N-2NSPML (BW) RIRs 1-22 - Redacted
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NSPML Responses to Bates White Information Requests 1 c-d) 2 The Maritime Link's transfer capability and actual flow delivered at the Woodbine (NS) 3 converter station is provided in Attachment 1 for each hour of the compliance period. 4 5...
AI summary NSPML provides data on the Maritime Link's transfer capability and actual energy flow at the Woodbine converter station, including projected availability performance and underlying assumptions about energy availability and outages.
Page 1 of 1 1 Q. Please provide any studies of reliability for the post Muskrat Falls project and 2 Labrador Island Link project. 3 4 5 A. Please refer to the following attached reports: 6 7 PUB‐NLH‐212 Attachment 1: "Technical Note Labrad...
AI summary The document presents a question and answer related to reliability studies for the post-Muskrat Falls project and the Labrador Island Link project. The answer refers to two technical reports attached to PUB-NLH-212, dated October 30, 2011, and April 10, 2012, which assess the impacts of the HVdc link on the Island Interconnected System.
The addition of a 900 MW HVdc transmission line between Muskrat Falls in Labrador and Soldiers Pond on the Island portion of the province Province has raised concerns regarding the impact that such a significant change will have on the rel...
AI summary The addition of a 900 MW HVdc transmission line between Muskrat Falls and Soldiers Pond has raised concerns about its impact on the reliability of the Island Interconnected System. This technical note aims to assess the system reliability, interrelationships affecting it, and the impact of the proposed transmission line.
SYSTEM RELIABILITY INTERRELATIONSHIPS To understand the concept of system reliability and overall impact the addition of a 900 MW HVdc transmission link between Labrador and Newfoundland will have on the Island Interconnected Transmission...
AI summary The text explains the need to understand interrelationships between system planning, transmission line design, and system operations to assess how a 900 MW HVdc transmission link between Labrador and Newfoundland will impact the Island Interconnected Transmission System's reliability.
System Planning Components Least cost reliable planning of the Island Interconnected Transmission System is comprised of two main components: generation planning and transmission planning.
AI summary The planning of the Island Interconnected Transmission System involves two key components: generation planning and transmission planning, focusing on least-cost reliable system design.
Transmission Planning Transmission planning at NLH follows traditional transmission planning practices similar to, but less stringent than, that found in North American Electric Reliability Corporation (NERC) Transmission Planning Standard...
AI summary NLH's transmission planning follows deterministic practices ensuring no load loss for transmission line failures but permits under-frequency load shedding for generator outages. This deviation from NERC standards is due to the Island System's isolation and cost constraints, requiring standby generation to meet LOLH targets.
Transmission Line Design In Canada, transmission line design practices can be found in at least two CSA standards (CSA C22.3 No. 1‐06 and CAN/CSA C22.3 No. 60826:06). A brief description of each is warranted.
AI summary The document references two CSA standards (CSA C22.3 No. 1‐06 and CAN/CSA C22.3 No. 60826:06) that outline transmission line design practices in Canada, emphasizing their relevance to regulatory considerations in Nova Scotia.
Reference to Annex C indicates that: - The area surrounding the Churchill River is considered to have a loading condition of medium loading B; - The area traversed by the proposed HVdc line from Muskrat Falls to the Strait of Belle Isle is...
AI summary The text outlines loading conditions for different regions in Newfoundland and Labrador, specifying ice thickness requirements from Table 30. Medium loading B (12.5 mm), heavy loading (12.5 mm), and severe loading (19 mm) are assigned to specific geographic areas, including the Churchill River, HVdc transmission route, and the Bonavista/Avalon Peninsulas.
Section 10 of C22.3 No. 1‐06 states: The reliability‐based method should be used for supply lines greater than 70 kV phase‐to‐phase, in areas where significant amounts of meteorological data are readily available. This method may also be u...
AI summary Section 10 of C22.3 No. 1‐06 mandates the use of a reliability-based method for supply lines exceeding 70 kV phase-to-phase, contingent on availability of meteorological data. The method is also applicable for lines designed for specific climatic loads or calibrated with existing lines demonstrating long-term satisfactory performance.
CAN/CSA C22.3 No. 60826:06 International Standard CEI/IEC 60826:2003 (third edition, 2003‐10) has been adopted as CAN/CSA C22.3 No. 60826:06 Design criteria of overhead transmission lines with Canadian deviations and has been approved as a...
AI summary The Canadian standard CAN/CSA C22.3 No. 60826:06 adopts the CEI/IEC 60826:2003 international standard for overhead transmission line design, emphasizing reliability-based methods. It outlines criteria for designing lines using meteorological and strength data, with notes on applicability for specific climatic loads and design consistency.
Section 4.3 goes on to state: The objective of the design criteria described in this standard is to provide for reliable and safe lines. The reliability of lines is achieved by providing strength requirements of the line components larger...
AI summary The text outlines design criteria for transmission lines to ensure reliability against climatic loads, using return periods (e.g., 1:50, 1:500 years) to define required strength. It emphasizes higher reliability standards for critical lines and provides Canadian-specific ice thickness calculations for different return periods.
NLH Line Design At this point it is worth describing how each of the above noted standards has impacted transmission line design within the Island Interconnected System. The 230 kV transmission lines on the Avalon Peninsula are used to dis...
AI summary The document details historical transmission line design practices on the Avalon Peninsula, highlighting how ice storm failures led to upgrades. Original 230 kV lines used 25 mm ice thickness, but failures from 1970-1998 revealed insufficient design. NLH reinforced lines for a 1:50 year return period (66-75 mm ice) between 1998-2002, improving reliability.
System Operations With all equipment available and in service the Island Interconnected System operates at its most reliable level as the generation planning exercise ensures there is sufficient generation to meet the load even for loss of...
AI summary The Island Interconnected System maintains reliability through generation and transmission planning, ensuring sufficient capacity to handle single equipment losses. Forced outages and maintenance require System Operations to reconfigure the grid, scheduling maintenance to preserve backup capacity during unplanned outages.
Pole Outages CIGRE 2010 paper B4_209_2010 "A survey of the Reliability of HVdc Systems Throughout the World During 2007 – 2008" provides the latest available outage statistics for HVdc transmission systems worldwide. It must be noted that...
AI summary The text discusses reliability concerns for HVdc transmission systems, referencing CIGRE 2010 outage statistics. It highlights potential pole outages in the Labrador–Island HVdc Link, their impact on system frequency, and measures like temporary ratings (2 p.u. for 10 minutes) to prevent under-frequency load shedding. The proposed system's operational parameters and mitigation strategies are detailed.
Bipole Outages – Maritime Link In Service For loss of the bipole, NERC transmission planning standards permit planned and controlled load loss in order to maintain system stability. In the context of the Labrador – Island Link loss of the...
AI summary The document discusses the implications of a bipole outage on the Labrador-Island Link and the Maritime Link. It outlines how a special protection scheme would manage load loss and system stability, and notes that Nova Scotia must plan for the loss of 500 MW from the Maritime Link without load loss, while Newfoundland and Labrador Hydro must ensure no adverse impact on neighboring systems.
- 1: Isolated Island Alternative includes a new 170 MW CCCT in 2022 bringing 465.5 MW Thermal to 635.5 MW - 2: Hardwoods 50 MW CT to retire in 2022 - 3: For BDE WAV 230 kV transmission line transfer capability add 328 MW In essence the 201...
AI summary The text discusses the impact of transmission line failures on energy availability in the Isolated Island Scenario compared to the Interconnected Scenario. It highlights that the loss of TL202 and TL206 would result in significantly higher unsupplied energy than the loss of the Labrador – Island Link. The analysis also considers the increased generating capacity east of Bay d'Espoir and the probability of unsupplied energy in 2017.
lues for the Island Interconnected Scenario are greater than the availability value today for loss of TL202 and TL206. System Planning Department, Newfoundland and Labrador Hydro October 30, 2011 9 Assumes 230 kV transmission line construc...
AI summary The text discusses system availability comparisons for the Island Interconnected Scenario, noting higher values than current levels for loss of TL202 and TL206. It references a 230 kV transmission line design assumption and highlights potential reliability improvements from the Maritime Link during Labrador-Island Link outages between 2017-2027.
HVdc Line Design Load The final question with respect to the reliability of the Labrador – Island Link relates to the exposure of the approximately 1100 km of overhead transmission line and how to prevent failure. In the context of the los...
AI summary The reliability of the Labrador–Island Link's HVdc transmission line is questioned, focusing on design standards to prevent failure. Alternate generation and transmission planning processes are considered to ensure capacity and energy availability during repairs, with the central issue being the required construction standard for the HVdc line.
SUMMARY To date the generation planning process incorporates the forced outage rate and associated impacts of the HVdc transmission line between Labrador and the Island portion of the Province along with appropriate capacity and energy sou...
AI summary The generation planning process incorporates forced outage rates and capacity additions for the Labrador–Island HVdc transmission line, ensuring compliance with NERC reliability standards. Low-probability outage events may result in minimal unserved energy (under 0.4% annually), mitigated through load rotation rather than additional combustion turbines to minimize customer costs.
REFERENCES - 1. CSA Standard C22.3 No. 1‐06 Overhead systems published October 2006 by Canadian Standards Association - 2. National Standard of Canada CAN/CSA‐C22.3 No. 60826:06 Design criteria of overhead transmission lines published Octo...
