Critical Interrelations Between ICT and Electricity System

Abstract

The widespread blackouts of 2003 have exposed the critical role of ICT systems in maintaining reliable operation of power systems. Fundamental errors in providing back-up and alarm function in the control room were one of the main contributing factors to the 2003 USA/Canada blackout. The lack of proper ICT infrastructure to enable proper communication and cooperation between system operators in Italy and Switzerland led to delayed remedial actions and the consequent blackout of Italy in 2003. Improved ICT systems would enable a better real-time cooperation and coordination between utilities in an interconnected power system but the main challenge is political: overcoming resistance of individual utilities to give up partially their interdependence and operate within the paradigm of a distributed, but coordinated, control. Emergence of GPS-synchronised Wide Area Measurement Systems (WAMS) holds a great promise for improved monitoring and control of modern power systems and therefore avoiding future blackouts.

Appendices

Appendix 1: Maintaining Reliability of an Interconnected Power System

A control area is a geographic area within a large interconnected network in which a system operator (SO) balances generation and loads in real time to maintain reliable operation. Control areas are linked with each other through transmission interconnection tie lines. Close cooperation between system operators is required to support the reliability of their interconnection. There are approximately 140 control areas in North America while in Europe a control area usually means a single country although larger countries may be divided into more control areas (as, e.g. Germany). In the USA, reliability coordinators are responsible for coordination between a number of SOs controlling different control areas.

ICT system are fundamental for maintaining power system reliability. System operators look at potential problems that could arise on their systems by using contingency analyses, driven from state estimation, that are fed by data collected by the SCADA system.

SCADA: System operators use System Control and Data Acquisition systems to acquire power system data and control power system equipment. SCADA systems have three types of elements: field remote terminal units (RTUs), communication to and between the RTUs, and one or more master stations. Field RTUs, installed at generation plants and substations, are combination data gathering and device control units. They gather and provide information of interest to system operators, such as the status of a breaker (switch), the voltage on a line or the amount of real and reactive power being produced by a generator, and execute control operations such as opening or closing a breaker. Telecommunications facilities, such as telephone lines or microwave radio channels, are provided for the field RTUs so they can communicate with one or more SCADA master stations or, less commonly, with each other. Master stations are the pieces of the SCADA system that initiate a cycle of data gathering from the field RTUs over the communications facilities, with time cycles ranging from every few seconds to as long as several minutes. In many power systems, master stations are fully integrated into the control room, serving as the direct interface to the Energy Management System (EMS), receiving incoming data from the field RTUs and relaying control operations commands to the field devices for execution.

State Estimation: System operators must have visibility (condition information) over their own transmission facilities, and recognize the impact on their own systems of events and facilities in neighbouring systems. To accomplish this, system state estimators use real-time data measurements (real and reactive power flows, the state of switches) available on a number, but not all, of transmission lines, substation and other plants. This information is fed to a mathematical model of the power system to estimate voltages and real and reactive power flows throughout the system.

Contingency Analysis: A power system must be able to withstand on its own, i.e. without intervention of the system operator, impact of probable events (such as tripping of lines or generators) that are referred to as contingencies. The most common criterion used is “N-1” contingency which means that a trip of a single element should not result in overloading of power system elements, loss of stability or voltage violation. This gives SO time to adjust operation should a contingency happen. Contingency analysis is run regularly by SO based on the current system operating conditions as identified by the state estimator.

Appendix 2: Wide Area Measurement Systems

Wide area measurement systems (WAMS) is a measurement system based on transmission of analogue and/or digital information using telecommunication systems and allowing a synchronisation (time stamping) of the measurements using a common time reference. Measuring devices used by WAMS have their own clocks synchronised with the common time reference using satellite GPS (global positioning system).

4.1.1 WAMS and WAMPAC Based on GPS Signal

The satellite GPS system is the result of many years of research undertaken by US civil and military institutions aiming to develop a very accurate navigation system. The system has been made available for civil users around the world.

The accuracy of the GPS reference time of about 1 μs is good enough to measure the AC phasors with frequency 50 or 60 Hz. For a 50 Hz system, the period time corresponding to a full rotation corresponding to 360° is 20 ms = 20 × 10³ μs. The time error of 1 μs corresponds to the angle error of 360°/(20 × 10³) = 0.018°.i.e. 0.005%. Such an error is small enough from the point of view of phasor measurements.

The possibility of measuring directly voltage and current phasors in a power system has created new control possibilities:

• Monitoring of operation of a large power system from the point of view of voltage angles and magnitudes and frequency. This is referred to as wide area monitoring (WAM).

• Application of special power system protections based on measuring phasors in large parts of a power system. Such protection is referred to as wide area protection (WAP).

• Application of control systems based on measuring phasors in large parts of a power system. Such control is referred to as wide area control (WAC).

Wide area measurement systems (WAMS) integrated with wide area monitoring (WAM) and wide area protection (WAP) and wide area control (WAC) is referred to as wide area measurement, protection, and control (WAMPAC).

Recent years have seen a dynamic expansion of WAMPAC systems. Measurement techniques and telecommunication techniques have made a fast progress but the main barrier for the expansion of WAMPAC system is a lack of WAP and WAC algorithms based on the use of phasors. There has been a lot of research devoted to that problem but the state of knowledge cannot be regarded as satisfactory.

4.1.2 Structures of WAMS and WAMPAC

WAMS, and constructed on their basis WAMPAC, may have different structures depending on telecommunication media used. With point-to-point connections, the structure may be multi-layer when PMU data are sent to phasor data concentrators (PDC). One concentrator may service 20-30 PMUs. Data from concentrators is then sent to computers executing SCADA/EMS functions or WAP/WAC phasor-based functions. An example of a three-layer structure is shown in Fig. 4.7.

Fig. 4.7

An example of a three-layer structure of WAMPAC. PMU - phasor measurement unit, PDC - phasor data concentrator, P&C - protection and control based on phasors

In each stage of data transmission, delays are incurred. Concentrators in the lowest layer service PMUs. As the delays are the smallest at that stage, the concentrators may supply data not only for monitoring (WAM) but also for protection (WAP) and control (WAC).

The middle-layer concentrators combine data from individual areas of a power system. The data may be used for monitoring and for some WAP or WAC functions.

The top, central, concentrator services the area concentrators. As at that stage the delays are the longest, the central layer may be used mainly for monitoring and for those SCADA/EMS functions that do not require a high speed of data transmission.

The main advantage of the layered structure is the lack of direct connections between area concentrators. Such connections may make it difficult, or even impossible, to execute those WAP or WAC functions that require data from a number of areas. The only way to get access to data from another area is via the central concentrator which incurs additional delays. That problem may be solved by adding additional communication between area concentrators. That leads to more complicated communication structures as more links are introduced.

Computer networks consisting of many local digital area networks (LAN) and one wide area digital network (WAN) offer best possibilities of further WAMPAC development and application. Such a structure is illustrated in Fig. 4.8. LAN services all measurement units and protection and control devices in individual substation. The connecting digital wide area network (WAN) creates a flexible communication platform. Individual devices can communicate with each other directly. Such a flexible platform may be used to create special protection and control systems locally, for each area, and centrally. The platform could also be used to provide data for local and central SCADA/EMSs.

Fig. 4.8

WAMPAC structure based on a flexible communication platform