To make the most of potential new business opportunities in the growing solar panel sector‚ contractors need to understand the technology and the electrical testing associated with PV system installation‚ says Jim Wallace of Seaward Solar

Energy regulator OFGEM recently reported the 2010 year end total of solar power installations reached 45MW. Month by month numbers of domestic PV installations ended the year with over 2‚000 per month during November and December.

This solar microgeneration ‘boom’ reflects the impact of Feed-in Tariffs (FITs) introduced from 1 April 2010 and also the arrival of free installation schemes that enable the property owner to benefit from solar electricity while the installer receives the FIT payments. Any PV installation seeking funding from the FITs initiative must use Microgeneration Certification Scheme (MCS) approved contracting companies. MCS is a quality assurance scheme and approval is therefore a pre-requisite for any company seeking to take advantage of the growing demand for solar panel installation.

Given the obvious synergies‚ it is widely expected grid connected PV systems will quickly become a mainstream electrical contracting industry activity. Alongside MCS accreditation‚ the installation process itself is unlikely to be too difficult for a qualified electrician‚ although there are significant differences from the usual installation wiring technology that they are likely to be working with on a day to day basis.

PV installation overview
The installation of PV systems presents a unique combination of hazards linking the risk of electric shock with the implications of working at height.

PV arrays produce a DC voltage when exposed to sunlight. In the wiring system associated with PV panel installation‚ the DC current generated by the solar array is converted to AC by means of an inverter which then feeds into the AC mains supply of a building.

From the outset, therefore, the designer and installer of a PV system must consider the potential hazards carefully and systematically devise methods to minimise the risks - including mitigating potential hazards present during and after the installation phase. In particular, it is vital the long term performance and electrical safety of the system is not compromised by a poor installation or subsequent poor maintenance.

Much of this comes down to the quality of the installation and the system inspection and testing regime.

PV systems are unusual in that the energy source cannot be switched off. If there is daylight falling on a PV panel it will produce electricity and it is possible for a relatively small array of only a few panels to deliver a lethal shock.

Another important point is PV panels generate DC voltage, which is not always commonly used by electricians in their normal work. In addition‚ because of the current limiting properties of PV cells‚ they are incapable of producing sufficient fault currents to operate over-current protection devices such as fuses. Once established a fault may remain undetected, not only posing a hazard for an extended period but also wasting energy generated by the PV system. Undetected faults may also develop into a fire hazard over time. Special measures must therefore be taken during installation of PV systems to eliminate the risks of dangerous working and latent electrical problems.

These include completing the DC wiring before connection is made to the panels and avoiding working with both positive and negative conductors simultaneously. This will allow the effective isolation of the dc system (via a DC isolating switch and module cable connectors) while the array is installed and the effective isolation of the PV array while the inverter is installed.

Installation standards
The general requirement is that grid connected PV solar systems are tested according to 17th edition electrical wiring regulations but there also additional requirements for PV systems.

Engineering Recommendation G83/1 is the installation commissioning confirmation form for the connection of Small Scale Embedded Generators‚ such as PV arrays‚ of up to 16A per phase with public low voltage distribution networks. Installers are required to complete G83/1 with information on various tests‚ system details and a range of supporting information to satisfy the requirements of the Distribution Network Operator.

Installation of domestic grid connected PV systems falls with the scope of Part P of the Building Regulations and it the responsibility of installer to ensure systems are installed according to the existing BS7671 electrical installation standard – the 17th Edition IEE Wiring Regulations.

However‚ the inspection and testing of DC circuits associated with PV arrays requires special considerations.  The IEE Guidance Note 7 Special Locations provides guidance on Solar photovoltaic (PV) power systems.

‘IEC 62446: 2009 Grid connected PV systems – minimum requirements for system documentation, commissioning tests, and inspection’ specifies the minimum requirements for PV system documentation‚ commissioning tests and inspections.

Building or electrical works in the vicinity of the PV array are also likely and the ownership of a system may also change. The standard recognises that only by the provision of adequate documentation at the outset can the long term performance and safety of the PV system be ensured.