AI summary The document lists several references, including standards and studies related to overhead transmission lines, HVDC systems, and transmission planning, all filed by Newfoundland and Labrador Hydro. These references are relevant to technical and regulatory considerations in power system planning and reliability.
LO WER CHURCHILL PROJECT Document Title: Reliability & Availability Assessment of the H HVdc Island Link Total Number of Pages Incl. Front Sheet 32+6
AI summary The document discusses the reliability and availability assessment of the HVdc Island Link project, focusing on technical aspects related to high voltage direct current transmission lines and their impact on system reliability.
Date: 10-Apr-2012 Prepared by: Peter Anderson RELIABILITY & AVAILABILITY ASSESSMENT OF THE HVDC ISLAND LINK Revision
AI summary This document, dated 10-Apr-2012, is a reliability and availability assessment of the HVDC Island Link, prepared by Peter Anderson. It focuses on evaluating the performance and reliability of the High Voltage Direct Current transmission system.
2.2 HVdc Line Transmission line outage statistics for HVdc lines are not as readily available as those for ac lines. However, the available outage data of selected projects are presented in Table 2-4 from a compilation of CIGRE statistics...
AI summary The document discusses the limited availability of transmission line outage statistics for HVdc lines compared to ac lines, referencing CIGRE statistics from the 1990s to indicate HVdc line performance. The reporting periods reflect the years for which data was available, not the total years in service.
RELIABILITY & AVAILABILITY ASSESSMENT OF THE HVDC ISLAND LINK Nalcor Doc. No.: ILK-SN-CD-8000-EL-SY-0004-01 B1 Date Page SLI Doc.: No. 505573-480A-47ER-0017 00 10-Apr-2012 8 Table 2-4: HVdc Transmission Line Outage Statistics System Length...
AI summary The document presents a reliability and availability assessment of the HVDC Island Link, including outage statistics for various HVDC transmission lines. It provides average outage rates and durations, and calculates expected reliability performance for a 1,100 km route length.
An electrode line will be provided at each converter station to connect to a remote ground electrode. These lines, under bi-pole mode, will carry only the unbalance current between the two poles of the dc line but will also be used at 150%...
AI summary The document discusses the design and reliability of electrode lines for a high-voltage direct current (HVDC) transmission system. It outlines the electrode line lengths, redundancy measures, and monitoring practices. It also provides failure rate assumptions based on CEA statistics and considers the impact of common-mode failures on system operation.
Table 4-1: Converter Reliability (Average 2007-2008) Outage FOR (%) FU(hrs/yr) F/yr Repair Time (hrs) Pole 0.265 24 1.64 13.8 Bipole 0.00025 0.02 0.24 0.13 Objective 2: To develop R&A performance indices for the HVdc transmission line from...
AI summary The document presents Table 4-1, which outlines the reliability of converters during 2007-2008, including metrics like FOR and FU. It also mentions the objective to develop R&A performance indices for the HVdc transmission line from Muskrat Falls to Soldiers Pond.
Labrador-Island Link
AI summary The Labrador-Island Link (LIL) is a proposed High Voltage Direct Current (HVDC) transmission project connecting Newfoundland and Labrador to the Island of Newfoundland, aiming to enhance grid reliability and facilitate renewable energy integration. The initiative involves Nova Scotia Power Marketing Limited (NSPML) and Newfoundland and Labrador Hydro (NLH), with regulatory considerations under the Utility and Review Board (UARB).
Market in April 2021. - » In December 2019, BPA signed an implementation agreement to start the process of joining the Western Energy Imbalance Market with April 2022 as planned membership start date. In each case, the PMAs conducted cost-...
AI summary The text discusses BPA's agreement to join the CAISO Energy Imbalance Market and PMAs' cost-benefit analyses of joining ISOs/RTOs or imbalance markets. Benefits include improved net costs, lower congestion, enhanced reliability, and efficient transmission planning, with BPA aiming to leverage its power system's flexibility in California's sub-hourly dispatch process.
4.1.2 Hydropower Power Purchase Agreements (PPAs) The median hydropower PPA price has followed a similar trend to wholesale electricity prices in recent years, except in regions with little or no geographic overlap with ISO/RTO markets (No...
AI summary The median hydropower PPA price aligns with wholesale electricity prices except in regions outside ISO/RTO markets, where prices remain higher. PPAs are standard for non-utility hydropower sales, with utilities and emerging entities as off-takers. Footnotes discuss energy imbalance markets, ISO/RTO participation, and BPA's collaboration with CAISO on flexible capacity products for transmission planning.
ed. For Canadian electricity imported by New York, New York ISO cites higher prices in Canada as well as congestion and outages in transmission links as reasons for reduced Canadian imports in 2018.64 The increasing trend in Canadian impor...
AI summary Reduced Canadian imports in 2018 were due to higher prices, congestion, and outages. Increased imports in the 2020s are expected from new PPAs, including Manitoba Hydro's agreements and Hydro-Québec's deals. Projects like Keeyask and the Romaine complex are key, though the New England Clean Energy Connect faces permitting challenges.
Assessment of Labrador Island Transmission Link (LIL) Reliability in Consideration of Climatological Loads Prepared By: Asim Haldar, Ph.D., P. Eng. Principal Investigator Haldar & Associates Inc. St. John's NL Report Prepared for Newfoundl...
AI summary This document assesses the reliability of the Labrador Island Transmission Link (LIL) under climatological load conditions. Prepared by Asim Haldar for Newfoundland and Labrador Hydro (NLH) on March 10, 2021, it evaluates how climatic factors impact transmission reliability.
1.2 Labrador Island Transmission Line (LIL) System Configuration The ± 350 kV HVdc line route extends from the Muskrat Falls generating station in Labrador to the Strait of Belle Isle, before passing under the Strait of Belle Isle via an u...
AI summary The Labrador Island Transmission Line (LIL) is a ±350 kV HVdc system connecting Muskrat Falls to Newfoundland, passing through regions prone to severe icing. It includes key components like converter stations and integrates with NLH's AC network, spanning 1093 km with 388 km in Labrador and 705 km in Newfoundland.
to validate the design for an increased return period based on ice and wind loads; however, the clearances due to increased sag and due to swing angles need to be addressed (serviceability criteria)". Mr. Alteen's submission from Newfoundl...
AI summary The text addresses the need to validate design for increased return periods due to ice and wind loads, emphasizing clearances for sag and swing angles. Mr. Alteen's submission highlights reliability concerns for the Labrador Island Transmission Link (LIL) and the Isthmus zone's critical corridor post-Holyrood decommissioning, noting Nalcor's oversight in considering line length in reliability assessments.
1.4 Return Period Concept in Selecting Overhead Line Design Loads One of the major concerns that has been raised during the review and information gathering process is that LIL did not strictly meet the CSA C 22.3 60826-06 standard and tha...
AI summary The text discusses concerns that the Labrador Island Transmission Link (LIL) did not meet CSA C 22.3 60826-06 standards, leading to underestimated design loads. Nalcor responded by citing a 50-year return period, operational experience of NLH, and Hydro's risk assessments. The CSA standard requires higher reliability (Level III) unless justified by studies. Methodologies by Haldar (1990s–2020s) are cited for cost-risk optimization in line design.
1.5 Objective of this Study The primary objective of this report is to assess the structural reliability of the LIL considering two predominant types of icing to which the line is exposed. These are (a) glaze icing due to freezing precipit...
AI summary The study assesses the structural reliability of the Labrador Island Transmission Link (LIL) against glaze and rime icing, using CSA 60826-2010 standards. It evaluates failure rates under various scenarios, conducts a sensitivity analysis, and benchmarks against operational data to inform system planning reliability.
1.9 Layout of the Report Section 1 provides a brief historical background of this project and the objective and the primary focus of this study. This section also presents a high-level chronological overview on the Nalcor's submissions to...
AI summary The report outlines a structured analysis of the Labrador Island Transmission Link (LIL) design, focusing on reliability, system planning, and CSA standard compliance. It emphasizes the impact of line length on reliability for a long HVdc radial line, critiques CSA 60826-2010, and benchmarks against NLH's operational experience. Key themes include reliability-based design, transmission planning, and system reliability considerations.
2.0 Basic System Design Concept In overhead line design, reliability is determined by assigning a fixed return period to extreme climatic events, such as wind, ice, and combined wind and ice loads. This implies some expected failure rate d...
AI summary The section discusses reliability and security in power system design, emphasizing overhead line reliability through return periods for extreme weather and structural security measures like containment structures. It outlines BEPS planning criteria (N-1, N-2, N-1-1) and contrasts reliability (probabilistic) with security (deterministic) in power networks versus structural design.
u)$ rates, which are directly related to the design return period of the climatic loads and the duration of the repair respectively (hours, days etc. after a failure) should the line fail. The repair duration is normally linked to repair r...
AI summary The text discusses the relationship between design return periods, repair duration, and system reliability, emphasizing the need for quantitative linkage between reliability and security parameters. It highlights the critical role of the LIL in the power system and the severe consequences of its failure.
3.4 Limit States of Transmission Lines –Examples
AI summary The section provides examples of limit states for transmission lines, focusing on technical criteria and safety margins relevant to power system reliability and infrastructure design standards.
