Prepared by HVPD Ltd. ©2009-2013 HVPD Test Experience of On-line PD Testing on Offshore Wind Farms.
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Transcript of Prepared by HVPD Ltd. ©2009-2013 HVPD Test Experience of On-line PD Testing on Offshore Wind Farms.
Prepared by HVPD Ltd.
©2009-2013
HVPD Test Experience of On-line PD Testing on Offshore Wind Farms
Introduction
• High Voltage Partial Discharge Ltd (HVPD) are experts in the growing technology field of On-line Partial Discharge (PD) test and monitoring technology for in-service high voltage cables and plant.
• We now have a significant body of experience in the On-line PD testing of offshore installations, primarily Oil and Gas, Renewables, and Sub-sea interconnector cables.
• The full scope of the medium voltage (MV) power network of offshore subsea and deep-water installations can be tested and monitored by on-line and off-line testing for PD related condition degradation.
Introduction
HVPD have over 7 years of experience in the insulation condition testing and monitoring of subsea and land-sea HV cables:
• Land-sea export cables 33 kV – 132 kV HVAC and HVDC• Offshore wind farm sub-sea MV cable arrays• Oil & gas platform MV interconnection cables
HVPD have carried out on-line condition testing of subsea cables using three main condition assessment techniques:
• On-line Partial Discharge (OLPD) testing, monitoring and mapping• Power Quality/Harmonics/Earth Screen Current monitoring• Time Domain Reflectometry (TDR) cable ‘fingerprinting’ tests
HVPD Offshore Experience
HVPD’s subsea global cable clients include:
• HVDC & HVAC Interconnector owners
• Off-shore oil and gas extraction
• Off-shore wind farm operators
Off-line and On-line PD Testing of Subsea Cables
Factory• All components tested separately along
with factory-made cable joints
At commissioning• Ensure installation integrity• Ensure no transport damage
During the cable’s service life• Baseline OLPD measurement and/or
permanent monitoring• Routine maintenance/CBM• Post Fault test and analysis (to ensure
the repairs have worked)
‘Drivers’ for Applying On-line Testing and Condition Monitoring
• Cables are essential for the effective operation of offshore installations.
• On-line condition testing and monitoring provide an early warning against HV insulation faults - to provide sufficient advance warning carry out preventative maintenance and avert unplanned outages.
• Most of these incipient insulation faults can be detected prior to potential catastrophic failure.
• State and condition monitoring technologies include using early-stage detection of PD activity, temperature hot-spots using DTS, power quality/harmonics, sheath currents and overvoltage/overcurrent events such as transient earth faults (TEF’s).
Why Test Subsea HV Cables for PD?
• Long repair time and/or replacement time.
• Repairs are expensive as additional cable lifting vessels are required for subsea cable faults.
• Unplanned outages are much more expensive to repair than scheduled preventative maintenance during planned outages (outages can cost around 10-20 times more).
• Operators need to ensure their HV cable networks have high reliability, good maintainability and maximum availability.
• Diagnostic On-line PD testing and monitoring can be done without outage, with the cable assessed under normal operating conditions
Reliability Centred Maintenance ‘Bathtub Curve’
Steady State Failure
‘Infant Mortality’ Phase
End of Life ‘Wear-out’
3 Years 20-50 Years
Infant Mortality Steady State Failure End of Life ‘Wear-out’
Time
Failu
re R
ate
Specific ‘Drivers’ for the Offshore Renewables Industry
• Offshore wind generation - the most expensive of the renewable energy options (at a total cost of £130/MWh over the 20-year asset life) c.f. Onshore wind generation - £75/MWh.
• The UK Government’s Department of Energy and Climate Change, DECC, are looking at technologies which can reduce this lifetime cost of offshore wind generation by 25% (to £100/MWh by 2020).
• More proactive, on-line condition monitoring and predictive asset management tools allow better scheduling of planned maintenance by detecting issues early and reducing expensive unplanned outages.
• These cost reductions will only be achievable through a operator company moving towards condition based management (CBM).
MV and HV Cable Failure Rate Data for Offshore Wind Farm Networks
• Typical annual failure rate for land-based, UK distribution utility MV cable networks - 2-3 per 100 km.
• The annual failure rates of some of the recently installed UK offshore cable networks - 5-8 per 100 km.
• These failures typically occur within the first 3 years of service life, typically at their weak points at cable joints and cable terminations due mainly to incorrectly installed cable accessories.
