uSec)

20191817161514131211109876543210

Chan 1

1.5

1

0.5

0

-0.5

-1

-1.5

TDR Blue Phase – Injection at Satellite Platform Available Waveform Display

Chan 1 Curs 1 Curs 2

Time (uSec)

20191817161514131211109876543210

Chan 1

1.5

1

0.5

0

-0.5

-1

-1.5

Available Waveform Display

Chan 1 Curs 1 Curs 2

Time (uSec)

432

Chan 1

0.3

0.2

0.1

0

-0.1

-0.2

-0.3

-0.4

-0.5

-0.6

-0.7

Fig. 12: 6.6kV subsea cable TDR waveforms pulse injection at the main platform

Step response noted at 820nsec

Fault

Position

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4.0 Conclusions

This paper has set out the technical and financial drivers for the application of

condition monitoring technology in the offshore wind farm and oil and gas

industries. Such systems are of particular interest to the offshore windfarm

operators who are more likely to suffer from higher levels of faults due to early-life,

‘infant mortality’ failures with their new subsea cable installations.

The offshore windfarm operators have expressed a need for a multifunctional,

integrated state/condition/performance monitoring platform to allow for the

implementation of optimal and cost-effective preventive maintenance action. Such

an integrated system is required for the implementation of improved and more

effective condition-based management (CBM) schemes. Essentially, this requires

combining a range of power quality and conditioning monitoring, protection and

control technologies into a ‘holistic’ multi-parameter system.

For the offshore MV and HV cable networks, a ‘holistic’ monitoring approach

would require a number of complementary cable condition monitoring technologies,

including monitoring of partial discharge (PD), distributed temperature sensing

(DTS), cable sheath current, power quality monitoring (PQM), weather/tidal data,

power flow, and overvoltage/overcurrent events. With cross correlation of all of

these condition and state parameters, it will then be possible to provide the

necessary level of detailed diagnostic data required for implementing and CBM.

The purpose of such an integrated monitoring platform is to provide an advanced

‘early warning’ against ‘incipient’ HV insulation faults to enable planning of

preventive or corrective maintenance to be carried out and to avert unplanned

outages. From the practical point of view, this can be achieved through the

detection of early-stage PD activity, power quality issues (e.g. harmonics and

interharmonics, unbalances, dc currents, transient disturbances, resonances, etc.),

sheath currents and overvoltage/overcurrent events.

It can be noted that, due to the technically challenging nature of offshore HV

networks, the cost of an unplanned outage as a result of a fault on an HVAC or

HVDC export cable are typically 10-fold to 100-fold the cost of the same failures in

onshore HV networks. The offshore wind farm operators thus need to consider

radically better Power Quality Monitoring (PQM) and Condition-based

Maintenance (CBM) monitoring systems to help drive down the related high

operational and maintenance (O&M) costs.

As the O&M costs in the offshore renewables markets are presently very high, cost

reductions can only be achieved if there is a radical rethink on present asset

management practice, with a move towards condition-based management (CBM)

viewed as essential. Furthermore, it is argued that for effective CBM to be

implemented, detailed, real-time (continuous) diagnostic intelligence and data on

both the state and condition of the MV and HV subsea cable networks is necessary.

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REFERENCES

[1] R. Mackinlay and C. Walton, 2001, "Diagnostics for MV cables and switchgear as a

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