HVPD – Wind Turbine Testing Experiences 6th June 2013

Report
HVPD Test Experience of On-line PD Testing
on Offshore Wind Farms
Prepared by HVPD Ltd.
©2009-2013
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’
Infant Mortality
End of Life
‘Wear-out’
End of Life
‘Wear-out’
Failure Rate
Steady State Failure
Steady State
Failure
‘Infant Mortality’ Phase
3 Years
Time
20-50 Years
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 Networks
PD Hazards
The most likely points of failure of the subsea cables are at the cable joints
and terminations as shown below.
Offshore PlatformSubsea
or
Termination
MV/HV Substation
(Indoor)
Land Termination
(Indoor/Outdoor)
Land
Cable Joint
Land Cable
Land-Subsea
Cable Joint
Subsea Cable
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.
The Weak Points within the Subsea MV and HV Cable Networks
PD Hazards
Key points of potential failure of the wind farm network are as follows:
Offshore Substation
switchgear / Export
Transformer
Test location
Turbine Generator
and Transformer
Test location
Ring Main Unit
Test location
Subsea Cable Joints
•
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
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 longterm operation, reducing costs of maintenance as well as
avoiding downtimes.
45 km 132 kV Export Cables are connected to Windfarm via
Offshore Substation Platform
Two main areas of test on
main export offshore
substation are:-
132 kV GIS Switchgear under test
using HVPD Longshot and HFCT on
available cable terminations
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:
Results
EM noise was associated with audible electro-mechanical sounds in the room.
Data collected when intermittent background noise pulses disappeared:
Phase Pattern
Low Levels of typical Electronic Switching Noise
Local PD Waveform
Local PD
10
Volts (mV)
PD Magnitude (dB)
15
5
0
-5
-10
-15
6
4
2
0
-2
-4
-6
0
0
90
180
270
Phase of Pow er Cycle (deg)
360
1 2 3
4 5 6
7 8 9 10 11 12 13 14 15
Time us
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 electromechanical noise is not heard.
33 kV Turbine Switchgear initially screened with HVPD PDSAir™
PD Sensing Techniques and Measurement Systems
HFCTs 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
Access to nacelle by service lift or
ladder climb.
If testing of plant at top required,
equipment is loaded into lift and
hoisted.
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
1
Tests were performed at:
1
Platform A 33 kV Switchgear
2
Turbine A RMU
Platform A 33 kV
switchgear
20 km Incomer
from beach
Approx. 1.5 km
subsea cable to
wind farm
2
Two 5 MW wind turbines
Water depth – 50 metres
Approx. 500 metre cable
linking the two turbines
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 singleended 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 singleended 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
Platform A
• 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
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
Platform A
• 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
Test 3
Platform A
• 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
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 shortterm (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
Offshore Wind
farm
33kV Grid Substation
33kV Switching
Substation
Circuit 1
Circuit 2
Offshore 33kV
GIS Switchgear
Land Cables 3 x single
core
Land-Subsea
Cable Joints
3 core Subsea
Cables
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
L2
Cable PD
2,000
1,000
0
-1,000
-2,000
0 90 180 270 360
Phase of Pow er Cycle (deg)
Cable PD
PD Magnitude (pC)
PD Magnitude (pC)
0
0
90 180 270 360
Phase of Pow er Cycle (deg)
4,000
2,000
0
-2,000
-4,000
0 90 180 270 360
Phase of Pow er Cycle (deg)
L1
Circuit B
PD Magnitude (pC)
Cable PD
PD Magnitude (pC)
PD Magnitude (pC)
Cable PD
Circuit A
L3
0
0
90 180 270 360
Phase of Pow er Cycle (deg)
L2
L3
Cable PD
Cable PD
PD Magnitude (pC)
L1
0
0
90 180 270 360
Phase of Pow er Cycle (deg)
10,000
5,000
0
-5,000
-10,000
0 90 180 270 360
Phase of Pow er Cycle (deg)
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
PD Activity Over One Week – high levels of hourly PD variation
Circuit 2
L1
L2
L3
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-Up
Note: PD pulses take similar propagation path
Switching
Substation
HFCT Sensors
DSO
Pulse
Generator
Grid Substation
Land Cable
Reflection
Land-Subsea
Joint
Reflection
Subsea Cable
Case Study 2: 33 kV Wind Farm Export Cables
On-line TDR Waveform
Available Waveform Display
Injected
pulse
Measured Return Time = 20.9µs
Chan 1
0.005
0
-0.005
Reflection
from landsubsea joint.