Churchill Falls 735kV Lines In the December 27, 1995 storm, several line trips and subsequent clearing were first experienced on line 7051 and, on the following day, lines 7052 and 7053 experienced outages. The heavy icing caused a ground...
AI summary A 1995 storm caused line outages on Churchill Falls 735kV Lines due to heavy icing, leading to a ground wire detachment from a tower via broken U-bolts. The 1997 failure, initially classified as DLS, resulted in line decommissioning after OHGW removal.
4.2.1 Rime Icing Forecast along LIL Route in Zones 2, 5, and 7 (EFLA, 2021) CSA 60826-10 does not provide any rime ice map as it does for glaze icing. EFLA-KVT was retained by NLH to develop the rime icing loads (in-cloud icing loads) on t...
AI summary The study by EFLA-KVT for NLH on rime icing along the LIL route in Zones 2, 5, and 7 used monitoring stations, hindcast data, and the Makkonnen model. The model overpredicted icing compared to test data, highlighting the need for accurate forecasting in transmission planning.
5.2 LIL Reliability – System Approach Very long lines are often divided into several segments (several weather zones) because of different loading criteria for various weather zones. Lines below 200km in a severe climatic zone may be desig...
AI summary The section discusses modeling the reliability of the Labrador Island Transmission Link (LIL) by segmenting long transmission lines into weather zones, calculating segment failure probabilities, and applying reliability formulas (e.g., equation 5.5) to assess system-wide reliability under various loading conditions like wind and ice.
5.3 Regional Grouping Considering Multiple Segments Under Various Weather Zones In a technical note, Thomas (2011) outlined the justification for selecting the 50-year return period for LIL and showed that the higher return period could no...
AI summary The text discusses the design and reliability considerations for the Labrador Island Transmission Link (LIL), emphasizing the 50-year return period for its design. It highlights concerns about forced outages in HVDC lines due to length, environmental factors, and repair times, referencing Thomas (2011) and the CIGRE report. The author stresses the need to adjust design loads based on line length to maintain reliability.
5.3.1 Determination of Reliability for LIL (Assumptions for Various Levels) - Level 1 (No regional grouping, full correlation along the entire line length and among elements, no distinction made between different exposure levels, e.g., ici...
AI summary The document outlines four levels of reliability assessment for the Labrador Island Transmission Link (LIL), varying by regional grouping, correlation assumptions, and exposure distinctions (e.g., icing types). Each level corresponds to specific base cases and scenarios, with figures illustrating regional groupings and reliability outcomes.
7.4 Glaze Icing on Avalon Peninsula – (Avalon Study) This section reviews the Avalon glaze ice load that was used during LIL design. Question has been raised in several RFI's why Nalcor did not follow the internal NLH study recommendation...
AI summary This section examines the Avalon Peninsula glaze ice load assumptions used in LIL design, noting discrepancies between NLH's 1996 study (75mm for 50-year return period) and the Avalon study's data. The Avalon study used a 28mm conductor diameter and recommends periodic data updates with new meteorological and operational information.
7.6 Rime Icing on LRM – (EFLA & KVT Study, Full Effects of Topography and Terrain Characteristics) Several studies have been presented as part of this LIL project to assess rime ice loads on the LIL. As reported in Section 4, the recent st...
AI summary The section discusses studies on rime ice loads for the Labrador Island Transmission Link (LIL) using the WRF model, noting the use of USGS landuse data but omission of topographic effects like escarpments. The author recommends a separate study for glaze icing.
8.1 NLH System at a High Level Figure 8.1 presents the Newfoundland and Labrador Hydro bulk power system at the 230-kV level. The transmission line system connects the major hydraulic generating stations. The basic 230 kV transmission line...
AI summary The document describes the Newfoundland and Labrador Hydro (NLH) bulk power system at the 230-kV level, detailing transmission lines connecting major generating stations like Bay D'Espoir and hydroelectric plants (Cat Arm, Hinds Lake). It outlines parallel line configurations, load centers, and infrastructure distinctions (e.g., steel vs. wood pole lines) in both eastern and western regions, referencing figures for visual context.
8.3.3 Northern Peninsula (TL 247 & 248, Hannah et al.) Lines designed and operating at present on the Northern Peninsula have a large dispersion in ice loadings, varying from 0.3 to 4 inches of radial ice. This corresponds to 13.0 to 102mm...
AI summary The Northern Peninsula power lines (TL 247 & 248) exhibit significant ice loading variations (0.3–4 inches radial ice, 1.5–30kg/m load) across 69kV–230kV systems. The Deer Lake–Cat Arm line, designed for 4-inch ice loads (30kg/m), includes a NW-SE segment critical for NE wind-driven freezing precipitation, justifying its higher design standard.
8.5 Benchmarking of Transmission Lines
AI summary This section discusses the benchmarking of transmission lines, focusing on methods and standards for evaluating their performance and reliability. Key considerations include comparative analysis with industry benchmarks and regulatory requirements.
8.6 LIL Outage/Failure Rate – Comparison of Results with Published Data A transmission line outage can be caused by (1) electrical fault and (2) permanent faults caused by mechanical damage/failure of line components. Electrical faults are...
AI summary The section discusses LIL outage/failure rates, comparing them with published data. It explains causes of outages, differentiates between electrical and mechanical faults, mentions statistical data from studies, and notes the lack of guidance for mechanical failures. The permanent failure rate is estimated at 0.03/year/100km.
9.1 Summary This report assesses the impact of two types of icing on the structural reliability (and probability of failure) of the LIL HVdc line. The two types of icing are (a) glaze icing due to freezing precipitation and (b) rime icing...
AI summary This report evaluates the structural reliability of the LIL HVdc line under glaze and rime icing scenarios, validating its design against CSA 60826-2010. It calculates failure rates (λ) and repair rates (μ) for system planning, benchmarks LIL performance against utility outage data, and discusses Hydro's operational experience with transmission lines.
ice loads for the LITL HVDC overhead line, Prepared for Newfoundland and Labrador Hydro • KVT-EFLA 2020 Extreme wind data for Newfoundland and Labrador, Prepared for Newfoundland and Labrador Hydro • Ghannoum, E 2016 Reliability Assessment...
AI summary The document compiles references on ice and snow load studies for HVDC transmission lines, including the Labrador Island Link and LCP project. It cites research by engineers and organizations like Newfoundland and Labrador Hydro, focusing on reliability, design standards, and extreme weather impacts on infrastructure.
4.3 High-Power Testing - As previously reported in Hydro's final 2025–2026 Winter Readiness Report, 12 the high-power test of the - LIL has been postponed because of Hydro's prioritization of reliable service to customers during the - wint...
AI summary The high-power test of the Labrador-Island Link (LIL) has been postponed until Q1 2026 to prioritize winter service reliability and reservoir management. Prerequisites include system conditions, coordination with neighbors, and risk mitigation.
LIL Strengthening Overview January 2026
AI summary The document provides an overview of efforts to strengthen the Labrador-Island Link (LIL) in January 2026, focusing on enhancing transmission infrastructure and reliability for the power grid. The context highlights technical and regulatory considerations for interregional energy connectivity.
1.0 Introduction - The Labrador-Island Link ("LIL") is an important transmission line for the provincial energy grid due to its - power carrying capacity that is used to deliver a large portion of the winter peak energy and demand to - the...
AI summary The Labrador-Island Link (LIL) is critical to Nova Scotia's energy grid, with past failures attributed to icing and unbalanced loading. Newfoundland and Labrador Hydro conducted investigations, leading to a 2026–2028 capital project to reinforce the line, including tower modifications, damping systems, and electrode conductor relocations to enhance reliability.
1.0 INTRODUCTION NL Hydro has experienced several performance issues for the Labrador-Island Transmission Link, +/- 350 kV HVDC. Performance issues include the following: - · Electrode conductor failure - Electrode cross-arm structural fai...
AI summary NL Hydro's Labrador-Island Transmission Link (LIL) faces technical issues including electrode conductor failures and tower buckling. The memo proposes mid-span structures to reduce tower loading and address weight span imbalances, enhancing transmission line performance.
3.5 GALLOPING ELLIPSE CLEARANCES The galloping ellipse method used for the transmission line design is described in the 350 kV HVdc LINE DESIGN CRITERIA, document number ILK-SN-CD-6200-TL-DC-0001-01, Appendix A. No results or reporting was...
AI summary The document discusses the galloping ellipse method for 350 kV HVdc transmission line design, noting the lack of existing evaluation data. It analyzes the impact of new attachment geometry and insulator lengths on electrode-pole clearance, focusing on the longest span (496 m) between towers 258 and 259. The study concludes that the new cross-arm and insulator design provide adequate separation.
LIL Engineering Study – Calculations for OPGW Peak Reinforcement Newfoundland and Labrador Hydro Report No. ILK-TT-CD-6200-TL-H15-0002-01 TT Document Number: 705-2579500100-REP-G0003-00 July 21, 2025
AI summary This document is a report from Newfoundland and Labrador Hydro titled 'LIL Engineering Study – Calculations for OPGW Peak Reinforcement,' dated July 21, 2025. It outlines engineering calculations related to reinforcing the Optical Ground Wire (OPGW) for the Labrador-Island Link (LIL).
N-4NSPML (IG) RIRs 1-26 - Redacted
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third party in connection with the March–April 2024 29 icing event, including any findings comparing actual weather conditions to design criteria and 30 any recommendations for design upgrades. 1 2 3 A. a) Line L3501/2 is the 350 kV HVdc o...
