Hydro-Québec adopts advanced distribution automation applications and power-quality monitoring in its smart grid.
The increasing complexity and management of power systems, growing demand and service-quality expectations — for example, system reliability, efficiency and security — in addition to environmental energy sustainability concerns, have triggered the evolution of smart grids. Utilities are implementing new technologies in power systems, including renewable energy resources, distributed generation, and the latest information and communications technologies.
A successful power system management activity such as distribution automation (DA) relies on information collected by an integrated monitoring system. DA enables control center staff to monitor system operating conditions in real time and allows the automatic reconfiguration of the system to optimize its efficiency and reduce the impact and duration of outages.
As part of a plan to move toward a smart grid, Hydro-Québec has taken DA further and implemented advanced distribution automation (ADA) on its 25-kV overhead line distribution network.
ADA may be defined as a number of technologies that enable an electric utility to remotely monitor, coordinate and operate distribution components in a real-time mode from remote locations. The group of ADA technologies includes supervisory control and data acquisition (SCADA), volt and VAR control (VVC), fault location and feeder reconfiguration, or self-healing. In combination, this is known as fault location, isolation and service restoration (FLISR).
Although integrated power-quality monitoring is not regarded as a real ADA application, it can be easily integrated with automated applications. Hydro-Québec has established a road map toward a smart grid that includes monitoring the system to improve reliability, the equipment to improve maintenance and the product to improve power quality.
The utility also has introduced ambitious programs to achieve energy efficiency by installing capacitor banks and giving greater attention to voltage control. To reduce the duration of fault outages, Hydro-Québec has focused on fault location. Pilot projects were conducted to demonstrate the efficiency of these ADA system initiatives, and the company has evaluated the impacts on the distribution network and customers.
Volt and VAR Control
The VVC application is based on the conservation voltage reduction (CVR) concept, which is associated with having the customer's voltage at the lowest level consistent with proper operation of the equipment and within the levels set by regulatory agencies and standards organizations. Hydro-Québec aims to save energy by controlling the voltage level and managing the VAR power in the distribution network.
To fulfill this goal, the utility used a VVC system that requires permanent monitoring of the voltage level at the end of the distribution feeder and the installation of switching shunt capacitor banks along the length of the feeders. In 2005 and 2006, Hydro-Québec conducted tests at the Pierre-Boucher substation in suburban Montreal to determine the effectiveness of the CVR for energy savings and to evaluate the economic feasibility of this concept.
In the fall of 2008, Hydro-Québec Distribution commissioned a VVC system, named CATVAR, at the Pierre-Boucher substation to reduce energy consumption and distribution network losses. Basically, the voltage regulation system at the substation was replaced with an intelligent system that uses the network measurements to maintain a stable voltage level at the end of the feeder close to the lowest statutory voltage. The CATVAR system also analyzes the network's VAR requirements and is designed to switch the shunt capacitor banks on and off when required.
This pilot project had two goals: first, to determine whether maintaining a lower statutory-limit voltage would have an impact on the number of voltage sags experienced by customers and, second, to prevent the potential power-quality problems created by the switching operations of 1.2-MVAR capacitor banks. Electromagnetic transients program (EMTP) power system simulations were conducted, and the results were compared with real-time measurements made on the network.
The two common methods for locating faults are the voltage-drop fault location (VDFL) and impedance-based fault location (IBFL) systems. The former requires distributed power-quality measurements along the length of the feeder, while the latter relies on the impedance measured between the source substation and the fault position.
Hydro-Québec designed and developed Maintenance Intelligente de Lignes Électriques (MILE), a fault-location system based on VDFL technique that uses voltage and current waveforms from distributed power-quality measurements along the feeder. To date, the MILE system monitors eight distribution feeders.
The average absolute error of the MILE system is less than 200 m (656 ft). This error value reflects not only the accuracy of the numerical assessment, but also errors in the feeder characteristics database and inaccuracies in the actual distance evaluation.
Data, Data, Data
To function, ADA systems require information such as network voltage and current values. The CATVAR system measures the RMS values of current and voltage at the source substation and the RMS voltage at the feeder end in regular time intervals. The MILE system records current and voltage waveforms at different positions along the feeder when supply interruptions or voltage sags occur. The accuracy of these data acquisition processes critically impacts the efficiency and reliability of the two systems.
The CATVAR system requires voltage measurements at the source substation and the end of the feeder. A distribution substation transformer typically supplies three or four feeders. When one of the voltage-level monitoring devices at the end of these feeders is malfunctioning, the CATVAR system disables the voltage adjustment by the load tap changer (LTC). To avoid this problem, the CATVAR system could be equipped with an integrated management system based on state estimators. Enhanced state estimators require more information on the power flow and more voltage and current monitoring points.
