Sverre Hvidsten

Severe degradation of the conductor screen of service and laboratory aged medium voltage XLPE insulated cables

The main purpose of this paper is to show the strong correlation between corrosion of the metallic aluminum conductor and the formation of interconnected cracks / voids in the conductor screen, creating initiation sites for vented water trees in service aged medium voltage XLPE cables. The results show that porous structures in the conductor screen previously reported for laboratory aged insulation systems, also develop in the conductor screen in service aged medium voltage XLPE cables. These structures can bridge the screen and serve as path for contaminants and corrosion products from the aluminum conductor and initiate water trees. A prerequisite for the formation of such structures is the presence of liquid water at the interface between the conductor and conductor screen causing corrosion. The initiation site of such structures has been identified, and is likely caused by environmental stress cracking (ESC). Initiation sites were determined in all cables, but porous structures in the conductor screen were only observed in the cable suffered from service failure, where liquid water had entered the cable conductor between the strands. Severe degradation of the XLPE insulation was observed at the initiation sites for water trees growing from these structures.

Diagnostic testing of MV XLPE cables with low density of water trees

In this paper, results from diagnostic measurements performed on service aged 12 and 24 kV (MV) XLPE cables equipped with strippable insulation screens are reported. The main purpose of this work has been to examine if condition assessment can be performed on such cables having typically low density of vented water trees. The actual condition of the cables was determined by laboratory AC breakdown tests and water tree examinations performed on the same cables. Secondly, the influence on the diagnostic testing of the joints installed on the cables has been examined. The results show that it is not possible to distinguish the ageing status for cables having breakdown voltages of 5 U. and higher. The evaluation criteria need to be further developed, in order to examine if the condition of cables with breakdown voltages lower than 5 U. can be reliably assessed. Joints with resistive field grading can have very high resistive losses preventing a reliable condition assessment of the cable insulation.

A Transformerless generator-converter concept making feasible a 100 kV light weight offshore wind turbine: Part I - The generator

A novel HVDC technology which enables lightweight HVDC machines is described in two papers: Part I describes the concept of a segmented HVDC generator and some of its possible designs. Part II addresses the modular AC/DC-converter. In both papers the HVDC concept is applied in an electric drive for an offshore wind turbine. The HVDC technology is a modularized electric drive train in which the connection between VSC converter modules and machine modules will have a great influence on the required insulation thickness in the machine. Two main effects are obtained: Better insulation coordination within the machine and the possibility to exploit the benefits of HVDC insulation. A case study indicates the possibility to make a transformerless 100 kV DC electric drive for offshore wind turbines. The high voltage is achieved at the very first steps in the energy chain. For moderate transmission distances no further voltage transformation steps is necessary, thus minimizing the needed components for offshore energy transmission and increasing the total efficiency of the system.

Water treeing in XLPE insulation at a combined DC and high frequency AC stress

For many subsea HVDC cable systems, the DC current is transmitted through the HV cable in a voltage source converter (VSC) - HVDC scheme. Modulated upon the DC voltage are harmonics, which originate from the switching feature of the VSC stations. The main purpose of this paper is to examine the effect of a superpositioned high frequency AC voltage on wet polymeric XLPE submarine cable systems. Rogowski type test objects were manufactured with an AC XLPE insulation and corresponding semi-conductive screens. Small sodium chloride particles were introduced as initiation sites for vented water treeing from the lower semi-conductive screen. A DC stress was applied to the object with a combined stress of a 10% sinusoidal voltage at 5 kHz. As references, parallel test objects were subjected to a sinusoidal 50 Hz or 5 kHz AC stress with the same peak magnitude but without the DC stress. The ageing was characterized by AC breakdown voltage testing, water tree analysis recording the tree lengths and SEM analysis on selected samples. The results show that acceleration of water tree growth by frequency is strongly dependent on the size of the contamination at the initiation site. No water trees are observed under high field DC conditions, even for the samples with sodium chloride inclusions. The combined DC and high frequency AC stress generates very long vented water trees. The initiation and growth rates are mainly determined by the AC part of the stress. However, the results also indicate that the high DC stress impedes the water tree growth.

Diagnostic testing of thermally aged medium voltage XLPE cable joints

Current loading of wind farm distribution network is very different from that observed for traditional underground cable systems. Variations in wind power results in a significant number of current load cycles during service. The current can increase from zero to maximum rated load in a short time. This can cause high temperature gradients in the cable systems inducing significant thermo-mechanical forces during heating and cooling, and thermal oxidation at high load. Several premature service failures of cable joints in wind farm distribution networks have occurred, mainly due to the combined action of bad metallic connectors and high load current. Partial discharge measurements are today performed on-site using different frequencies and magnitudes of the test voltage. As the oxidation process causes the conductivity of the bulk and surfaces of the materials involved to strongly increase, this will also likely impact the frequency dependence of the partial discharges. This work includes laboratory high temperature ageing of rubber type heat-shrink MV XLPE cable joints including temperature gradients by application of high load currents. The ageing has been electrically characterised by variable partial discharge measurements in the frequency range of 10 mHz to 100 Hz up to 12 kV (2 U0). The joint material was examined by microscopy examinations after ageing. The results show that the partial discharges are strongly frequency and voltage dependent. For shorter ageing times of the rubber joints, the number of discharges per voltage cycle decrease to zero for frequencies below 10 Hz. At longer ageing times resulting in severe material ageing, the number of discharges per voltage cycle strongly increases by decreasing frequency. In this case the inception voltage at 0.1 Hz was equal or lower than that measured at higher frequencies. It is observed by SEM that especially the stress-control material was strongly degraded by the high temperature conditions.