AI summary The third party inquired about the March–April 2024 icing event's impact on the 350 kV HVdc transmission line L3501/2, including design criteria comparisons and upgrade recommendations. The line spans 1,100 km through three meteorological zones, with 19 loading zones and 11 tower types. Damage occurred to specific towers during the incident.
1.0 Introduction - The Labrador-Island Link ("LIL") is an important transmission line for the provincial energy grid due to its - power carrying capacity that is used to deliver a large portion of the winter peak energy and demand to - the...
AI summary The Labrador-Island Link (LIL) transmission line has experienced ten failures over five years due to icing-related overloading. Investigations identified root causes and led to a 2026–2028 capital project to strengthen the line through infrastructure upgrades, including ice monitoring, tower modifications, and electrode conductor reconfiguration to enhance reliability and reduce failure risks.
1.0 INTRODUCTION NL Hydro has experienced several performance issues for the Labrador-Island Transmission Link, +/- 350 kV HVDC. Performance issues include the following: - · Electrode conductor failure - Electrode cross-arm structural fai...
AI summary NL Hydro's Labrador-Island Transmission Link (LIL) faces multiple technical issues, including electrode conductor failures and structural weaknesses. The memo proposes mid-span structures to reduce tower loading and improve weight span balance.
3.2 $4-576 (2543) Tower position S4-576 (2543) was chosen due to long weight spans on both sides of the tower, as shown in Table 4. To avoid weight spans imbalance, it was decided to add two mid-span structures; one in the back span (BS) a...
AI summary Tower position S4-576 (2543) was selected due to long weight spans on both sides, necessitating mid-span structures to balance loads. Long spans create high vertical loads during ice events, leading to local peak failures despite no electrodes being present on the tower.
3.5 GALLOPING ELLIPSE CLEARANCES The galloping ellipse method used for the transmission line design is described in the 350 kV HVdc LINE DESIGN CRITERIA, document number ILK-SN-CD-6200-TL-DC-0001-01, Appendix A. No results or reporting was...
AI summary The document discusses the galloping ellipse clearance method for a 350 kV HVdc transmission line, evaluating the impact of electrode insulator string lengthening on electrode and pole ellipse proximity. The longest span (496 m) was analyzed, and results confirm adequate separation with the new cross-arm and insulator design, as detailed in Appendix A.
Appendix D LIL Engineering Study – Calculations for OPGW Peak Reinforcement
AI summary Appendix D details an engineering study focused on calculating reinforcements for the Optical Ground Wire (OPGW) on the Labrador-Island Link (LIL), addressing infrastructure needs for peak load capacity.
LIL Engineering Study Calculations for OPGW Reinforcement Newfoundland and Labrador Hydro
AI summary The document presents engineering study calculations for OPGW reinforcement as part of the Labrador-Island Link (LIL) project by Newfoundland and Labrador Hydro (NLH). It focuses on infrastructure planning and transmission planning for power line reinforcement.
er types (A1, A2, A3, A4, B1, B2, C1, C2, D1, D2, and E1) were designed to meet the loading requirements, which consist of a specified wind load, ice load, and combination of both applied to the line. There have been a number of failures t...
AI summary The document details transmission line failures in central Labrador due to ice events between 2021 and 2022. Electrode crossarms and conductors were damaged by unbalanced ice loads exceeding design specifications (50 mm radial glaze ice). Ice loads measured 54–72 mm (0.88–0.9 g/cm³ density) during events, leading to failures on A1-type towers with electrode conductors.
Purpose - Considering the importance of L3501/2 to the provincial energy grid and the need to understand the - line's performance, a detailed failure investigation was completed to determine the root cause of the - failures and to conclude...
AI summary The document outlines a failure investigation of the L3501/2 350 kV HVdc transmission line to determine root causes and preventive measures. Key components include failure analysis, weather impacts, construction quality, maintenance, material testing, and load analysis.
Weather Information - There were observations of significant icing on the lines on March 30th , as shown in [Figure 10.](#page-158-2) - Observations at site estimated the ice thickness on the conductor to be approximately 120–140 mm of - r...
AI summary The document details ice accumulation observations on a transmission line, including 120–140 mm radial ice thickness on conductors and 100–125 mm from an OPGW sample. Weather data from Blanc Sablon indicates colder temperatures and higher precipitation near the damaged structures compared to the weather station, with 55–60 mm precipitation recorded around the failure time.
Summary and Conclusions - The main root cause of the damage to the tower electrode crossarms, the OPGW tower peaks, and the - electrode conductor was an overload failure due to ice loads exceeding the design for this section of the - line....
AI summary The damage to the transmission line tower electrode crossarms, OPGW tower peaks, and electrode conductor was caused by ice loads exceeding design specifications. Ice loads of 100–125 mm with lower density than the design load of 50 mm (0.9 g/cm³) led to overload failure. Modeling suggests unbalanced ice loads and temperatures near zero contributed to the damage. Material testing confirmed ductile failure from overloading and wind-induced galloping.
- To gain a better understanding of the ice loads experienced by the line, monitoring of the line is - required. We currently have a test span installed near str. 1225 with plans to install another test span in - 2025. The test span consis...
AI summary The document outlines efforts to monitor ice loads on a transmission line, including test spans and planned 2025 installations. Damage from icing at str. 1225 disrupted data collection, but repairs are scheduled for 2025. Tangent towers are designed for specific unbalanced ice loads, but a 2024–2025 project recommends reevaluating designs using Haldar reports, CSA standards, and operational data to enhance reliability.
Executive summary Wayland Engineering Ltd. was asked by Newfoundland and Labrador Hydro (NL Hydro) to conduct an investigation for two electrical conductors (EL-1 and EL-2) removed from suspension Tower #1225. The conductors routed electri...
AI summary Wayland Engineering Ltd. investigated failures in conductors EL-1 and EL-2 at Tower #1225, attributing the ductile limit load fracture to ice accumulation and wind forces. Steel core migration and wind-induced galloping were identified as contributing factors, with radiographic imaging recommended for future inspections.
on and wind velocities reported suggests that the line was operating in excess of the design criteria both on the day prior to and during the day of the failures sustained by conductors EL-1 and EL-2. Figure 1-1 is a map showing the genera...
AI summary The text details conductor failures (EL-1 and EL-2) on a 350 kV HVdc line, attributing them to wind velocities exceeding design criteria and asymmetric ice accumulation causing galloping vibrations. NL Hydro reported prior observations of galloping near Tower #1225, with conductors installed in 2017 and subjected to seven years of service.
PARTIALLY CONFIDENTIAL 1 Of the $15.3 million in holdback from July 2024 to September 2025, $1.1 million was 2 related to the outage caused by icing in January 2025 and the remainder of the $15.3 million 3 was attributable to planned outag...
AI summary The document outlines a $15.3 million holdback from July 2024 to September 2025, attributed to an icing-related outage and planned outages. NSPML did not schedule these outages, as they were for NLH's assets. Coordination was managed by operations teams, with holdback considerations deemed inappropriate due to complexity. References to SBA IR-8 and IG IR-07 are provided.
Article 1. Definitions Adverse System Impact shall mean the negative effects due to technical or operational limits on conductors or equipment being exceeded that may compromise the safety and reliability of the electric system. Affected S...
AI summary Article 1 defines key terms for regulatory proceedings, including 'Adverse System Impact,' 'Affected System,' 'Affiliate,' 'Ancillary Services,' and 'Applicable Reliability Standards.' These definitions establish foundational terminology for evaluating interconnection impacts, system reliability, and compliance with technical and legal requirements.
4.1.1 Energy Resource Interconnection Service. - 4.1.1.1 The Product. Energy Resource Interconnection Service allows Interconnection Customer to connect the Large Generating Facility to the Transmission System and be eligible to deliver th...
AI summary The Energy Resource Interconnection Service enables connecting a Large Generating Facility to the Transmission System, with the Transmission Provider constructing necessary facilities. Eligibility for market bids depends on regions like PJM, ISO-NE, NYISO, and transmission delivery service depends on existing capacity or additional services.
4.1.2.2 Transmission Delivery Service Implications. Network Resource Interconnection Service allows Interconnection Customer's Large Generating Facility to be designated by any Network Customer under the Tariff on Transmission Provider's T...
AI summary Network Resource Interconnection Service enables Large Generating Facilities to be designated as Network Resources, allowing energy delivery under the same terms as existing resources. Ancillary Services require technical studies, and cost responsibilities for upgrades align with FERC guidelines. Undesignated facilities are not obligated to provide Ancillary Services unless requirements apply broadly.
nstructed under this option are only required for Interconnection Customers in a single Cluster and (2) all impacted Interconnection Customers execute and provide to Transmission Provider an agreement regarding responsibilities and payment...
AI summary The text outlines requirements for Interconnection Customers under a specific option, mandating agreements with the Transmission Provider regarding responsibilities and payments for constructing Interconnection Facilities and Stand Alone Network Upgrades. Customers in a single Cluster must collaborate, with Appendix A identifying upgrades. Customers may not construct other Network Upgrades under this option.
5.11 Transmission Provider's Interconnection Facilities Construction. Transmission Provider's Interconnection Facilities shall be designed and constructed in accordance with Good Utility Practice. Upon request, within one hundred twenty (1...