The voltage-level reduction at the substation equipped with a CATVAR system reaches 2% to 4% of the reference setpoint. The dynamic adjustment of the setpoint of the transformer LTC supplying the feeders and the efficiency of the VVC system are critically dependent on the accuracy of the voltage measurements at the end of the feeders.
Data available from customer metering, which are RMS values over 15-minute periods, is not sufficiently sensitive for this application. For this reason, the monitoring devices used for the CATVAR prototype system were versatile intelligent three-phase meters, the ION8600 from PowerLogic.
To locate a fault, the MILE system uses sets of waveforms recorded by several monitoring devices distributed along the feeder, such as versatile intelligent three-phase meters. The VDFL algorithm synchronizes the voltage waveforms recorded by devices at three different positions and uses the corresponding voltage drop to determine the fault location.
The accuracy of the fault location was evaluated for different waveform sampling rates ranging from 4 samples per cycle to 128 samples per cycle. From the results, it was determined the 32 samples per cycle sampling rate provides a reasonably accurate fault location.
Hydro-Québec has proved the power system reliability in smart grids is increased, mainly because of fault-location and feeder-reconfiguration systems, which reduces the system average interruption duration index. It is expected power quality also is improved.
However, VVC systems — by reducing the voltage level at the substation and switching the shunt capacitor banks along the feeder on and off — have negative impacts on power quality. These system operations could generate additional sags and switching transients.
The outcome of the pilot project conducted by Hydro-Québec's Research Institute indicates the joint impact of the VVC system and voltage sags occurring on distribution systems can be technically characterized by two effects: the appearance of statistical sags (a voltage reduction from 2% to 4% due to the VVC-CATVAR system plus a voltage drop inferior to 10% that is a fault contribution, for a total voltage drop of 12% to 14%) and equipment malfunctioning or tripping (the joint contribution brings the residual voltage level below the critical threshold of 70% of the reference voltage). Based on the data analyzed from four monitoring sites, neither effect was critical.
The analysis of transients generated by shunt capacitor bank operation on three different feeders confirmed the switching-on transients were less than 1.16 p.u., whereas the switching-off transients were hardly detectable.
In smart grids, as specified in the ADA definition, distribution equipment is monitored, coordinated and operated in a real-time mode from remote locations. These activities are possible because of different communications links, which allow information to flow both ways between the remote system control center and equipment controllers. Meters and major distribution equipment controllers belonging to different ADA systems can be used as elements of an integrated power-quality monitoring system. This symbiosis between ADA applications and the power-quality monitoring activity is one of the advantages offered by smart grids.
These intelligent electronic devices (IEDs) include many available features:
Projecting the Future
Measurement of voltage, current, demand, energy, power factor and frequency
Harmonics, voltage and current plus total harmonic distortion
Voltage flicker (so far only on meters)
Symmetrical sequences and waveform capture
Communications interface and protocols
Multi-port (serial, infrared, Ethernet, modem)
Multi-protocol access (DNP 3.0, MODBUS)
The current trend in the industry is that IEC 61850 communications, applicable to equipment in substations, will be extended in the future to include distribution equipment. Hydro-Québec Distribution has planned the utility's vision of a smart grid on its road map for 2015 and beyond. According to the map, major distribution equipment controllers will be replaced by standardized IEDs, which will comply with IEC 61850 and comprise plug-and-play devices.
The accuracy of the data acquisition process is an important factor, critically affecting the efficiency and reliability of ADA systems and, furthermore, the efficiency and reliability of the distribution network. Remote control and surveillance of distribution equipment together with data acquisition are important aspects of the automation process. Combining the surveillance of distribution equipment with power-quality monitoring is an inspired and sound decision. There are several advantages of using power distribution equipment controllers and intelligent meters as elements of an integrated power-quality monitoring system:
IEDs are already connected to the network, either on the medium-voltage side or low-voltage side.
Devices are in constant evolution.
Communications links for data transfer are available (IEDs remotely controlled and meters belonging to the advanced metering infrastructure).
To date, intelligent meters have been developed more rapidly than controllers, but evidence suggests the evolution in meters will be replicated in controllers.
Francisc Zavoda (firstname.lastname@example.org) graduated from Bucharest Polytechnic Institute in 1979 and received an MSEE degree in 1995 from École Polytechnique de Montréal. He started working for ISPE Bucharest, a consulting company for the Romanian power department before joining the Siemens Canada in 1990. Zavoda joined Hydro-Québec's Research Institute in 1995 and is now a senior research engineer. He is currently responsible for or participates on projects related to power quality, smart grids and the advanced distribution automation program.
Hydro-Québec | www.hydroquebec.com
PowerLogic | www.powerlogic.com