• The failures during the first 3 years of service are referred to as the ‘Infant Mortality’ Phase, as they occur within the initial stages of service life.
The Weak Points within the Subsea MV and HV Cable NetworksPD Hazards
The most likely points of failure of the subsea cables are at the cable joints and terminations as shown below.
Prior to failure, many ‘incipient’ cable insulation faults produce PD activity which can be detected and located on-line, with the cable remaining in service, to enable preventative maintenance to be made.
Land Termination(Indoor/Outdoor)
Subsea Termination(Indoor)
Land-Subsea Cable Joint
LandCable Joint
Land Cable Subsea Cable
Offshore Platform or MV/HV Substation
The Weak Points within the Subsea MV and HV Cable NetworksPD Hazards
Offshore Substation switchgear / Export
TransformerTest location
J-tube Cable Entry Points
• Main Components (6): Land terminations, Land XLPE cables, Land joints, Land-subsea joints, Subsea XLPE cables (with factory joints), Offshore terminations
Key points of potential failure of the wind farm network are as follows:
Subsea Cable Joints
Turbine Generator and Transformer
Test location
Ring Main Unit Test location
Most Likely Causes of Subsea Cable Faults
• Poor installation causing partial discharge (PD) and tracking in cable joints and terminations.
• Inadequate cable/cable accessories design, inadequate mechanical protection for duty in the sea producing sheath faults from external abrasion.
• Mechanical wear and bending caused by movement of subsea cables, this can cause mechanical movement of the cable joints.
• Due to the nature of offshore cable networks, the cost of an unplanned outage can range from anything from 10x to 100x of the failure of a similar onshore cable, depending on where the faulted cable is!
Causes of Subsea MV and HV Cable Faults
• Thermal – incorrect design or installation of cross-bonding or earthing bonds (at cable joints) can cause ‘thermal runaway’, tracking and failure.
• Electrical – incorrect installation and/or poor workmanship of the cable accessories are the No.1 cause of faults within the ‘infant mortality phase’.
• Ambient – the effects of mechanical wear and tear from bending caused
by movement of the subsea cables with tidal and current changes in the sea.
• Mechanical – inadequate mechanical protection of the cables for duty
in the sea, particularly at the land-sea cable intersection.
Examples of Insulation Faults in a Medium Voltage Land-Sea Export Cables
HVPD’s On-line PD Measurement Technology for Subsea Cables
• HVPD Longshot™- Spot-testing and location
Options for long-term condition monitoring:
• HVPD Multi™ Portable- Short-term monitoring
• HVPD Multi™ Permanent- Long-term/permanent monitoring
Case Study 1:
Typical On-line Partial Discharge (OLPD) Test of 132 kV and 33 kV Assets
on 500 MW Wind Farm
Background
• The proposal for expansion of Wind Farm submitted for completion in 2016 will increase the number of operating wind turbines from 140 to 280 generating up to 1,008 MW of power.
• The growing number of assets will require effective and non-intrusive methods of testing to ensure a reliable long-term operation, reducing costs of maintenance as well as avoiding downtimes.
45 km 132 kV Export Cables are connected to Windfarm via Offshore Substation Platform
132 kV GIS Switchgear under test using HVPD Longshot and HFCT on available cable terminations
Two main areas of test on main export offshore substation are:-
High levels (at this voltage) of wide frequency spectrum background noise were detected with HFCT sensors using HVPD Longshot™ and PDS Air™.
The noise exists in the frequency spectrum occupied by genuine Cable PD events. The results of FFT on Noise waveform are shown below:
An attempt to reduce some of the noise was made using 100 kHz and 200 kHz High Pass Filters as shown in Table 6 below.
Due to levels of noise testing with Longshot is recommended at this location going forwards.
…and 33 kV GIS Switchboard using HVPD Longshot and TEV Sensors.
Cables were not accessible for testing due to requirement for isolation.
Noise was investigated at site. Two distinctive groups of intermittent high frequency content pulses with magnitude of up to 41dB were detected within the switchboard room using TEV sensors as shown below:
ResultsEM noise was associated with audible electro-mechanical sounds in the room.
Data collected when intermittent background noise pulses disappeared:
The exact location of the noise should be pinpointed with HVPD Longshot™ unit and distributed TEV sensors. The noise source should be then isolated if possible for duration of PD testing.
If any TEV readings with PDS Air™ are to be made on the switchboard, they should be made when intermittent noise is not present i.e., the audible electro-mechanical noise is not heard.
