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Measurement Challenges identified in the Strategic Research Agenda (SRA)
The excerpts below are linked to question 9 of the 2020 EMN for Smart Electricity Grids stakeholder survey.
Metering for billing purposes has always been crucial for fair trade and customer confidence. Conventional electricity meters have been based on the Ferraris concept for many decades, a very reliable concept based on a purely electro-mechanical transducer relating the metered electrical energy to counting the number of revolutions of a disc. Electronic meters use current sensors based on Rogowski coils, shunt resistors, Hall-effect magnetic sensors or current transformers. They have therefore no moving mechanical elements, but can rather be seen as an electronic board with sensors, a micro-processor and an interface port.
Smart meters are electronic meters offering the possibility to record detailed consumption and two-way communication between the meter and the measurement infrastructure, either by wireless link (mobile networks, radio) or physical link (Ethernet, fiber optic, power line carrier - PLC). They operate in conjunction with a gateway or a data concentrator on the other side of a two-way communication scheme. While a smart meter has to fulfil metrological requirements, it is confronted, along with the gateway and data concentrator, with various degrees of IT security requirements, which are subject to non-harmonised national legislation.
The current immunity requirements of MID for electricity meters have been put into question recently. Electricity meters might be subject to much more electro-magnetic interference today. Some electronic meters have shown vulnerability to these under specific circumstances. Research is underway to understand what types of meters are more immune to these interferences and to support the revision of European and international standards for electro-magnetic compatibility.
The interest in DC metering is growing owing to solar PV energy generation, fuel cells, electric energy storage, transport systems, electric vehicles, power distribution in IT networks and data centres, to name a few. The main challenge is the development of metrologically sound harmonised legislative frameworks possibly following similar principles as for AC active energy meters.
Issues with the quality of the electric supply have been known since the beginning of electrification. The advent of power electronics and more recently of inverters in connection with the multiplication of renewable energy sources mean an increase of non-linear loads and sources connected to the distribution grids. This produces harmonics of the 50 Hz sine waveform and, together with a wide range of other disturbances, can pose a risk to the safe operation of the grids. Hence, Power Quality is sometimes referred to as the set of limits of electrical properties that aims at ensuring that electrical systems function in their intended manner without significant loss of performance or breakdown. Monitoring both the current and voltage contribution to Power Quality allows to prevent outages or damages on the one hand, or to analyse issues in retrospect. The European standard EN 50160 specifies Power Quality in low- and middle-voltage grids, whereas the IEC standards IEC 61000 4 30, 4 7 and 4 15 define power quality quantities and methods.
Power Quality is analogue to electromagnetic compatibility but limited to 9 kHz. Disturbances of significant levels have been observed up to 500 kHz: supraharmonics up to 150 kHz and effects owing to narrow-band power line communication (PLC) up to 500 kHz. The low-voltage grid impedance is influenced by the impedance of the devices or equipment connected to it, and as such is frequency dependent. This varying impedance has an impact on the grid stability, but also on the reliability of PLC signals. Even today, the experimental instruments and methods available to precisely measure the line impedance are limited. Furthermore, the various proposed methods tend to yield incompatible results. There is a need to establish a metrological traceable grid impedance standard, in order to be able to compare different measurement techniques and open the road towards standardisation.
Some of the harmonic content of the power waveform is transferred to different voltage levels through power transformers. The instrument transformers to monitor current and voltage at power stations are designed for a nominal operation at 50 Hz and generally have an unknown frequency characteristic. It is assumed that some of the harmonics are transferred to the next voltage level, but this cannot be traced due to the inadequacy of instrument transformers. Therefore, these harmonics are not accounted for, leading to uncontrolled parasitic power losses and a risk of premature aging of some sensitive components with limits designed for 50 Hz nominal operation. Typical components affected by harmonic energy content are transformers and shunt reactors, but this issue affects asset management more generally. Understanding the propagation of harmonics is an important challenge helping to prevent detrimental effects. This requires the characterisation of the frequency transfer function of instrument transformers (see chapter 4.4 Digital substations).
