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Prepared by HVPD Ltd. ©2009-2013 HVPD Test Experience of On-line PD Testing on Offshore Wind Farms.

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Presentation on theme: "Prepared by HVPD Ltd. ©2009-2013 HVPD Test Experience of On-line PD Testing on Offshore Wind Farms."— Presentation transcript:

1 Prepared by HVPD Ltd. © HVPD Test Experience of On-line PD Testing on Offshore Wind Farms

2 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.

3 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

4 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

5 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)

6 ‘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).

7 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 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

8 Reliability Centred Maintenance ‘Bathtub Curve’ Steady State Failure ‘Infant Mortality’ Phase End of Life ‘Wear-out’ 3 Years20-50 Years Infant Mortality Steady State Failure End of Life ‘Wear-out’ Time Failure Rate

9 Installation Lifetime Testing and Monitoring Philosophy Manufacturing Damage Mistake Repair Aging Acceptance Testing Continuous Monitoring TransportationInstallation Factory Testing Operation

10 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).

11 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 per 100 km. The annual failure rates of some of the recently installed UK offshore cable networks 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.

12 Subsea MV/HV Cable Export Cable Networks Site Overview Main Components (6): Land terminations, Land XLPE cables, Land joints, Land-subsea joints, Subsea XLPE cables (with factory joints), Offshore terminations Offshore Platform or MV/HV Substation

13 Subsea MV and HV Cable Networks – Key Components Site Overview Offshore Platform or MV/HV Substation Deep Water Wind Turbine Subsea XLPE Cable Up to 10 km Subsea XLPE Cable Up to 10 km or 3x Turbine RMU Subsea export cable to land (typically 132 kV) Main Components (6): Land terminations, Land XLPE cables, Land joints, Land-subsea joints, Subsea XLPE cables (with factory joints), Offshore terminations

14 Subsea MV and HV Cable Networks Key Components Tower Base Offshore Platform or MV/HV Substation Deep Water Wind Turbine Subsea XLPE cable Up to 10 km or 3x Turbine RMU Subsea Cable Joint J-Tubes Foundation Pile Towards substationTowards end of string J-Tubes – Protect and secure cables up height of pile / tower. Subsea Cable – XLPE, armoured, single cable for three phases with fibre- optic communication. Jointed frequently. Tower (deep water only)

15 Subsea MV and HV Cable Networks Key Components Nacelle and Transformer Generator / Power Converter (690 V) 33 kV Cables to RMU 690 V Cables 690 V – 33 kV Transformer Generator – Power is generated and converted to low voltage AC. Transformer – Fed directly from the generator and mounted either at the top or bottom of the tower. 33 kV typical voltage.

16 Subsea MV and HV Cable Networks Key Components Tower Base Ring Main Unit Subsea Cable J-Tube Subsea Cables run down J-Tubes Access Lift 33 kV Cables from Turbine Ring Main Unit – Connection point for adjacent turbine subsea cables and feed from transformer above Access Lift – For moving equipment or personnel up tower.

17 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. 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. Offshore Platform or MV/HV Substation

18 The Weak Points within the Subsea MV and HV Cable Networks PD Hazards Offshore Substation switchgear / Export Transformer Test 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

19 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!

20 Causes of Subsea MV and HV Cable Faults T hermal – incorrect design or installation of cross-bonding or earthing bonds (at cable joints) can cause ‘thermal runaway’, tracking and failure. E lectrical – incorrect installation and/or poor workmanship of the cable accessories are the No.1 cause of faults within the ‘infant mortality phase’. A mbient – the effects of mechanical wear and tear from bending caused by movement of the subsea cables with tidal and current changes in the sea. M echanical – inadequate mechanical protection of the cables for duty in the sea, particularly at the land-sea cable intersection.

21 Examples of Insulation Faults in a Medium Voltage Land-Sea Export Cables

22 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

23 Case Study 1: Typical On-line Partial Discharge (OLPD) Test of 132 kV and 33 kV Assets on 500 MW Wind Farm

24 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.