AI summary The section outlines the Transmission Provider's obligations to design and construct interconnection facilities per Good Utility Practice, deliver as-built documents within 120 days of Commercial Operation Date, and obtain control upon completion. It emphasizes compliance with standards and timely delivery of required documentation.
ctivated and maintained under, but not be limited to, the following events: system paralleling or separation, scheduled and unscheduled shutdowns, equipment clearances, and hourly and daily load data. 8.2 Remote Terminal Unit. Prior to the...
AI summary Article 8.2 mandates the installation of a Remote Terminal Unit (RTU) or equivalent equipment by the Interconnection Customer or Transmission Provider to collect and telemeter real-time power data via dedicated circuits. The Transmission Provider specifies communication protocols, and both parties must promptly address equipment errors or malfunctions.
9.7.1 Outages. - 9.7.1.1 Outage Authority and Coordination. Each Party may in accordance with Good Utility Practice in coordination with the other Party remove from service any of its respective Interconnection Facilities or Network Upgrad...
AI summary Section 9.7.1 outlines procedures for outage coordination between Transmission Provider and Interconnection Customer. Parties may remove facilities from service for maintenance, requiring mutual agreement absent emergencies. Transmission Provider must post outages on OASIS, while Interconnection Customer must submit 24-month maintenance schedules, subject to rescheduling for system reliability.
- 9.7.4.4 Each Party's protective relay design shall incorporate the necessary test switches to perform the tests required in Article 6. The required test switches will be placed such that they allow operation of lockout relays while preve...
AI summary The text outlines requirements for protective relay design, testing, and maintenance of system protection facilities in compliance with Good Utility Practice. Key provisions include test switch placement, calibration tests, functional trip tests, and coordination of fault removal with transmission system protection. The Interconnection Customer must install protective equipment to isolate faults from large generating facilities.
Article 11. Performance Obligation - 11.1 Interconnection Customer Interconnection Facilities. Interconnection Customer shall design, procure, construct, install, own and/or control Interconnection Customer Interconnection Facilities descr...
AI summary Article 11 outlines obligations for interconnection facilities, network upgrades, and distribution upgrades. The Interconnection Customer bears sole responsibility for designing, constructing, and funding Interconnection Customer Interconnection Facilities and Distribution Upgrades. Transmission Provider/Owner handles Network Upgrades, with optional funding by the Interconnection Customer.
Upgrades through the date on which Interconnection Customer receives a repayment of such payment pursuant to this subparagraph. Interconnection Customer may assign such repayment rights to any person. Notwithstanding the foregoing, Interco...
AI summary The text outlines repayment terms for network upgrades, allowing Interconnection Customer to assign repayment rights. It permits alternative payment schedules if mutually agreed, with requirements for reimbursement within 20 years of the Commercial Operation Date. Reimbursement is also mandated if a generating facility later uses the upgrades, contingent on identifying the responsible entity.
Article 29. Joint Operating Committee - 29.1 Joint Operating Committee. Except in the case of ISOs and RTOs, Transmission Provider shall constitute a Joint Operating Committee to coordinate operating and technical considerations of Interco...
AI summary Article 29 establishes a Joint Operating Committee to coordinate operating and technical considerations for interconnection services. The committee, formed by Transmission Provider and Interconnection Customer, must meet annually, review data requirements, equipment standards, and maintenance schedules, and ensure information sharing to align with LGIA provisions.
Interconnection Details
AI summary The document section titled 'Interconnection Details' outlines technical and procedural aspects of connecting energy systems, referencing entities like NSPML and NSUARB, and discussing standards, transmission lines, and interconnection agreements relevant to Nova Scotia's energy infrastructure.
iii. Supervisory Control and Data Acquisition (SCADA) Capability The wind plant shall provide SCADA capability to transmit data and receive instructions from Transmission Provider to protect system reliability. Transmission Provider and th...
AI summary The wind plant must provide SCADA capability to transmit data and receive instructions from the Transmission Provider to ensure system reliability. Essential SCADA information is determined by the Transmission Provider and the wind plant's Interconnection Customer, considering factors like plant size, location, and reliability impact.
s development, more submarine power cable projects are economically viable, or even possible. New applications for submarine power cables appear while known applications are pursued on a larger scale. Submarine power cables draw the attent...
AI summary The text highlights growing interest in submarine power cables driven by offshore wind projects, new applications, and involvement from diverse stakeholders including engineers, investors, regulators, and environmental groups. Cable costs and installation challenges are critical factors, with regulators and authorities increasingly engaged due to rising permit applications.
Chapter 1 Applications of Submarine Power Cables
AI summary Chapter 1 provides an overview of submarine power cable applications, likely focusing on their role in energy transmission, infrastructure planning, and regulatory considerations within Nova Scotia's electricity sector.
1.1 Power Supply to Islands Islands located closely to the mainland can be connected to the mainland grid by submarine power cables. This is normally done with medium-voltage a.c. cables (≤52 kV) and a transmission power of 10–30 MW per ca...
AI summary The text discusses connecting islands to mainland grids via submarine cables, highlighting AC and HVDC technologies, examples like Vancouver Island and Gotland, and challenges of long-distance connections. It emphasizes cable redundancy, historical case studies, and the role of submarine cables as backup power.
1.2 Connection of Autonomous Grids Since the advent of powerful submarine cables many grids have been interconnected, using different techniques. Submarine cables connect grids of different countries (To name a few: UK – France, Sweden – G...
AI summary The text discusses interconnecting autonomous grids via submarine HVDC cables, enabling shared generation capacity, green power trading, efficient spinning reserves, and exploiting price volatility. Examples include NorNed and other long HVDC systems, highlighting benefits for reliability, resource sharing, and market operations.
1.3 Offshore Wind Farms Offshore wind farms (OWP) consists of a number of wind turbine generators (WTG). The distance between the WTGs is 300–800 m. A grid of submarine cables interconnects the WTG and bring the power to shore. The in-fiel...
AI summary Offshore wind farms (OWP) use wind turbine generators (WTG) spaced 300–800 m apart, connected via submarine cables. Medium-voltage cables (10–36 kV) transmit power to shore for short distances, while high-voltage (HVDC) systems are used for longer distances due to lower losses. HVDC requires offshore and onshore converter stations, which are costly but necessary for large-scale projects.
1.4 Supply of Marine Platforms Production platforms in the offshore oil and gas business have a large power demand to extract hydrocarbons from wells. Energy use covers a range of activities including driving pumps to extract hydrocarbons...
AI summary Offshore oil and gas platforms require significant power for operations, often generated via low-efficiency onboard systems. Connecting platforms to onshore grids via submarine cables is becoming viable as power demands grow, with Norway’s example highlighting CO2 reduction potential through hydropower integration.
1.5 Short-Haul Crossings Hundreds of submarine power cables have been installed to transport power across rivers, channels, straits, fjords, or bays. Though overhead lines can be used for crossings up to 3 km (e.g. Messina Strait, Italy) i...
AI summary The text discusses the use of submarine cables for short-haul crossings over water bodies, highlighting their advantages over overhead lines in terms of visibility, maintenance, and reliability. Examples include the St. Lawrence River and Ems River crossings, with the latter's blackout incident underscoring the risks of overhead lines. Trenchless methods are suitable for shorter crossings, while longer ones require traditional submarine cable laying.
References - 1. Doyen H et al. (1989). Experiences with Different Cable Designs and Laying Methods in Conjunction with the Power Supply of the Islands in the North and Baltic Sea, CIRED 1989. - 2. Suen H (2006). Vancouver Island Transmissi...
AI summary The references section lists technical studies and presentations on HVDC transmission, submarine cable designs, and electrical heating applications, citing works from 1989 to 2007 related to power supply systems and cable engineering.
2.1 The Conductor The current-carrying conductors of submarine power cables are made of copper or aluminium. Even though copper is more expensive than aluminium in relation to the current-carrying capability, the majority of submarine powe...
AI summary The text discusses conductor materials for submarine power cables, comparing copper and aluminium. Copper is preferred for smaller cross-sections and corrosion resistance, but aluminium is used in cost-sensitive scenarios. Hybrid approaches (e.g., Estlink project) combine materials based on route conditions. Market volatility and corrosion risks influence material selection.
2.1.2 Conductors Stranded from Round Wires Most conductors for submarine power cables are stranded from round wires. The wires are laid up in the stranding machines in layers. The conductor is compressed by the action of dies or roller set...
AI summary Conductors for submarine power cables are stranded from round wires, compressed to achieve a 92% filling factor. Stranding directions (Z-lay/S-lay) affect coiling stability. Compressed conductors are suitable for AC/DC applications, often following IEC 60228 Class 2. Proximity and skin effects influence ampacity, with insulation methods to mitigate losses.
2.1.3 Profiled Wire Conductors The conductors are composed from cake-piece-shaped wire cross sections, sometimes also called keystone wire conductors. In the stranding machine, the wires (strands) combine perfectly to a circular conductor....
AI summary Profiled wire conductors, formed from cake-piece-shaped wires, achieve high filling grades (up to 96%) and smooth surfaces, ideal for HVDC submarine cables. The IEC 60228 standard does not cover these conductors. The Conform method enables production of profiled copper wires with annealed copper conductivity.
2.1.7 Watertightness of Conductors Longitudinal water tightness is often required for submarine power cables to prevent water from migration into the cable after a cable fault. Also, water ingression from defect end caps during transport o...