Measurement of Solubility and Water Content of Insulating Oils for HV XLPE Cable Terminations

Water has been found to be one of the the main causes for some service breakdowns of high voltage XLPE cable terminations in Norway. Therefore, measurements of water content have been performed on oil samples taken from several oil-filled housings in service. In addition, measurements of water solubility of three actual oil types have been performed at different relative humidities and temperatures in order to detect the saturation contents. The results show that high water content in the oils in service can be present, and even liquid water was detected. The measurements of water solubility of actual oils show that condensation of water droplets can occur during service. It is therefore recommended to perform maintenance work on such installations with respect to monitor the water content of the insulating oils.

Condition assessment of 12- and 24-kV XLPE cables installed during the 80s. Results from a joint Norwegian/Swedish research project

This paper reports the results from the condition assessment of 12- and 24-kV cross-linked polyethylene (XPLE) cables using a technique based on dielectric spectroscopy initially developed at KTH in Sweden. The work aims to examine whether the method could detect water tree degradation for the second generation medium voltage (MV) cables with long, but not bridging, water trees. While the overall cable condition was better than expected for second generation XPLE cables, water trees were found in most of the selected cables. The diagnostic method based on the measurement of the dielectric response could only detect water tree degradation in the examined second generation cables when the water trees bridged the insulation wall. Condition assessment above service stress may, in some cases, be required to detect bridging water trees. The results indicate that there is a correlation between the voltage level and the breakdown voltage of the cable. This can be used as a diagnostic criterion for this group of cables.

Effects of raw natural gas on the aging of high-voltage electrical machine mainwall insulation

The total recovery of natural gas from subsea wells can be significantly increased with a compressor installed near the wellheads. The compressor is powered by a high-speed induction motor integrated in the same casing. The process gas flows through the motor and acts as a cooling medium. The insulation system of the motor is in direct contact with the gas and must be resistant to it. The gas mixture contains hydrocarbons, water, and monoethylene glycol. The effects of the gas mixture and its individual components on the properties of a high-voltage machine mainwall insulation consisting of mica, glass, and epoxy are obtained by experimental tests with raw natural gas at accelerated conditions. The tests at high pressures and temperatures indicate that heavy hydrocarbon compounds cause similar effects to plasticizers inside the bisphenol A epoxy resin, but such compounds do not penetrate easily into epoxy novolac resin. The plasticizing effect is seen as increased weight and volume, decreased mechanical strength and E-modulus, and reduced glass transition temperature. The polymers did not decompose chemically. The mainwall insulation is vulnerable to delamination, which is initiated by the detachment of glass strains and epoxy resin. Water causes dielectric loss peak at very low frequencies, while the heavy hydrocarbons produce a loss peak in higher frequency range.

Simulation of Water Diffusion in Polymeric Cables Using Finite Element Methods

The major aging mechanism in polymeric medium voltage cable insulation is water treeing. Water trees can grow from contaminations and protrusions in the cable insulation when the relative humidity (RH) in the cable insulation exceeds a value of about 70 %. Water trees can cause service breakdown of the cable when they reach a critical length. The service life of cables without any metallic water barrier can be prolonged by delaying the water ingress into the cable. The water ingress is dependent on the diffusion rate, water sorption, initial water content in the cable materials, and the temperature of the cable. A numerical model for simulating the water ingress into a cable has been made using a finite element method. For some of the cable materials the water solubility coefficient was concentration dependent, and details of modeling these coefficients are included. Simulations for several cable configurations have been performed to investigate the time it takes for the humidity in the cable insulation to reach the critical threshold for water tree growth. The results have been compared with a simplified method for determining the time to reach 70% RH. The results show that it is possible to include concentration-dependent solubility coefficients in the finite element method. The results from the simulations and the simplified method show good agreement. By taking account of the water absorbed by the semiconductors, the time to reach 70%RH is increased by about 10%.

HV cable design applicable for direct electrical heating of very long flowlines

Direct electrical heating (DEH) has shown to be a very promising method to prevent wax and hydrate formation in subsea pipelines used in the North Sea. Up to now the system has been installed on flowlines of lengths between 5 and 15 km. In this system the heated pipeline is an active conductor in a single-phase electric circuit, together with a single core high voltage extruded cable strapped (piggybacked) to the heated flowline. A specially designed cable with an insulating outer sheath has been proven feasible for lengths up to 15 km. However, for new projects with flowlines exceeding 40 km a new cable design is essential to limit high voltages subjected to the screen caused by the capacitive and inductive currents. This paper presents electrical and thermal rating of the DEH system for long flowlines, measurements of mechanical and electrical properties of different semiconductive cable outer sheath materials aged in relevant service conditions, and measurements of electrical resistivity and water content of clay samples taken from relevant oil fields. The results are very promising and show a long endurance of the semiconductive cable sheath materials at the calculated service temperatures. The tests confirm that a sufficient low resistivity of the semiconductive outer sheath and clay for continuously transferring capacitive currents to ground was measured. The results indicate that the DEH system can be used for particular long flowlines to prevent wax and hydrate formation