As generation and distribution systems have grown ever more complex, so the monitoring and control systems have grown more sophisticated with a host of acronyms covering every stage.
Each has been developed in response to particular needs expressed by the utility and industrial power companies running the systems.
Many systems were hard-wired to display boards giving a graphical overview of part of a system, but while they are able to give alerts when something goes outside pre-set limits, they don’t collect and collate sufficient data for controllers to see a situation developing, nor retain historical data to enable past events to be analysed with a view to preventing a recurrence.
Power generation – handling thousands of points from hundreds of devices
American Electric Power (AEP) operates a hydro-electric pump storage power plant on the Roanoke River, Virginia. The Smith Mountain power plant has five generating units with a total capacity of 605 megawatts. The system monitors for some 500 alarm conditions and previously displayed on seven hard-wired panels. A central monitoring station 45 miles away covering all of AEPs hydro plants in the area would receive notification of an alarm at a plant, but no details.
AEP have installed an ethernet-based alarm annunciator and a CitectSCADA monitoring and control system with Sixnet EtherTrak I/O modules, Sixnet RemoteTrak Serial I/O modules and a Sixnet intelligent ethernet switch communicating via Open Modbus TCP.
CitectSCADA, a Windows-based SCADA system, from Citect Ltd (part of Schneider Electric) is capable of handling thousands of I/O points from hundreds of I/O devices.
It is also designed to be a data storage system, as well as an operator interface. With the new annunciator system, operators at the plant and the monitoring station in Roanoke share the same information regarding alarm status.
Using CitectSCADA, operators not only see which alarms are tripped in the remote location, they also know the sequence in which the trips occurred. The alarm history information is saved in both plain text and DBF files, allowing managers to review the logged alarm data to pinpoint problem areas which need addressing.
Plant operators are increasingly looking to reduce operating costs and improve plant availability by deploying M&D systems, capable of analysing the state of critical components enabling them to plan preventative maintenance strategies and avoid unexpected equipment failure. This is particularly true in older plants operating ageing equipment that is more likely to fail.
In the past, M&D systems were distributed systems that collected and analysed data from a particular piece of equipment. Today, there is a trend towards designing systems that cover many pieces of equipment from several different suppliers.
AMODIS (Alstom monitoring and diagnostics system) is an M&D system from Alstom is one such system. The PAMOS module is used to monitor partial discharges in the stator windings, ROMON II monitors the condition of the rotor and an HSGR module monitors the heat recovery steam generator. Other modules in use are generator rotor flux monitoring, gas turbine performance or gas turbine pulsation.
As with SCADA systems, M&D relies heavily on software to analyse and display data. All AMODIS modules send data to the same platform, having the information on an integrated platform, viewable on a single screen, allows operators to share and cross-reference data.
Power distribution – handling real-time data
One of the challenges faced by network operators is there are few monitors sending real-time data to the controller to let them know what is happening on their network. Traditionally utility companies deploy devices inside their substations, but beyond that the feedback is very limited.
When the system was based entirely around centralised generation this worked satisfactorily, but as more small scale generators and domestic micro-generation schemes are attached to the network it becomes imperative that managers really know what is happening everywhere, from the distribution sub-station to the individual property.
Adrian McNulty, Director, DMS Product Marketing at Ventyx (part of ABB), sees their Network Manager system as having three major components: SCADA to monitor and control the network, distribution management and outage management – the last two often being considered together as DMS.
Implementation varies around the world. Europe has in the past focussed on deploying SCADA solutions, whilst in the Americas Outage Management has been driving the deployment of computer based systems. Worldwide there is now a trend to integrate all of these into a single package. Ventyx call their product in this field Network Manager DMS.
Key to the system is a GIS (geographic information system) model incorporating the electrical characteristics of the network. Once that is established, data from a limited number of sensors out on the network is applied to the model which can then calculate what conditions must pertain elsewhere to give rise to the conditions that are being monitored.
Once that information is available it is possible to use other software algorithms to look at measures such as conservation voltage reduction (CVR)
Effective CVR can reduce demand by 2-4% at times when the network is under pressure, but earlier implementations using local controls or centralised control based on simple rules were hard to optimise and often ineffective. With model-based volt/var distribution companies are able to implement CVR without violating consumer voltage limits.
Domestic micro-generation, plans to use plug-in electric vehicles as power storage on the grid and sophisticated load shedding possibilities are driving the installation of ‘smart meters’ in more houses, creating an AMI system. Companies such as ABB are now looking to link data from AMI into DMS, thus increasing the amount of automation in substation control. Gradually, as all these technologies converge, we are seeing the emergence of a truly smart grid.