AI summary The text discusses methods to ensure longitudinal watertightness in submarine power cables, including swelling agents (powder, tapes, yarns), hydrophobic compounds like Petrojelly, and oil-filled/mass-impregnated cables. Swelling agents perform better in fresh water, while other materials provide alternative solutions.
he latest submarine cable of this kind was the Kontek link between Denmark and Germany with 600 MW d.c. power in 1996. The cable will be replaced by a conventional mass-impregnated HVDC cable in 2010. Oil-filled cables could be improved by...
AI summary The text discusses historical submarine cable technologies, including the Kontek HVDC link (1996) and the planned replacement with mass-impregnated HVDC cables. It highlights advancements in oil-filled cables using paper-polypropylene laminates (PPLP) for improved dielectric strength and reduced losses in EHV AC applications, referencing figures and a 1980s development timeline.
ives. Mass-impregnated HVDC cables with high-viscosity compounds can be used for indefinite route length because they are not depending on external pressurization from on-shore feeding stations [27]. Mass-impregnated cables have small void...
AI summary Mass-impregnated HVDC cables are suitable for long routes due to their self-pressurization properties, but face challenges with AC due to partial discharge risks. While PPLP alternatives show limited improvement, further development is needed. Technical considerations include dielectric strength, void management, and standardization gaps.
2.3.4 Polymeric Sheaths Polymeric cable sheaths have different functions depending on where they are located in the cable construction. A polymeric sheath usually protects the underlying lead sheath from corrosion and abrasion. For this pu...
AI summary Polymeric sheaths in cables serve protective and insulative functions, with HDPE and LDPE being common materials due to their chemical stability and cost-effectiveness. They prevent corrosion, provide water barriers, and manage voltage distribution. Materials like PVC and polyamide offer alternative properties, while PVDC shows potential for lower water vapour permeability though it's not yet used in power cables.
2.6 Three-Core Cables Modern medium-voltage submarine cables (≤52 kV) are usually designed as threecore (3C) cables with XLPE insulation. 2 The cable cores are similar to those of land cables. Many different design alternatives are used fo...
AI summary The text discusses the design and construction of three-core (3C) submarine cables for medium-voltage (≤52 kV) and high-voltage (up to 170 kV) applications. It highlights materials like XLPE insulation, water protection methods (e.g., extruded plastic sheaths, aluminium laminate), and the use of copper wire screens for fault currents. Modern 3C cables balance capacitive currents and are tailored for diverse submarine power link conditions.
2.6.1 Choice Between One Three-Core and Three Single-Core Cables In some cases, the customer has the choice between one 3C cable and three 1C cables for the selected route. The best choice is not always obvious but depends on a large numbe...
AI summary The selection between one three-core (3C) cable and three single-core (1C) cables depends on factors like armoring losses, thermal performance, cost, and installation logistics. 3C cables have lower armoring losses but poorer heat dissipation, while 1C cables allow for redundancy through spare cables. Cost differences arise from manufacturing complexity and installation requirements.
2.7 Two-Core Cables Two-core cables have been used for HVDC systems where two conductors naturally occur. A development of the Mollerhoj cable has two fully insulated cable cores in a common lead sheath and has been used for the Danish par...
AI summary Two-core cables are used in HVDC systems, such as the KontiSkan and NorNed links, offering advantages like magnetic field cancellation. They operate with opposing voltages or through sea electrodes. Future applications include 6-phase AC systems for offshore wind power, minimizing magnetic losses in steel armor.
44 2 Submarine Power Cables and Their Design Elements Fig. 2.10 Two core 450 kV HVDC cable for the NorNed project Flat two-core cables can be bent easily but in one direction. This property makes manufacturing, loading, and installing diff...
AI summary The document discusses challenges with flat two-core 450 kV HVDC cables used in the NorNed project, noting that their directional bending properties complicate manufacturing, loading, and installation, necessitating significant equipment investment.
2.8 Coaxial Cables Coaxial cables have been used in earlier times to achieve concentric cables even in multiphase (two or three) systems (Fig. 2.11). Due to the difficulties of jointing and termination, they have been considered as impract...
AI summary Coaxial cables were historically used in multiphase systems but became impractical due to jointing and termination challenges. Despite this, coaxial HVDC cables were deployed in the 2002 Moyle Interconnector between Scotland and Ireland, highlighting their niche application in specific projects.
of a joint box deep in the water. Sometimes very long lengths of DTS monitoring are stated, but this requires relay or amplifying boxes en route , which is rarely an option in submarine power cables. Optical fibres can also be used for fau...
AI summary The text discusses the use of optical fibres in submarine power cables for fault detection via OTDR and DTS, highlighting limitations such as the need for relays and the inability to detect all power cable faults. It also notes the potential for combining submarine power cables with repeatered telecom lines for long-distance data transmission.
2.10 Five Generic Cable Types The large number of different submarine power cable species and their varieties may be confusing to those not deeply involved in the subject. It is one of the main tasks of this book to create a better underst...
AI summary The text outlines five generic submarine power cable types, detailing their rated voltages, insulation materials, typical applications, and maximum lengths. It emphasizes that these cables are not standardized and often require customization based on specific project conditions, while suggesting that defining cable standards could reduce costs for redesign and testing.
, presented by Cigré Working Group 21 as Session Paper 21-12 at the 1986 Cigré Session, Paris, France. - 41. Elgh L et al. (1982). Repair of 400 kV ac Submarine Cable. Paper 21-05, Cigré Session 1982. - 42. Galloway S J et al. (1990). 150...
AI summary The text lists technical references discussing power transmission technologies, including submarine cables, offshore windfarm connections, and electric cable systems. These sources are cited in the context of engineering research and historical developments in electrical infrastructure.
3.1.2.1 Conductor Losses The magnetic alternating field around the conductor current causes the skin effect, by which the current density is low in the centre of the conductor, and high in the outer regions of the conductor. The useful con...
AI summary The text explains conductor losses due to skin and proximity effects, detailing how alternating current distribution causes increased resistance. Skin effect reduces usable conductor area, while proximity effect worsens resistance in closely spaced conductors. Formulas for AC resistance (R) incorporating skin (ys) and proximity (yp) factors are presented, with implications for conductor sizing and ampacity.
1 should be taken into account for a.c. cables with large segmental conductors, and cables where the λ 1 losses have largely been reduced by cross-bonding or single-side bonding. λ 2 denotes the losses due to circulating currents in the ar...
AI summary The text discusses technical aspects of screen losses in AC cables, including factors like cross-bonding, eddy current losses in steel armorings, and the impact of magnetic fields on armoring and external pipes. It highlights design considerations for reducing losses in single-core and three-phase cables.
capacitances C, which represent the thermal capacities of the different cable layers and the ambient soil. The thermal capacitance of a given volume V of a material with the specific heat $c_p$ is: & lt;sup>6 In the electric analogy the co...
AI summary The text explains thermal capacitance modeling in power cables using an electric analogy, discussing heat flow, thermal resistance, and time constants. A simplified cable example demonstrates temperature rise dynamics under constant conductor losses, reaching 63% of steady-state after 1220 seconds.
3.1.3.2 Temporary Overload Today, submarine power cables are usually buried 1–3 m down in the seafloor. The seafloor temperature will rise slowly, heated by the cable losses. The constant ambient temperature assumption in the simple model...
AI summary The text discusses the thermal behavior of submarine power cables, emphasizing the seafloor's thermal capacitance and resistance. It introduces two quasi-time constants (τ^c for conductor temperature and τ^s for soil temperature) to model temperature evolution during load changes, with implications for cable design and operation.
3.1.3.3 Cyclic or Variable Loads Most submarine power cables are operated with varying load, which is often below the rated power transmission. These cables are under-utilized during certain periods, and the operator might be interested in...
AI summary The text discusses managing variable loads in submarine power cables, emphasizing cyclic load patterns and IEC 60853 methods for overload calculations. It highlights opportunities for higher short-term ampacity during low-load periods and smaller conductor sizes with guaranteed load patterns. Offshore wind parks (OWPs) are noted for variable loads, with thermal considerations for unburied cables lacking ambient soil thermal reserves.
Temperature rise at -0.2 m and -0.3 m Fig. 3.8 Temperature rise over the undisturbed seafloor. Curve 1: A pair of HVDC cables, touching, cable diameter 100 mm, -0.3 m; Curve 2: A pair of HVDC cables, touching, cable diameter 100 mm, -0.2 m...
AI summary The document discusses temperature rise calculations for HVDC cables at depths of -0.2 m and -0.3 m, using equations and figures. It outlines methods to compute temperature increases based on cable losses, thermal resistivity, and cable diameter, emphasizing steady-state conditions and cyclic load averaging via Eq. 3.26 and 3.27.
3.2.1 Tensional Forces During Laying When the cable is being laid from a cable ship there are at least four components that contribute to the tensional forces at the laying wheel: - Static weight of the cable between the laying ship and th...
AI summary The text details tensional forces during underwater cable laying, identifying four contributing factors: static cable weight, residual bottom tension, catenary line weight, and dynamic forces. It provides formulas for calculating tension (Ts = w·D and T = √(T0² + w²s²)) and explains the catenary line's role in bottom tension and cable positioning.
3.3 Electric Design The electric design of submarine power cables follows the same design principles as those for underground cables. Since submarine cables are often more remote and less accessible for repair, it should be considered to i...