Phase Pattern Low Levels of typical Electronic Switching Noise
Local PD
Phase of Pow er Cycle (deg)360270180900
PD
Mag
nitu
de (
dB)
15
10
5
0
-5
-10
-15
Local PD Waveform
Time us1514131211109876543210
Vol
ts (
mV
)
6420
-2-4-6
33 kV Turbine Switchgear initially screened with HVPD PDSAir™
PD Sensing Techniques and Measurement SystemsHFCTs on 33 kV feeder cables to turbine switchgear
Non-intrusive PD sensors are used for on-line PD detection in MV/HV cable networks:
• Inductive, wideband, high frequency current transformer (HFCT) sensors (1 per phase) are used to detect PD in the cables and remote plant.
• Transient earth voltage sensors (TEV) are used for detection of electromagnetic radiation from ‘local’ PD activity nearby the sensor from sources in the cable termination or switchgear.
By combining these sensors, sensitivity to different types of PD can be obtained and the measurements can also be correlated to aid diagnosis.
HFCT PD Sensors on 33 kV and 132 kV Cables Non-intrusive, inductively coupled
Further examples
33 kV Turbine Switchgear cable arrangement – install HFCTs around each cable.
Cables to Transformer (unarmoured)
Cables to Array String(armoured)
HVPD Longshot with TEV sensor and HFCT.
Test feeders to turbine, and both feeders along cable string
If testing of plant at top required, equipment is loaded into lift and hoisted.
Access to nacelle by service lift or ladder climb.
Results
Moderate levels of wide frequency spectrum background noise were detected with HFCT sensors using HVPD Longshot™ and PDS Air™.
Switchgear, Array Cables and Transformer incomer cables were tested for Local and Cable PD as well as to assess the condition of the 33 kV Transformer windings.
Due to levels of noise testing with Longshot™ is recommended to assess the insulation condition of the cables and 33kV Transformer windings. Site is suitable for cursory screening of the Switchgear panels with PDSAir™ using the handheld’s inbuilt TEV sensor.
Logistics for Personnel and Equipment
Access is often restricted due to weather conditions and boat availability. Average daily boat costs are in the region of £5k with boats limited to 12 men
including crew.
Boat transfer or Helicopter transfer to assets.
• Ladder climb to platform and Entrance via Transition Piece.
• Equipment hoisted onto platform in 20 kg hoist bags.
Case Study 2:
Experiences Testing and PD Location for a 33 kV Offshore Wind Farm Oil & Gas Supply Cable
Network
Background
• Two platforms, A and B, are separated by a subsea cable of approx. 5 km length.
• Two wind turbines supply power exclusively to satellite oil extraction platform A, 1.5 km away.
• Several tests were performed to assess condition of key circuits
Site Overview
Tests were performed at:
Platform A 33 kV Switchgear
Turbine A RMU
20 km Incomer from beach
Approx. 1.5 km subsea cable to
wind farm
Two 5 MW wind turbinesWater depth – 50 metres
Approx. 500 metre cable linking the two turbines
Platform A 33 kV switchgear1
2
2
1
Test 1
PD Test and Mapping performed with Longshot™ on Platform A’s 33kV 4x feeder switchboard.
Test 1
• PD Test and Mapping performed with Longshot™ on Platform A.
• Significant PD detected within red phase
• On-line TDR and single-ended PD mapping located incipient fault to the cable splice on the platform, 15 m out from the switchgear.
PD Detected in cable splice
Test 1
• PD Test and Mapping performed with Longshot™ on Platform A.
• Significant PD detected within red phase
• On-line TDR and single-ended PD mapping located incipient fault to the cable splice on the platform, 15 m out from the switchgear.
• Results (shown right)
Test 1
• PD Test and Mapping performed with Longshot™ on Platform A.
• Significant PD detected within red phase
• On-line TDR and single-ended PD mapping located incipient fault to the cable splice on the platform, 15 m out from the switchgear.
• Mapping data (shown right)
Test 1
• Test repeated 2 years later
• PD still present, remedial work had not been performed.
• Activity had not increased, but risk of failure still present, compromising a key transformer’s reliability.
Test 2
• PD Test and Mapping performed with Longshot™ on Platform A.
• Significant PD detected within yellow phase cable joint.
• Single-ended mapping located PD to the subsea joint, 140 m from wind farm.