Reflection from
grid substation
-0.01
-0.015
6
8
Chan 1
10
12
14
16
18
Time (uSec)
20
Curs 1
22
24
26
28
Curs 2
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
Waveform data in Time
substation.
6
Direct PD pulse
4
Voltage (mV)
Single PD pulse and
reflection measured
at switching
substation
Cha
Cur
Cur
Cur
Cur
2
0
PD pulse
reflection from
land-subsea joint.
-2
-4
-6
0
5
10
15
20
25 30
Time (uSec)
35
40
45
50
Case Study 2: 33 kV Wind Farm Export Cables
PDMap© Graph Showing PD location
Switching
Substation
Land-sea
Transition Joint
Joint Pit 6
0
200
400
600
800
1,000 1,200
Location (meters)
1,400
1,600
Case Study 2: 33 kV Wind Farm Export Cables
High PD Detected on L3
PD Located
0
Joint with PD
removed and
replacement cable
section installed
200
400
600 800 1,000 1,200 1,400 1,600
Location (meters)
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
Main Gas
Production
Platform
Satellite
Production
Platform
6.6 kV Subsea Cable
(12.2 km)
Fault Location 56 metres from
Satellite
Platform
•
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.
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
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.
1.5
1
Chan 1
•
0.5
0
-0.5
-1
-1.5
0
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20
Time (uSec)
TDR Yellow
– Injection
at 1Satellite Platform
Available
Waveform Display
Chan 1 Phase
Curs
Curs 2
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.
1.5
1
Chan 1
•
0.5
0
-0.5
-1
-1.5
0
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20
Time (uSec)
TDR Blue
– Injection
at Satellite
Platform
Available
Waveform Display
Chan 1Phase
Curs
1
Curs 2
1.5
Chan 1
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.
0
-0.5
Fault
Position
-1
-1.5
0
Chan 1
•
Step response noted at 820nsec
1
0.5
0.3
0.2
0.1
0
-0.1
-0.2
-0.3
-0.4
-0.5
-0.6
-0.7
1
2
3
4
Chan 1
2
Chan 1
5
6 7 8 9 10 11 12 13 14 15 16 17 18 19 20
Available Waveform
Display
Time (uSec)
Curs 1
3
Time (uSec)
Curs 1
Curs 2
4
Curs 2
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
Injected
Pulse
Measured Return Time = 1.28ms
60 km
joint
Second
reflection
Far end
Case Study 4: TDR Fingerprinting on 90 kV Cable
Zoom to show land joints and the land-sea
transition joints
Land Joints
Land-Sea
Transition Joint
Case Study 4: TDR Fingerprinting on 90 kV Cable
Comparison of TDR Measurements to route records for joints
Length, m
Feature
Start
Time, ms
Calculated
From records
Difference
% error
0
0
0
0
N/A
Land joint 1
7.19
640
623
17
2.7%
Land joint 2
14.72
1310
1270
40
3.1%
-17
Land/Subsea transition
‘10 km' BICC/ Pirelli
Joint
‘60 km' Pirelli/ BICC
Joint
21.6
1923
1940
0.9%
153
131
11661
11508
1.3%
-122
721
64178
64300
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
HVPD Proposed ‘Holistic’ Subsea Cable
Monitoring (HSCM) System Layout
(Subject to Cable Layout)
Offshore HSCM
Master Unit
20 km
20 km
20-40 km
20-40 km
Subsea Node units
Every 20 km
20-40 km
20-40 km
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
Thank you for your time
Do you have any questions?
[email protected]

similar documents