AI summary The electric design of submarine power cables follows principles similar to underground cables, with increased safety margins due to their remote and less accessible nature. The chapter focuses on dielectric properties of DC submarine cables, which are less covered in existing literature compared to AC cables.
3.3.3 Dielectric Design of a.c. Cables While the thermal design of a.c. cables is a complex matter due to the extra losses generated by the alternating magnetic field, the electric design of a.c. submarine power cables is so much easier. T...
AI summary The dielectric design of AC cables focuses on ensuring insulation can withstand electric stress from voltages without exceeding breakdown strength. Stress distribution is calculated using Laplace's equation, leading to the formula E(r) = U/(r ln(D_o/D_i)). Key factors include uniform dielectric constant, insulation thickness, and material quality to manage stress concentrations.
3.3.3.1 Overvoltages During testing and operation of submarine power cables a number of different voltage shapes can occur. Power frequency overvoltages can occur during a singlephase-to-ground cable failure until the fault is cleared. Dep...
AI summary The text discusses overvoltages in submarine power cables, including power frequency overvoltages during faults, abnormal operation conditions, and voltage impulses from switching or lightning. It emphasizes the risks of insulation ageing and breakdown, the importance of system studies for protection measures, and references testing standards for lightning and switching impulse tests.
3.3.4 Dielectric Design of d.c. Cables Direct current high-voltage power transmission is more than a century old, and paper-insulated submarine cables have been used for submarine d.c. transmission since more than 50 years [30]. Extruded d...
AI summary The text discusses the dielectric design of DC cables, emphasizing the role of insulation materials and their conductivity under electric fields and temperature. It highlights the use of extruded DC cables by ABB, challenges in measuring conductivity, and equations from references [30]-[32] to model σ(E,T).
4.1.4 Beach Joints Sometimes, the submarine cable can be connected to an overhead line or a substation directly at the landing point, but in many cases the cable route continues onshore. A beach joint between the submarine and the land cab...
AI summary Beach joints are necessary for submarine cables when onshore conductor size requirements differ from offshore conditions or when cable terminations are too distant from shore. The example of the Baltic Cable, which required a 4 km onshore pull, illustrates the practical challenges of such connections.
4.1 Submarine Cable Joints 115 – In many projects the submarine cable is 3C while the land cable system consists of three single-core cables. The transition joint is usually erected in the shoreline The design and installation of beach joi...
AI summary The text discusses challenges in designing and installing submarine cable joints, emphasizing the need for dry environments, cofferdams, and platforms to manage beach joints for HVDC systems. Tidal currents and environmental considerations are highlighted as critical factors affecting installation processes.
4.2.1 On-Shore a.c. Cable Terminations Onshore a.c cable terminations are equal for submarine and underground cables in most respects. Standard terminations for a.c. submarine cables are available from a row of manufacturers: - – Open-air...
AI summary The section details onshore AC cable terminations, noting their similarities to submarine and underground cables. It outlines three termination types: open-air (with corrosion-resistant materials), GIS (compatible with switchgear), and transformer terminations (rarely used for submarine cables). Design considerations include creepage lengths, corrosion protection, and dielectric fluid usage.
4.2.2 On-Shore d.c. Cable Terminations So far, only cable-to-air terminations have been devised for submarine d.c. cables. The stress control in d.c. termination must rely at least partly on resistive elements, Fig. 4.8 Indoor HVDC cable t...
AI summary The document details technical aspects of on-shore HVDC cable terminations, emphasizing stress control using resistive materials, differences between extruded and mass-impregnated cable designs, and oil management systems. It notes similarities to AC terminations but highlights DC-specific adaptations like non-linear resistivity elements and oil expansion vessels.
References 1. HVDC Development options – Cable Capacity. 3rd Supporting Document to the Investment Proposal for the HVDC Inter-Island Link Upgrade Project, Transpower New Zealand Ltd, 2005. http://www.electricitycommission.govt.nz/pdfs/opd...
AI summary The references detail technical documents on HVDC and submarine cable projects, including Transpower New Zealand's 2005 HVDC upgrade proposal, Cigré papers on submarine cable designs (e.g., 525 kV Canada-Vancouver Island link, 420 kV Denmark-Sweden connection), and historical cable reviews. These materials focus on transmission infrastructure and engineering standards.
to soak the dried cable core. Thanks to the low viscosity the impreg- Fig. 5.4 Viscosity vs. temperature of a HVDC cable impregnation mass [3] 5.1 Manufacturing 129 nation and cooling process is much faster than for mass-impregnated cables...
AI summary The text describes the manufacturing process for HVDC cables, emphasizing the use of low-viscosity impregnation oil to accelerate cooling and the method of transporting insulated conductors via oil-filled tubes to prevent humidity absorption during transit.
5.2.2.2 Load Cycle Test Load cycle tests are part of the type tests for all submarine power cables. The a.c. cables are usually subjected to electric tests according to the same specifications as underground cables. The load-cycle test pro...
AI summary The load cycle test procedures for mass-impregnated HVDC submarine cables involve 24-hour cycles with alternating positive and negative voltages, considering ambient temperature variations. Key limiting factors include conductor temperature and insulation thermal stress, with parameters interdependent during testing.
6.1 Scope of the Marine Survey There are no strict general rules for the needed scope of a marine survey. It should be clear to the submarine cable project planner that a more comprehensive survey can help the installing contractor to perf...
AI summary The scope of a marine survey for submarine cable projects requires balancing comprehensive data collection with cost efficiency. A Desk Top Study (DTS) using public and commercial data is essential for planning, while on-site surveys with accurate equipment are critical for precise cable installation. Permits, geodetic standards (e.g., WGS84), and seafloor sampling are emphasized to avoid costly errors.
6.2 Bathymetry The marine equivalent of a topographic land map is a bathymetric map of the sea bottom, indicating the depth at any point. The cable design engineer needs to know the water depth in order to determine the mechanical properti...
AI summary The text discusses the importance of accurate bathymetric data for submarine cable design, highlighting the limitations of electronic charts and the need for up-to-date hydrographic surveys. It emphasizes that electronic charts may not be more accurate than paper charts and that historical data can be outdated, affecting the reliability of bathymetric information.
6.3 Sub-bottom Profiling If the submarine cable is to be protected, the knowledge of the seafloor bathymetry is not enough. Especially for cable burying it is necessary to know what is hidden below the sea bottom. The character, hardness,...
AI summary Sub-bottom profiling is critical for submarine cable protection, as it reveals sub-seafloor layers affecting burial methods and thermal parameters. Inadequate profiling can lead to unexpected obstacles, such as encountering bedrock or hidden pipes, causing costly operational changes. Comprehensive profiling ensures accurate planning and avoids risks during cable installation.
6.4 Visual Inspection In complicated waters a survey performed from the sea surface may be too insensitive to reveal all underwater features. In order to achieve a complete picture on the subsea conditions before cable laying, manned subma...
AI summary Visual inspection methods for underwater cable laying include ROVs/AUVs for detailed seabed assessments and site visits to evaluate soil conditions and logistics. Data collection from interviews and DTS complements these efforts to inform installation technology choices and hazard mitigation.
Chapter 7 Installation and Protection of Submarine Power Cables
AI summary Chapter 7 focuses on regulations governing the installation and protection of submarine power cables, likely covering technical standards, safety protocols, and compliance requirements for underwater electrical infrastructure.
is method requires a continuous cable tension during loading and laying. If the continuous tension is interrupted, this method can cause disorder in the cable turns as they slide down from the center. Some vessels are or can be equipped wi...
AI summary The text describes methods for laying HVDC cables using cable laying vessels (CLVs), emphasizing continuous tension, dual turntables for simultaneous cable laying, spaced laying wheels to maintain cable distance, and bundling techniques for shallow water operations. It notes that burial can occur in a single operation after laying.
7.1.3 Loading and Logistics Submarine cables with short length can be handled and transported on standard or oversize drums. Most standard and all oversized drums require flatbed trailers making the onshore transport expensive. When the su...
AI summary The text discusses challenges in transporting and installing submarine cables for offshore wind parks, comparing methods like pre-cut drums versus coils. It highlights risks of damage during loading, the need for synchronized equipment, and the importance of proper cable sealing to prevent water intrusion. Logistics costs and efficiency are emphasized, particularly for long cable lengths.
7.1.4 Laying of Submarine Power Cables Submarine cables on drums, e.g. for in-field cables, can be installed from barges with simpler navigation equipment. A drum pay-off and a linear machine with brake are necessary. The cable runs over a...
AI summary The text describes the process of laying submarine power cables using barges, emphasizing the need for anchors, tugboats, and specialized vessels. It highlights risks of damaging existing infrastructure, slow progress (1–2 km/day), and challenges with visibility for ROV cameras in certain waters.
7.1.5 Landing of Submarine Cables The landing of submarine power cables sometimes requires the most engineering, the most equipment and often the most time of all efforts of the cable project. The majority of all submarine cable projects h...
AI summary The landing of submarine power cables is a complex engineering process requiring careful planning and execution. Methods vary based on shore conditions, equipment capabilities, and regulatory requirements. Examples like the NorNed cable project demonstrate successful open trench landings even in sensitive areas like dikes.