Grids which are weakly coupled to the main grid infrastructure, e.g. in railway infrastructure, large ships, electric vehicle charging stations, sometimes operate at different frequencies (DC, 16.7 Hz) with compatibility requirements at interconnection or border nodes. In railway grids, transients and in-rush currents need to be monitored closely in order to maintain voltage regulation, inverters produce high levels of harmonic distortion and meters need to be able to handle various frequency systems. Neither commercial power quality analysers nor standards comparable to IEC 61000-4-30 have been developed for these specific applications so far.
Future electrical power grids will require real-time control and monitoring systems to face increasingly complex and challenging conditions. Digital instrumentation will slowly substitute conventional analogue instrumentation. New standards in the IEC 61869 series address the digital communication of electronic instrument transformers, as well as stand-alone merging units (SAMUs), digitisers for analogue instrument transformers. Following the introduction of these new standards, the transition from traditional analogue instrumentation towards the new digital instrumentation technology is expected to gain speed, both on transmission and on distribution level. To support this change, new metrological tools and methodologies are needed, as test systems for new technology and test systems to prove performance of intelligent electronic devices, like digital energy meters or real-time critical all-digital PMUs.
To ensure synchronism between digitally equipped substations, accurate, secure and reliable time synchronisation in a wide area is necessary. This can usually be achieved by using global navigation satellite systems (GNSS). However, satellite-independent time dissemination and synchronisation, based on PTP or White Rabbit methods are required to provide reliability of timekeeping in the mission critical substations.
More precise synchronization is needed within substations for SAMU timing. Providing traceable linking of timing of PTP and PPS signals is a challenge, as well as the precise timing of SAMU sampling using PTP protocol.
Large-scale roll-out of smart meters is planned or already going on in several European countries. The resulting network is an internet of things of devices requiring a high level of IT security to prevent malevolent coordinated intrusions from destabilising the grid control.
Instrument Transformers and Sensors
The safe operation and regulation of electrical grids require a large number of grid sensors to monitor voltage and current at key grid nodes. High voltage and current are sensed through instrument transformers, high accuracy electrical devices, which scale the grid voltage and current to fit the input levels of measuring instruments and secondary control circuitry, with the advantage of ensuring their galvanic isolation. The primary winding of the transformer is connected to the high voltage or high current circuit, and the measuring instrument is connected to the secondary circuit. Most instrument transformers are inductive, wire-wound transformers using an electromagnetic principle, but capacitor voltage transformers use a capacitor potential divider for use at higher voltages. Traditionally, traceability for instrument transformers is established for pure sine waves and at 50 Hz only. The presence of harmonics can impact the measurement accuracy of an instrument transformer, but this effect is not taken into account by the traditional calibration carried out at power frequency only. The limited measurement bandwidth and the lack of traceability for frequencies other than 50 Hz limits the possibility to analyse harmonic signals and interferences.
Other wideband low power output passive or electronic instrument transformers, which operate on different principles, such as Rogowski coils and dividers, are now commercially available. Instrument transformers based on magneto-optical or electro-optical effects in an optical fibre offer significant advantages over inductive and capacitor instrument transformers. Their bandwidth is much larger and their size is considerably smaller. Since the optical fibre is an electrical insulator, they are inherently decoupled from the power lines and almost immune to electromagnetic interference. Electronic instrument transformers permit to record a large number of dynamic parameters and they are usually fitted with digital outputs compliant with IEC 61850 and other standards making them compatible with digital substations (see chapter 4.4 Digital substations).
Grid monitoring & data analytics
Monitoring of transmission grids
The stability of the grid requires sophisticated interconnected control loops. Monitoring the parameters such as frequency, voltage, phase is thus key to avoid shutdowns. If production exceeds consumption, the frequency increases, and vice versa. A fine balance must thus be struck for active power in order for the frequency to remain constant. The reactive power must be similarly well balanced to keep the operating voltage constant.