PD Detected 140 m from Wind Farm
Platform A
Test 2
• PD Test and Mapping performed with Longshot™ on Platform A.
• Significant PD detected within yellow phase cable joint.
• Single-ended mapping located PD to the subsea joint, 140 m from wind farm.
Test 2
• Test repeated 2 years later, from the wind turbine A end of the cable.
• PD still present in the cable joint, remedial work had not been performed.
• Activity had increased, but risk of failure still present, again threatening power supply.
PD Detected 140 m from Wind Farm
Platform A
Test 3
• PD measured on the Yellow phase of the Turbine A feeder.
• Peak magnitudes of PD have been measured in excess of 6000 pC, with average levels of 1871 pC.
• The overall activity is moderately high, activity levels typically 30 nC/cycle have been measured.
• This PD located on the Yellow phase (L2) Wind farm Turbine A 33 kV cable joint at the 33 kV transformer.
PD Detected on 33 kV Transformer feeder cable
Platform A
Test 3
• PD measured on the Yellow phase of the Turbine A feeder.
• This PD located on the Yellow phase (L2) Wind farm Turbine A 33 kV cable joint at the 33 kV transformer.
Test 3
• PD measured on the Yellow phase of the Turbine A feeder.
• This PD located on the Yellow phase (L2) Wind farm Turbine A 33 kV cable joint at the 33 kV transformer.
Test 3
• PD measured on the Yellow phase of the Turbine A feeder.
• This PD located on the Yellow phase (L2) Wind farm Turbine A 33 kV cable joint at the 33 kV transformer.
Test 3
• Measurement of PD pulses observed on Turbine A cable feeder, showing a clear direct & indirect reflected pulse.
• Joint location confirmed
• PD located to 52 m, agreeing with visual estimates.
Case Study 2:
PD Testing, Location, Monitoring and Preventative Maintenance of a 33 kV Land-Sea
Wind Farm Export Cable
Case Study 2: 33 kV Wind Farm Export Cables Background
• Off-shore wind farm with two 33 kV export supply cable circuits
• Project carried out in follow up to a number of faults (at joints) on land cable section
• On-line PD testing, PD Mapping and short-term (1 week) monitoring was carried out to assess insulation condition of circuits
Case Study 2: 33 kV Wind Farm Export Cables
33 kV Export Cable Circuit Details• 1.7 km single core XLPE land cable• 9.6/11.5 km 3 core XLPE subsea cable
33kV Switching Substation
Offshore Wind farm
Land-Subsea Cable Joints
Land Cables 3 x single core
Offshore 33kVGIS Switchgear
33kV Grid Substation
3 core Subsea Cables
Circuit 1 Circuit 2
Case Study 2: 33 kV Wind Farm Export Cables
On-line PD test equipment installation at switching substation
HFCT Sensors HVPD Multi™ PD Monitor
Case Study 2: 33 kV Wind Farm Export Cables
On-line PD test results - Phase Resolved PD Patterns
Cable PD
Phase of Pow er Cycle (deg)360270180900
PD
Mag
nitu
de (
pC)
2,000
1,000
0
-1,000
-2,000
Cable PD
Phase of Pow er Cycle (deg)360270180900
PD
Mag
nitu
de (
pC)
0
Cable PD
Phase of Pow er Cycle (deg)360270180900
PD
Mag
nitu
de (
pC)
4,000
2,000
0
-2,000
-4,000
L1 L2 L3
L1 L2 L3
Cable PD
Phase of Pow er Cycle (deg)360270180900
PD
Mag
nitu
de (
pC)
0
Cable PD
Phase of Pow er Cycle (deg)360270180900
PD
Mag
nitu
de (
pC)
0
Cable PD
Phase of Pow er Cycle (deg)360270180900
PD
Mag
nitu
de (
pC) 10,000
5,000
0
-5,000
-10,000
Circuit A
Circuit B
Case Study 2: 33 kV Wind Farm Export Cables
Circuit A: On-line PD monitoring results
PD Activity Over One Week – Load related PD on Phase L3 Circuit 1
L1 L2 L3
Case Study 2: 33kV Wind Farm Export Cables
Circuit B: On-line PD monitoring results
Circuit 2
L1 L2 L3
PD Activity Over One Week – high levels of hourly PD variation
Case Study 2: 33 kV Wind Farm Export Cables
• High PD consistently detected on three cables.• PD Mapping (PD site location) carried out.• Initial focus on Circuit B, L3 phase (highest PD,
up to 10,000 pC).• PD Mapping
– Step 1: On-line TDR for cable return time.– Step 2: Location of measured PD pulses.