In short the standard sets out measures to ensure:
t The PV panels and electrical supply connections have been wired up correctly
t That the electrical insulation is good
t The protective earth connection is as it should be
t There has been no damage to cables during installation

Under electrical tests the standard sets out specific requirements for:
t Earth continuity of array frame to earth and connection to main earthing terminal
t Polarity of all DC cables
t PV string open circuit voltage test
t PV string short circuit current test
t PV array insulation test  
t Operational test – PV string current
t Functional test
t Irradiance
IEC62446 also requires inverter details to be recorded and MCS requires that installation records are kept.

Testing times
Between them‚ the various installation requirements for PV systems are designed to ensure the electrical safety of the installation and installation personnel - and the verification of performance/power output of the system.

However‚ in what is still a relatively new area for many contractors‚ there remains a lack of understanding of some issues.

For example, many inverters have transformer isolation between the AC and DC side, preventing DC fault currents from being fed into the electrical installation. Transformerless inverters are increasing in popularity due their increased efficiency and reduced cost and physical size.

IEE Guidance Note 7 advises where an electrical installation includes a PV power supply without at least simple separation between the Ac and DC sides, an RCD installed to provide fault protection shall be type B.

However, the guidance also states where the inverter is, by construction, not able to feed DC fault currents into the electrical installation, an RCD of type B is not required. Manufacturers of transformerless inverters commonly provide declarations to this effect - avoiding the need for a type B RCD.

One area of PV installations where there is there is also much debate is that of protective earthing and equipotential zones.  Where the PV array is not Class II, exposed metal parts must be connected to protective earth. When the electrical installation is a Protective Multiple Earthing (PME) system, the recommendation is that the PME is not taken outside the equipotential zone.

In such cases, the recommendation given in the DTI Guide to the installation of PV systems is connection to earth is via an earth spike. However, there is much debate as to whether a PV is inside or outside the equipotential zone. The array itself is mounted on the exterior of the building - however, conductive parts such as fixings or brackets may be accessible from inside the building as they pass through the roof. Also‚ in terms of test instrumentation‚ different PV electrical tests require the use of different testers – typically including an earth continuity and insulation resistance tester‚ a multimeter and DC clampmeter. Using such an array of instruments can be cumbersome and time consuming – considerations which have led to the introduction of a new generation of integrated testers capable of performing all of the tests required by IEC 62446.

Ongoing verification of performance
The installation of PV system by householders is clearly only undertaken after careful consideration of the costs involved and potential return on investment provided by lower energy bills and FIT payments. The verification of system performance and energy output from the panels is therefore particularly important and a major reason why periodic verification and testing of the system can also be very important – as well as being essential to comply with warranty and PV system guarantees. In many cases simple electrical faults or wiring failures can cause a serious inefficiency in the ability of the panel to produce power. This is particularly important for installers working on ‘roof rental’ schemes were installation has been provided free of charge in return for receipt of the FIT payments. In such circumstances proper metering will always give an indication of system performance but effective electrical testing is vital not only to prove the safe installation of a new system but also to verify ongoing functional performance over extended periods.



The use of connectors in wind turbines faces a unique set of challenges explains Kevin Canham of Harting

Working with wind turbines, ambient conditions such as vibration and air humidity are harsher than in some industrial environments. This applies in particular to wind farms sited in offshore waters – an increasingly important location.

As well as needing to be resistant to these environmental influences, it is important prefabricated components can be assembled quickly and without mistakes on-site. One of the requirements is the time taken to assemble these turbines and take them into operation is kept as short as possible.

Application sectors
Fig.1 shows the key areas where high-quality interconnection is required in a wind turbine:
Pitch control: Almost all modern wind turbines use so-called ‘pitch control’ to regulate speed and power output. Here, the angle between the rotor blades and the wind is changed by rotating them around their longitudinal axis. In this application, components in Harting’s flexible Han-Modular‚ connector series can be freely combined, so that users can configure their own connector. An extensive range of modules is available for electric, optical and gaseous signals.

An urgent question facing many manufacturing companies is, ‘How do we provide clean, safe, environmentally-sustainable energy products for Britain, Europe and the world as a whole, during the twenty-first century? - Steve Gallon, UK MD of enclosure manufacturer Fibox, explains its approach

With scientists predicting the world's population will continue to grow for several decades at least. It’s clear the demand for energy is likely to increase even faster, and the proportion supplied by electricity will also grow faster still. - However, this is where opinions depart as to whether the demand for electricity will continue to be served predominantly by extensive grid systems, or whether there will be a strong trend to locally distributed generation.