The grid control relies on a Supervisory Control and Data Acquisition (SCADA) system which measures power and voltage at key locations of the grid. Thanks to this infrastructure, energy flow in all parts of the grid can be calculated. The deployment of Global Navigation Satellite Systems made it possible to achieve high synchronisation of the measurements. Phasor Measurement Units (PMU) enable an accurate measurement of voltage and current amplitude, phase difference at different nodes relative to UTC (Universal Time Coordinated), frequency and rate of change of frequency (ROCOF). PMUs yield better state estimations with the possibility to observe long-distance oscillations with high refresh rate (up to 50 times per second compared to 15 minutes for SCADA). PMUs have been largely deployed across North America, to the contrary of Europe, following spectacular grid blackouts .
Monitoring of distribution grids
The variability, and to some degree also the information density, of the distribution grids increases with the advent of more and more renewable energy sources. One of the motivations of the large-scale deployment of smart meters is to provide fine geographical and time-resolved information to the utilities. This explosion in available data requires big data analytics in order to convert data to actionable information.
Sensors are used to measure network current, voltage and frequency, with this data aggregated to form a view of the overall network state. However, distributed generation will need distributed sensor deployments. Methods for optimising sensor placement, the use of phasor measurement units (PMUs), and state estimation using aggregated smart meter data are just a few examples to improve network management beyond the present SCADA systems that are commonly in use. As an example, a 50 kV distribution network in the south-west part of the Netherlands was used to provide real data for comparing state estimation algorithms applied to PMU data with SCADA data. The grid was equipped with a SCADA system already, whereas PMUs have been installed during the recent decade as additional monitoring devices. The PMUs can be used to provide much more information on a much denser time scale, such as the rate of change of frequency (ROCOF), grid inertia from frequency and ROCOF, synthetic inertia, detection of sub-synchronous oscillations, fault location identification, dynamic line rating and remote instrument transformer calibration. To what degree and to which scale the granularity of PMU installation is useful in distribution grids is the subject of further research. For shorter monitored scales, observing amplitude and phase differences between different locations requires improved voltage and current accuracy as well as a higher degree of synchronisation.
Conventional power grids, typically equipped with centralized SCADA systems, receive state information from many substations only once every 15 minutes. Obviously, accurate timing for such measurements is not crucial. However, future electrical grids will require real-time capable control and monitoring systems on sub-station level to ensure stability under increasingly complex and challenging conditions. The associated digital high voltage sensors and digital metering systems must be managed through accurate, secure and reliable time synchronisation in a wide area, both within and between substations. This has been achieved using GPS where state-of-the-art IT security technologies, in some cases supported by independent-back-up systems, are necessary to protect against jamming and spoofing.
Modelling and data analytics
PMUs deployed by grid operators provide significant potential for the real-time monitoring of abnormal grid dynamics and post-mortem fault analysis. Significant data volumes are generated. There is a need for appropriate visualisation and for big data analytics in order to convert these data into actionable information for grid improvement and maintenance to avoid repetition of issues.
Network operators are interested in the detection of abnormal events in response to faults or changes to system dynamics. Data analytics techniques can be used to detect anomalies and atypical behaviour in power system operation and facilitate new alarm metrics for control room staff and protection systems. An example of grid instability is the build-up of oscillations in power systems due to the increasing difficulty of convertors locking onto a stable grid frequency and their intrinsic sensitivity to abnormal events, hence the need for early warning indicators based on fast data analytics. Another example is the change in grid inertia due to the relative increase of distributed generation with respect to traditional generation. Measurement and control of grid inertia is one of the most important issues facing system operators in future energy scenarios.
PMU data could thus also be used to dynamically manage power flow in networks. As high levels of renewable energy sources and electrical vehicles are installed, parts of the grid are overloaded for short periods of supply and demand. Investing in the development of data analytics to manage power flow and rating management and consumption could result in lower investments in hardware related to rating over-dimensioning or substation reinforcement, and consequently enhance penetration of renewable energy sources.
Modelling, for instance of virtual power plants for prediction before integration in a smart grid, plays an increasing role in planning phases.