Case Study 2: 33 kV Wind Farm Export Cables
On-line TDR Set-UpNote: PD pulses take similar propagation path
DSO
Pulse Generator
Reflection
Land Cable
Land-Subsea Joint Subsea Cable
Grid Substation
Reflection
Switching Substation HFCT Sensors
Case Study 2: 33 kV Wind Farm Export Cables
On-line TDR WaveformAvailable Waveform Display
Chan 1 Curs 1 Curs 2
Time (uSec)2826242220181614121086
Cha
n 1
0.005
0
-0.005
-0.01
-0.015
Injected pulse
Reflection from land-subsea joint.Reflection from
grid substation
Measured Return Time = 20.9µs
Case Study 2: 33 kV Wind Farm Export Cables
PD Mapping• Due to reflection from land-subsea joint pulse
reflection was observed on larger PD pulses.• Possible to perform single-ended PD location on
Circuit B L3 phase, land section from on-shore substation. Chan 1 (mV)
Cur 1Cur 2Cur 3Cur 5
Waveform data in Time
Time (uSec)50454035302520151050
Vol
tage
(m
V)
6
4
2
0
-2
-4
-6
Direct PD pulse
PD pulse reflection from land-subsea joint.
Single PD pulse and reflection measured at switching substation
Case Study 2: 33 kV Wind Farm Export Cables
PDMap© Graph Showing PD location
Land-sea Transition Joint
Joint Pit 6
Location (meters)1,6001,4001,2001,0008006004002000
Switching Substation
Case Study 2: 33 kV Wind Farm Export Cables
Joint with PD removed and replacement cable section installed
Location (meters)1,6001,4001,2001,0008006004002000
High PD Detected on L3
PD Located
Lower-level sporadic PD signals from different site after joint replacement
Summary
• Pulse reflections from land-subsea joint allowed locations to be made of large PDs on land cable
• Regular testing of other cables recommended with PDMapping possible if PD level increases
• PD phase patterns indicate different types of PD• Defective joint removed on circuits A and B, L3
- A- Defects due to insufficient mastic around connector- B- Defects along XLPE surface due to bad fitting stress
control
Case Study 3:
Cable Failure on a 12.2 km, 6.6 kV Oil & Gas Platform Feeder Subsea Cable
Case Study 3: High Cost Cable Failure on a 12.2 km, 6.6 kV Subsea Feeder Cable
• The main gas production platform had a single 12.2 km, 6.6 kV interconnecting submarine cable to the satellite production platform, this being the sole supply to all of the MV motors and MV plant on the satellite.
• An earth fault occurred on the blue phase cable core which meant that the satellite gas platform lost power. Off-line, pinpointing TDR measurements were used to locate the fault and direct the cable repairs.
Main Gas Production
Platform
Satellite Production
Platform
6.6 kV Subsea Cable(12.2 km)
Fault Location - 56 metres from
Satellite Platform
Case Study 3: High Cost Cable Failure on a 12.2 km, 6.6 kV Subsea Feeder Cable
• The off-line TDR testing was conducted at both ends of the 12.2 km long cable. The ‘Return Speed’ of the cable was measured using calibration pulse injections and was found to be 92 m/microsecond
• TDR measurements from the main platform showed the location of the fault at 99.54% of the cable length out from platform (or 0.0046% of the total cable length out from the satellite platform).
• Using the total cable length and the return speed of PD pulses along the cable provided a fault location of around 56 m out from the satellite platform.
• This position on the cable coincided with the entry point of the cable to the subsea cable pipe.
Case Study 3: High Cost Cable Failure on a 12.2 km, 6.6 kV Subsea Feeder Cable
TDR Red Phase – Injection at Satellite Platform
Available Waveform Display
Chan 1 Curs 1 Curs 2
Time (uSec)20191817161514131211109876543210
Cha
n 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
Cha
n 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
Cha
n 1
1.5
1
0.5
0
-0.5
-1
-1.5
Available Waveform Display
Chan 1 Curs 1 Curs 2
Time (uSec)432
Cha
n 1
0.3
0.20.1
0-0.1-0.2
-0.3-0.4-0.5-0.6-0.7
Step response noted at 820nsec
Fault Position
• It was found that the cause of the fault had been due to the (mechanical) stress-relieving ‘bung’ at the end of the pipe becoming dislodged.