Either way, it will not prevent the need for more power, especially in urbanised and industrialised areas, and much of that demand will be for a continuous, reliable supply of electricity.


No denying it. Fukushima has changed the ground rules for the wonderful world of electricity. Forever.

In service high-voltage (HV) substation equipment is exposed to many stresses, from the electrical, mechanical and thermal to the environmental. These stresses can act to accelerate the deterioration of the insulation and the electrical integrity of the HV equipment eventually leading to failure. Partial discharge (PD) is both a symptom and a cause of insulation deterioration, so the detection and measurement of PD phenomena can provide early warning signs of insulation failure.

Critical to this detection is the availability of accurate and cost effective surveillance tools, which, if non-invasive, can provide early recognition and location of possible sites of electrical degradation while components are still in service. Gathering and trending PD activity over time is essential to monitor the rate and severity of degradation. Maintenance can then be planned in an effort to avoid unplanned outages, interruptions and inevitable loss of revenue.

The use of radio frequency interference (RFI) measurement is an efficient, non-invasive surveillance technique to detect and locate partial discharges in individual HV apparatus. This article will look at the benefits of combining the assessment of RFI emissions with the targeted deployment of complementary, non-invasive electromagnetic interference (EMI) detection techniques. Specifically, frequency sweep data and time-resolved traces can be compared with follow up assessments using complementary EMI couplers such as high frequency CTs (HFCT) and transient earth voltage (TEV) couplers. This combination of tests provides an increased level of confidence in the location, identification and assessment of the severity of degradation and is beneficial when dealing with complex HV apparatus.

The detection and measurement of RFI emissions from PD phenomena involves the measurement of complex waveforms varying considerably and often erratically in amplitude and time. RFI signals from such phenomena are considered to be broadband and impulsive in nature with low repetition rates.

Measurements carried out on PD activity within oil-insulated HV equipment demonstrate that the discharges produce current pulses with rise times less than a nanosecond and therefore capable of exciting broadband signals in the VHF (30 to 300MHz) and UHF (300MHz to 3GHz) bands. Other investigations in open-air insulation substations show that signals from PD and flashover occupy a frequency range up to 300MHz.

When PD occurs inside a metal enclosure, such as in a transformer tank, the signal propagates within the structure, suffering frequency attenuation, reflection, etc. Detection of RFI emission relies on the placement of apertures in the tank walls and penetrating conductors to allow the RFI emissions to propagate and radiate externally.

In the following examples, the instrument used (Doble PDS100) has two different detection modes: spectrum analyser and time-resolved mode. Within spectrum analyser there are three separate detection techniques: peak detection, average detection and separated peak and average detection.

Case Study 1
Dissolved Gas Analysis (DGA) carried out on a South African, 275/88/11KV, 250MVA transformer showed signs of a discharge type fault. RFI measurements (using the Doble PDS100) and conducted EMI measurements (using a HFCT) were performed to establish correlation between the measurements. RFI measurements were taken around the periphery of the transformer. The frequency traces (FIGURE 2) exhibit a discrete appearance as pulses are accumulated. Short bursts of pulse accumulation were interspersed with long intervals of no or low energy activity. Triangulation based on signal intensity of the higher frequencies locates the source of propagation in the vicinity of the HV B-phase. Observing the RFI at 900MHz for a period of time in spot frequency mode sees the measured peak amplitude reaching -45dBm at that location. This mode also confirms the burst nature of the pulse sequence.

The conducted EMI was measured using a 300MHz split-core HFCT at the HV neutral connection to earth. The measured conducted EMI is subjected to significant attenuation through the HV neutral connection and requires an extended observation time. In time-resolved mode both the RFI and conducted EMI measurement confirm the measured pulse behaviour. However, the pulsed activity is more easily captured and more of the lower energy pulses are detected.

Partial discharge activity is indicated by both the RFI and EMI techniques. In each, the dynamic behaviour of the activity is characterised by very short burst activity interspersed by intervals of no or low energy activity. The sequence exhibits the characteristics of a floating type discharge. A secondary source of discharge is evident in the time-resolved traces. The results confirm the conclusions drawn from the DGA analysis. This study proves the use of RFI as an assessment tool while the use of an HFCT coupler provides increased sensitivity to internal PD activity, offering an increased level of confidence in the identification and assessment of PD activity.