Much expectation is placed in smart grids for achieving higher efficiency in electric energy consumption, for the most part through enabling a better power management of energy utilities and consumers.
Technical energy losses are due to energy dissipated in transmission and distribution lines, transformers, converters and inverters, and are either permanent or variable, i.e. varying with the amount of electricity distributed.
Characterisation methods for wasted energy and energy efficiency of converters (rectifiers and inverters) still need development. Evaluation of efficiency has two major aspects: on the one hand, total input power versus useful power. The difference being the loss is best measured at fundamental frequency only. On the other hand, identifying during product development exactly where losses occur necessitates accurate wide-band measurement of active power. This can be exemplified by the case of an HVDC substation. The AC grid will supply AC power at fundamental frequency. The HVDC converter inevitably creates harmonics in its operation. If not completely filtered, these harmonics will be injected back into the AC grid causing power loss in the grid. Measuring converter input AC power with a wide-band measuring system will then measure the power of the fundamental drawn from the grid minus the power of the harmonics re-injected into the grid, causing losses elsewhere, leading to an optimistic figure on efficiency.
Evaluation of converter efficiency requires support from an accurate measurement of power in a wide frequency range in presence of highly distorted voltage and current waveforms. These characterisations methods must account for the specific final application and actual working conditions, including non-stationary situations. The complexity of the required measurements, combined with the lack of comprehensive standards or metrological traceability offered by the NMIs, lead to declared efficiency values that are neither traceable nor obtained by standardised procedures for accuracy evaluation.
Storage systems have been the preferred approach to mitigate the demand vs. supply with increasing shares of renewable energy in the distribution network. Electric vehicle fleets can potentially serve the electrical grid as an independent distributed energy source, by delivering the energy stored in their batteries according to the concept of vehicle to grid (V2G). In both cases, evaluating the efficiency of the storage system involves measurement of DC and AC power under highly dynamic and distorted conditions.
In the production of equipment for high voltage grids, dielectric testing is performed to verify that the equipment can withstand the operational environment, including high voltage and high current impulses. Methods and schemes for traceable calibration are defined in IEC 60060-2 for high voltage and in IEC 62475 for high current. However, system voltages are currently increasing to levels higher than those covered by this standard, and there is a need to extend the traceability of the test methods into the ultra-high voltage range above 800 kV.
The expansion of UHV grids, now operating at 1100 kV system voltage for DC and 1200 KV for AC, requires testing with voltages up to 2000 kV and traceability of DC and AC signals established up to 1000 kV. For switching and lightning impulse measurements, it is necessary to study impact on measurements due to proximity effects, corona, front oscillations, divider topology and measuring cables. The highest test voltages surpass 2500 kV for lightning impulse testing, 4000 kV for extreme cases, and the traceability is typically available up to 700 kV. New methods need to be developed to linearly extend traceability further. Large measurement systems are strongly affected by corona and proximity effects, and generally methods to handle wave shape distortions, like front oscillations, and losses in measurement cables need a revision. Providing traceability for these measurements is especially challenging in the case of impulse voltages above megavolt level. Traceability is also lacking for voltage dividers and measuring systems for composite and combined voltage tests. During these tests, a high impulse voltage is applied to the test object in addition to continuous high AC or DC voltage.
HV transformers and reactors
Loss measurements on large transformers and reactors are performed using complex measuring systems that rely on extremely precise voltage and current transducers connected to advanced power meters. For large power transformers it is necessary for manufacturers to measure the active power with an uncertainty of better than 3 % at a power factor that may be 0.01, which leads to an accuracy requirement of 0.03 % of the apparent power. Therefore, the calibration of such measuring systems at the manufacturer’s site should be done with a level of accuracy that is improved by at least a factor of 3. Individual component calibration is only partly suitable for the calibration of such systems and at present there are no calibration facilities in Europe that provide a calibration service for this purpose with sufficient accuracy (i.e. uncertainty smaller than 0.01 % in ratio or 100 rad in phase).