• The cable had failed due to abrasion due to mechanical movement, with respect to the fixed pipe that led to the cable failure through a sheath fault to earth.
• The cable fault was repaired with new cable joints and OLPD tests were carried out at both ends of the cable circuit after the repair to ensure that the new cable joints had been installed correctly.
• These tests showed the re-instated cable was discharge-free and thus suitable for service.
Case Study 4:
TDR ‘Fingerprinting’ on the Isle of Man 90 kV, 108 km AC Interconnector Cable
Case Study 4: TDR Fingerprinting on IOM 90kV Interconnector Cable
Background
• 108.7 km, 90 kV AC subsea cable
• 1.94 km land cable (England), 105 km of subsea cable and 1.75 km land cable (Isle of Man).
• The TDR ‘fingerprinting’ tests were made during a routine maintenance outage to establish cable return time, pulse propagation speeds and joint positions
Case Study 4: TDR Fingerprinting on 90 kV Cable
Recorded TDR trace showing return time
60 km joint
Far end
Second reflection
Injected Pulse
Measured Return Time = 1.28ms
Case Study 4: TDR Fingerprinting on 90 kV Cable
Zoom to show land joints and the land-sea transition joints
Land JointsLand-Sea
Transition Joint
Case Study 4: TDR Fingerprinting on 90 kV Cable
Comparison of TDR Measurements to route records for joints
Feature Time, ms
Length, m
Calculated From records Difference % error
Start 0 0 0 0 N/A
Land joint 1 7.19 640 623 17 2.7%
Land joint 2 14.72 1310 127040
3.1%
Land/Subsea transition 21.6 1923 1940
-17
0.9%
‘10 km' BICC/ Pirelli Joint 131 11661 11508
153
1.3%
‘60 km' Pirelli/ BICC Joint 721 64178 64300
-122
0.2%
Case Study 4: TDR Fingerprinting on 90 kV Cable
• The TDR records showed a good match to the cable route records e.g. 122 metres in 60 km (0.2%).
• TDR proved achievable even on these very long circuits (this technique was also applied successfully on the 290 km long 400 kV ‘Basslink interconnector’ from Victoria, Australia across the Bass Strait to Tasmania).
• The cable owner will use the pulse propagation speed data obtained from this test to quickly and accurately locate any fault or ‘incipient fault’ using PD Mapping.
The Future - HVPD’s Proposed Development of a
‘Holistic’ Subsea Cable Monitoring (HSCM) System
• It is proposed that the HSCM system will provide complete ‘state and condition’ monitoring for subsea high voltage cable circuits and networks.
• This will be achieved by combining a number of existing technologies into one acquisition platform.
• The system would require low power, distributed monitoring node units transmitting data via fibre-optic cable.
The Future - HVPD’s Proposed Development of a
‘Holistic’ Subsea Cable Monitoring (HSCM) System
The HSCM system will combine the following 5 technologies.
1. Distributed PD Monitoring (DPDM) module for the detection and location of early-stage PD activity.
2. Distributed Temperature Sensing (DTS) module.
3. Power Quality Monitoring (PQM) module.
4. Sheath Current Monitoring module.
5. Overvoltage/overcurrent recorder – to record transient earth faults (TEF’s).
HVPD Subsea Holistic HSCM Condition Monitoring System
Onshore HSCM Master Unit
Subsea Node units
20 km
Every 20 km
HVPD Proposed ‘Holistic’ Subsea Cable Monitoring (HSCM) System Layout
(Subject to Cable Layout)
20-40 km 20-40 km 20-40 km 20-40 km
20 km
Offshore HSCM Master Unit
Conclusions
• The Purpose of any condition monitoring to provide an advanced ‘early warning’ against ‘incipient’ HV insulation faults to enable planned, preventive maintenance to be carried out and to avert unplanned outages.
• With cross correlation of a number of cable condition and state parameters, it is then possible to provide the necessary level of detailed diagnostic data required for implementing Condition Based Management (CBM) schemes.
• The subsea HV cable owners need to consider radically better Power Quality Monitoring (PQM) and condition monitoring systems to help drive down the related high operational and maintenance costs.
• A move towards CBM is viewed as key for operating costs reduction.
• Effective CBM can only be implemented if there is detailed, real-time (continuous) diagnostic intelligence and data on both the state and condition of the HV subsea cables
End of Presentation
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