Case Study 2
At a distribution substation, RFI measurements were undertaken to survey the condition of each of the oil-filled circuit breakers making up a typical 11kV distribution switchboard configuration commonly found in the UK. A high percentage of 11/33kV switchboards have an installed age of over 25 years. They are subjected to various types of duty plus a varied level of maintenance. The trend is to extend the maintenance period for medium-voltage (MV) switchgear, which in turn creates the need for interim non-intrusive condition monitoring techniques to offer confidence in the equipment’s safety and reliability.

A baseline RFI scan was captured in an adjacent room away from the surveyed switchboard. Measurements at the rear of each circuit breaker were captured and compared with the baseline. The observed uplift of frequencies indicated a nearby discharge source, which was eventually triangulated to one particular circuit breaker by comparing the uplift in higher frequencies while moving the receiving antenna along the rear of the switchboard. Further RFI measurements were captured at the front of the switchboard. A comparison of the front and rear RFI measurements shows that the uplift in the lower frequencies was strongest to the front of the unit. These tests were followed by complementary EMI measurements to gather more information. 

RFI Peak Measurements: Front and Rear of Circuit Breaker
Legend: Front, Rear

The HFCT uses inductive coupling to detect PD pulses flowing to earth and is capable of picking up both local PD in the cable end box and also the lower frequency PD pulses coming from down the cable. The results of this method confirmed the observations from the RFI survey, with uplifts of up to approximately 50dB at 75MHz and 40dB at 200MHz. Time-resolved measurements also showed pulse behaviour is similar to those obtained from RFI measurements (FIGURE 6).

Lower Frequency ( circa 50MHz)
Legend: RFI, HFCT, TEV

Mid Frequency (circa 150MHz)
Legend: RFI, HFCT, TEV

Higher Frequency (circa 200MHz)
Legend: RFI, HFCT, TEV

The placement of HFCTs provides a means to trace the likely source of the signals by comparing the uplift in frequencies. The uplift reduces significantly as the location of the HFCT is moved away from the suspect circuit breaker. Repeated measurements on earth straps placed on adjacent circuit breakers indicate the circuit breaker identified is the source of the measured discharge activity.

The most advantageous setup for metal-clad switchgear is to use an HFCT sensor in conjunction with a TEV sensor. Transient Earth Voltage (TEV) measurements work on the principle that if a PD occurs within metal clad switchgear, electromagnetic waves escape through openings in the metal casing. The electromagnetic wave propagates along the outside of the casing generating a transient earth voltage on the metal surface. TEV sensors are “capacitive couplers”, which when placed on the surface of metal cladding can detect TEV pulses as a result of PD internal to the switchgear.

Observed peak TEV measurements on the main circuit breaker tank reach 0dBm at a frequency of 100MHz. Comparative measurements taken with the TEV sensor located on the cable end box show a reduction in uplift of approximately 20dB. The main circuit breaker tank is identified as the likely source of the discharge. Time-resolved measurements show pulse behaviour confirming the results obtained from both RFI and HFCT measurements.
The utility opened up the circuit breaker and found signs of carbon at the cable end in the main tank of the switchgear. Results of this study confirm that deploying frequency spectra measurements and time-resolved patterns from RFI, HFCT and TEV probes can be used to pinpoint PD issues within switchgear. Using TEV sensors in conjunction with RFI surveillance on metal clad switch gear offers an additional capability in confirming and localising the partial discharge source.

RFI monitoring offers, and has proven to be, a routine non-invasive and cost-effective surveillance technique that complements and provides added value to other well established HV asset monitoring techniques such as thermal imaging and DGA analysis. As the practical examples illustrate, measurements logged with an RFI instrument platform specifically designed for substation surveillance can assist in effective discrimination and recognition of the RFI emissions radiated from potential sites of insulation deterioration.

There are great benefits of combining the assessment of RFI emissions with targeted deployment of other complementary non-invasive electromagnetic interference (EMI) detection techniques using the same RFI instrument platform. The deployment of both ‘far field’ and ‘near field’ probes provide a diversity of sensors, which is of particular importance with complex HV apparatus such as transformers where the propagation paths for RFI are less well defined.