7.1.6 Jointing of Submarine Power Cables Although modern cable laying vessels can store and handle enormous lengths of cable, it is sometimes unavoidable to joint cables on open sea because the length of the cable route cannot be covered w...
AI summary Submarine power cable jointing on open sea is necessary due to route length limitations and design variations. The process requires specialized equipment, planning, and trained crews to avoid damage from overbending, overtensioning, or water intrusion. Improper methods may necessitate cutting damaged cables and using spare cable.
7.1.6.2 After-Installation Joints Sometimes it is necessary to lay down both Cables A and B onto the seafloor without jointing. A possible reason might be a short weather window not allowing for both jointing and subsequent laying in one g...
AI summary The text discusses post-lay jointing of submarine cables, noting that laying cables without initial jointing may be necessary due to weather constraints or cost efficiency. It outlines configurations for post-lay jointing, emphasizing overlap lengths based on water depth and cable guide lengths, and mentions equipment like ROVs and jointing shacks.
7.1.7.1 Winds Wind generates waves. The wind distribution can be very different for different places and is subject to strong seasonal variations, which may create weather windows of different length for the cable laying. The wind speed is...
AI summary The section discusses wind's role in generating waves and its impact on cable laying operations, noting seasonal variations and weather windows. Wind speed measurements are described using the Beaufort scale and other units, with Table 7.1 correlating wind conditions to sea-state characteristics.
7.2.1 Selection of a Suitable Cable Route After a desktop study a provisional cable route can be selected. As far as possible, hazardous areas should be avoided, such as: - Shipping lanes, anchorages, harbour entrances - Fishing grounds -...
AI summary The selection of a submarine cable route requires avoiding hazardous areas like shipping lanes, fishing grounds, and unstable shorelines. Key considerations include minimizing interference with maritime traffic, preventing damage from fishing activities, and accounting for environmental and future development impacts on cable integrity.
7.2.3.1 Trenching The most common protection method today is trenching, i.e. the burial of the cable under the seafloor. There is a variety of different trenching methods, and new equipment is being developed as the amount of submarine inf...
AI summary Trenching, specifically ploughing, is a common method for burying submarine cables under the seafloor. The process involves cutting a slit with a ploughshare, guiding the cable into the trench, and facing risks in rocky soils. Ploughing is economical for soft to medium soils but requires careful management in deeper waters and rocky conditions.
7.3 Appendix: The Catenary Line 207 Fig. 7.27 Catenary curve of the cable under the laying vessel. Here the catenary parameter a has the value a =30 Fig. 7.28 Catenary curve of the cable under the laying vessel The inclination of the curve...
AI summary The text details mathematical equations for calculating catenary parameters (a, L, H) during cable laying, including formulas for tension, cable length, and bending radius. These equations are critical for engineering analysis of submarine cable deployment.
used with weights up to 30 t for the largest ships. The anchors of "Queen Mary 2" weigh 23 t. Different anchor shapes have different efficiency and behave different in their contact to the sea bottom. The risk of anchor damages of a given...
AI summary The text discusses assessing anchor damage risks to cables using statistical methods, analyzing ship traffic data, and an empirical formula linking ship deadweight to anchor mass. It references anchor damage examples and distribution models for cable routes.
8.1.5 Damage During the Installation While many failure statistics account for failures during operation, they usually do not include damage to the cable that happens before commissioning. Cable damages during the installation might call f...
AI summary The text discusses damage to submarine power cables during installation, highlighting risks like loss of dynamic positioning, anchoring, kinks, loading/reloading, improper trenching, and emergency cuts. These issues can lead to costly repairs and emphasize the need for preventive measures.
8.1.6 Other Damage Anchors and fishing activities account for the largest portion of submarine cable damages. A minor share is caused by other factors, this portion being smaller for submarine power cables since they are stronger than tele...
AI summary The text discusses various causes of submarine cable damage, including anchors, fishing, free spans leading to vortex-induced vibrations, ship collisions, geo-hazards like landslides and volcanic activity, and shipwrecks with unexploded ordnance. These factors contribute to the degradation and failure of submarine cables, impacting transmission infrastructure and system reliability.
8.2 Repair The repair of submarine cables is one of the most demanding tasks of submarine cable engineering. Not only must the fault be found and identified in water depths often inaccessible to divers, also the damaged cable must be made...
AI summary Submarine cable repair is complex, requiring specialized methods like external sealing cassettes and submersible workshops. Challenges include inaccessible depths, surface retrieval, and adverse conditions. Preparation with 'red alert' plans is emphasized for effective repairs.
8.2.2 Repair Vessel The repair vessel may differ very much from the laying vessel, as there are different needs for load capacity and deck arrangements. A load capacity of a few hundred tons can be enough to carry the spare cable and all h...
AI summary The repair vessel differs from laying vessels in load capacity, deck arrangements, and specialized equipment needs. It requires open decks, jointing houses, cable handling systems, and may use ROVs for complex repairs. Repair setups vary based on cable type (e.g., 600 MW HVDC vs. 11 kV) and environmental conditions.
8.3.1 TDR The acronym TDR stands for "Time domain reflectometry" and is based on an electric impulse, which is sent into the faulty cable conductor. The easiest fault to detect is a complete cable break. The impulse travels down the conduc...
AI summary Time Domain Reflectometry (TDR) detects cable faults by sending electric impulses through conductors. Faults like breaks cause reflections with opposite polarity, allowing distance calculation via propagation velocity. The formula for velocity involves permittivity (ε) and permeability (μ) constants, with mass-impregnated cables having a velocity of 150 m/μs. Figures illustrate reflections for open and short circuits.
8.3.3 Fine Localisation The methods mentioned above are able to find the fault within a few percents of the total cable length. This can still be a few kilometres, too much for excavating the cable and searching with a ROV for the fault. I...
AI summary The text describes methods for fine localisation of submarine cable faults, including using signal currents, search coils, ROVs, and TDR measurements. Techniques involve detecting magnetic field changes, deploying ROVs for precise positioning, and cutting cables for TDR analysis when faults are within a few hundred meters.
References - 1. Lawrence M (2002). Submarine Cable Industry, -Alcatel Survey Standards and Future Trends. MUC Kiel, 2002. - 2. Hoshina R (2001). Improvements in Submarine Cable System Protection, SubOptic 2001. - 3. Shapiro S, Murray J, et...
AI summary The references discuss technical aspects of submarine cables, including protection, reliability, installation, and environmental factors, citing industry standards, risk assessments, and case studies from various experts and organizations.
9.1.2.1 DTS The Distributed Temperature Measurement System (DTS) is an optical fibre-based temperature sensor incorporated into the power cable, or installed alongside the power cable. Such a system is able to monitor the temperature along...
AI summary The Distributed Temperature Measurement System (DTS) uses optical fiber to monitor power cable temperatures, detect anomalies, and enable dynamic cable rating. It aids in identifying sediment erosion, supports submarine cable inspections, and allows operators to optimize ampacity based on ambient conditions for temporary overloads without compromising cable integrity.
9.1.4 LPOF, SCOF and SCFF Cables Fluid-filled (FF) and oil-filled (OF) cables require the monitoring of the oil-pressure feeding system. Since the performance of these cables is critically depending on the prevailing oil pressure, it must...
AI summary The text discusses the importance of monitoring oil pressure in LPOF, SCOF, and SCFF cables to detect damage and maintain system reliability. It emphasizes the need for degassed dielectric fluid, SCADA integration, and regional collaboration among cable operators to manage potential leaks and ensure timely repairs.
9.2.4.4 Long Island Seven single-core high-pressure oil-filled 138 kV cables were installed under the Long Island Sound and commissioned in 1969. At that time it was the longest oil-filled submarine cable in the world [9]. Eighty percent o...
AI summary The 1385 cable system under Long Island Sound, commissioned in 1969, faced frequent failures due to corrosion and external damage, costing over $45 million in repairs since 1990. It was replaced by three 3C 138 kV cables buried six feet deep, improving reliability.
Cu-conductor, 1200 mm 2 Al-conductor, 2000 mm 2 Conductor resistance at 20°C 0.015 mΩ/m $0.015~\mathrm{m}\Omega/\mathrm{m}$ Conductance 66.666 m/Ω 66.666 m/Ω Mass of conductor 10.7 kg/m 5.4 kg/m Energy used for raw material production [4]...
AI summary The table compares copper and aluminum conductors, highlighting metrics like resistance, conductance, mass, and energy consumption for raw material production. Aluminum shows lower mass and energy use when incorporating recycled materials, though both materials have similar conductance.
disturbance. In a risk evaluation, the additional risk due to compass deviation seems small compared to risks from ignorance and bad seamanship. The consequences of a vessel accident are quite small. Medium size vessels (draught 2–4 m) can...
AI summary The text evaluates the electromagnetic risks of HVDC cables on marine traffic, concluding that risks are low due to vessel design, navigation systems, and sufficient water depth. Most commercial vessels use non-magnetic navigation systems, minimizing potential impacts.
11.2 HVDC Cable Between Lydd, UK and Boulogne, F " C/S Dame Caroline Haslett" left Woolwich Cable Works at 24 May (probably 1961) for laying the English part of the cable. She made preps and test runs at the mooring position off shore. At...
AI summary The installation of an HVDC cable between Lydd, UK, and Boulogne, France, faced challenges when air cushions failed during deployment, causing the cable pair to sink. Weather delays and technical issues exacerbated the difficulties during the operation.