25 45 km 132 kV Export Cables are connected to Windfarm via Offshore Substation Platform

26 132 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:-

27 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:

28 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.

29 …and 33 kV GIS Switchboard using HVPD Longshot and TEV Sensors.

30 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:

31 Results EM 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 PatternLow Levels of typical Electronic Switching Noise

32 33 kV Turbine Switchgear initially screened with HVPD PDSAir™

33 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.

34 HFCT PD Sensors on 33 kV and 132 kV Cables Non-intrusive, inductively coupled Further examples

35 33 kV Turbine Switchgear cable arrangement – install HFCTs around each cable. Cables to Transformer (unarmoured) Cables to Array String (armoured)

36 HVPD Longshot with TEV sensor and HFCT. Test feeders to turbine, and both feeders along cable string

37 If testing of plant at top required, equipment is loaded into lift and hoisted. Access to nacelle by service lift or ladder climb.

38 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.

39 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.

40 Ladder climb to platform and Entrance via Transition Piece. Equipment hoisted onto platform in 20 kg hoist bags.

41 Case Study 2: Experiences Testing and PD Location for a 33 kV Offshore Wind Farm Oil & Gas Supply Cable Network

42 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

43 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 turbines Water depth – 50 metres Approx. 500 metre cable linking the two turbines Platform A 33 kV switchgear

44 Test 1 PD Test and Mapping performed with Longshot™ on Platform A’s 33kV 4x feeder switchboard.

45 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

46 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)

47 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)

48 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.

49 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

50 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.

51 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

52 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

53 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.

54 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.

55 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.

56 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.

57 Case Study 2: PD Testing, Location, Monitoring and Preventative Maintenance of a 33 kV Land-Sea Wind Farm Export Cable

58 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

59 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

60 Case Study 2: 33 kV Wind Farm Export Cables On-line PD test equipment installation at switching substation HFCT SensorsHVPD Multi™ PD Monitor

61 Case Study 2: 33 kV Wind Farm Export Cables On-line PD test results - Phase Resolved PD Patterns L1L2L3 L1L2L3 Circuit A Circuit B

62 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 L1L2L3

63 Case Study 2: 33kV Wind Farm Export Cables Circuit B: On-line PD monitoring results Circuit 2 L1L2L3 PD Activity Over One Week – high levels of hourly PD variation

64 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.

65 Case Study 2: 33 kV Wind Farm Export Cables On-line TDR Set-Up Note: PD pulses take similar propagation path

66 Case Study 2: 33 kV Wind Farm Export Cables On-line TDR Waveform Injected pulse Reflection from land- subsea joint. Reflection from grid substation Measured Return Time = 20.9µs

67 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. Direct PD pulse PD pulse reflection from land-subsea joint. Single PD pulse and reflection measured at switching substation

68 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, Switching Substation

69 Case Study 2: 33 kV Wind Farm Export Cables Joint with PD removed and replacement cable section installed Location (meters) 1,6001,4001,2001, High PD Detected on L3 PD Located Lower-level sporadic PD signals from different site after joint replacement

70 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

71 Case Study 3: Cable Failure on a 12.2 km, 6.6 kV Oil & Gas Platform Feeder Subsea Cable

72 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

73 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 % 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.

74 Case Study 3: High Cost Cable Failure on a 12.2 km, 6.6 kV Subsea Feeder Cable 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.

75 Case Study 4: TDR ‘Fingerprinting’ on the Isle of Man 90 kV, 108 km AC Interconnector Cable

76 Case Study 4: TDR Fingerprinting on IOM 90kV Interconnector Cable Background 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

77 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

78 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

79 Case Study 4: TDR Fingerprinting on 90 kV Cable Comparison of TDR Measurements to route records for joints Feature Time,  s Length, m Calculated From recordsDifference% error Start000 0 N/A Land joint % Land joint % Land/Subsea transition % ‘10 km' BICC/ Pirelli Joint % ‘60 km' Pirelli/ BICC Joint %

80 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.

81 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.

82 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).

83 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) km 20 km Offshore HSCM Master Unit

84 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

85 End of Presentation Thank you for your time Do you have any questions?


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