High voltage components such as cables, insulators, instrument transformers, capacitors or surge arresters require thorough testing, which typically includes - in addition to measurement of withstand voltage - measurement of loss factor, insulation resistance and partial discharge. Non-destructive testing methods are also required for commissioning or preventive maintenance of large equipment of installations such as power transformers, installed overhead lines and cables, high voltage substations or HVDC converter stations. On-site testing brings about severe logistical and technical challenges with complex interconnection schemes. For instance, high-capacitive test objects such as power cables, generators or capacitors can be tested after their installation on-site using very low frequency technique (VLF) down to 0.1 Hz.
DC Grids and Applications
Over the last two decades, a paradigm shift in our way of dealing with energy generation and consumption has increased the attractiveness of local DC grids as an extension to traditional AC distribution networks. Renewable energy sources (RES) such as wind and solar energy are becoming more and more reasonably priced, and consequently, distributed generation is growing. Simultaneously, LED lighting has shown to be a much more efficient way of illumination compared with the old-fashioned incandescent lamps and have taken over the market very rapidly. Many of these sustainable technologies are fundamentally DC, requiring power inversion to connect to the AC grid. Furthermore, storage systems such as batteries and supercapacitors are intrinsically DC, and electric vehicles (EV) and all electronic devices operate on DC power. Therefore, there is a realisation amongst grid operators that utilising local low voltage DC (LVDC) grids will lead to less energy is wasted in the conversion process. Investigations are needed to determine to which extent many promises of DC grids can be fulfilled, like e.g.: losses can be reduced by means of localisation, voltage drops can be improve, the number of substations can be reduced, the management of reactive power and PQ can be improved, implementation of renewable energy sources is made more simple, distribution losses are reduced, etc.
For DC grids, PQ issues such as ripple, inrush currents, voltage fluctuations and short circuit events, are different in nature from those in AC grids in terms of dynamics, duration, and magnitude. Therefore, there is a need for metrology support to obtain proper PQ definitions, a practical measurement guide and realistic and well-defined PQ limits for DC power systems. Since the nature of PQ in DC grids is currently unclear, on-site measurements must be performed in real LVDC trial grids to determine which disturbances have the highest influence in terms of losses, inconvenience to customers, or potentially damaging to grid equipment and other connected loads. Such grid measurements should preferably cover a variety of representative consumer and producer connection types, such as solar panels, windmills, EV charging stations, battery storage systems, industrial and household applications, and different grid topologies, with voltage and current levels up to at least 1 kV and several hundreds of amperes respectively. The measurements should be performed with target uncertainties below 0.1 % considering the presence of AC ripple and other disturbances. Special measurement equipment and methodologies are required to conduct the required surveys for setting compatibility levels. This same equipment will be the basis of future “planning level” surveys which will be carried out by utilities to manage the PQ levels in future DC networks.
A second important issue regarding DC grids is the accurate measurement of power and energy for billing purposes. In most countries, electricity meters are type tested with respect to standards issued for AC grids only. Therefore, there is a need to investigate additional specific metrological aspects of DC meters, which should be included in a future revision of this standard. Examples of such aspects are magnitudes of ripple currents and voltages existing in range up to tens of kilohertz, the immunity of DC energy measurement against such ripples, how to measure the energy contained in such ripples, the losses due to cables, etc.
Traceability is an essential ingredient to customer confidence for the emerging DC grids but is presently non-existent for DC power and DC PQ, and not even defined yet as a classified service category in the context of the CIPM MRA.
Seamless grid integration of traditional generation, renewables and storing technologies is key to address the challenges posed by decarbonisation, decentralisation and digital transformation. The key objective is maintaining grid stability while taking into account new supply and demand concepts, new power surplus and shortage patterns, new business models affecting consumption habits. In order to underpin grid stability and reliability requirements, sector coupling becomes a necessity, as do new storage and conversion schemes. Also to be considered are stronger interactions with other grids, for instance railway and electric vehicle grids, battery grids composed of domestic and distribution solutions, novel storage concepts such as Power-to-X.