This article is based on the paper Substation Surveillance Using RFI and Complementary EMI Detection Techniques, which was recently presented at the 78th International Conference of Doble Clients in Boston, Massachusetts USA. The paper was written by Alan Nesbitt, Brian Stewart and Scott McMeekin of Glasgow Caledonian University and Kjetil Liebech-Lien and Hans Ove Kristiansen of Doble Engineering Company.

Part 2 of this article will appear in the June 2011 issue of Electrical Review.

Arcing faults can be quickly detected and cleared using the Falcon Arc Detection System from CEE Relays. Clearing arcing faults more quickly reduces the incident energy of the fault. The incident energy at each busbar and required personal protective equipment (PPE) can be calculated using the Arc Flash Evaluation module of the Power*Tools for Windows (PTW) power system analysis software, helping engineers modify protection settings and the network configuration to reduce the incident energy. Reducing the incident energy reduces the risk to personnel and the expensive downtime due to the damage caused by arcing faults.

Newly announced by APC by Schneider Electric, a global leader in integrated critical power and cooling services, the MGE Galaxy 300 UPS system provides a compact, simplified and reliable solution for protecting small and medium businesses, commercial buildings and technical facilities.  It offers reliable power protection and a robust and easy to install system at the best price to performance ratio.

The new 3-phase UPS is a high availability solution which provides a wide input voltage range for harsh electrical environments; on-line double conversion topology for true isolation between input and output with zero transfer time; parallel capability to increase system redundancy and dual mains feed input for installation of one or two independent power sources.

With the deadline for the final phase of the incandescent lamp replacement directive due at the beginning of next year, Marie Parry from Click Scolmore, looks at the issues surrounding the replacement of the traditional light bulb

When it comes to industrial energy management, there are certainly a lot of hurdles to overcome; energy being the largest expense for many industrial facilities. According to the U.S. Department of Energy, consumption by manufacturers worldwide is projected to increase by 75% between 2010 and 2030. In addition, new Government and industry initiatives will create more difficult energy-management challenges for manufacturers explains Josh Olive, senior product specialist, Power Control Business, Rockwell Automation

In a two-year study involving customer projects around the world, Powervar, a specialist in power management systems, examined how power quality technology can significantly reduce the service burden rate, delivering cost savings and a measurable return on investment (ROI).  Here, Powervar UK Country Manager, Rob Morris, talks about the study, and outlines the business case for power conditioning

Most organisations today recognise power quality is an issue when it comes to the detrimental effect of power disturbances, such as electrical noise and voltage impulses, on sensitive electronic systems. The problem, however, is in accurately calculating figures that demonstrate the financial downside of dealing with bad power. Or simply put, how can you establish the ROI when selecting from different power protection systems?
For many organisations, power quality problems tend to be ‘out of sight, out of mind’. While the frequency of spikes, surges and other phenomena in power distribution is generally understood and accepted, many fail to make the connection between these irregularities and the impact to the bottom line.


At a distribution substation, RFI measurements were undertaken to survey the condition of each of the oil-filled circuit breakers making up a typical 11kV distribution switchboard configuration commonly found in the UK. A high percentage of 11/33kV switchboards have an installed age of over 25 years. They are subjected to various types of duty plus a varied level of maintenance. The trend is to extend the maintenance period for medium-voltage (MV) switchgear, which in turn creates the need for interim non-intrusive condition monitoring techniques to offer confidence in the equipment’s safety and reliability.

Taking a ‘joined up' approach to factory, plant or utility security can help significantly reduce your risk, explains Bradford H Hegrat, CISSP, CISM, senior principle security consultant, Rockwell Automation

Whether your company is considered part of the UK's ‘critical infrastructure' or not, the consequences of a malicious security breach could reach catastrophic proportions. When investigating the potential repercussions of a successful attack for a cement company we learned a miniscule change to the batch – minor enough in fact for it still to pass two levels of testing - could result in a concrete application that was inherently unusable for its intended application. If this concrete was intended for a large building foundation, for example, the forces involved by the time you reached the fifth floor of construction may be enough to bring the whole lot down.