By. J.C. McGough, P.Eng. and J.C. Fong, P.Eng.
In the past few years, a variety of utility oriented products, especially microprocessor-based digital devices with communication capabilities, have been introduced into substations. These digital devices include protective relays, fault recorders and metering units. It has become apparent that in order to make full use of this new technology, a means of collecting and organizing data is required locally in the substation. Such a system is now available using proven data acquisition and control technology.
This article describes the use of an application and technology enable software package together with a Programmable Logic Controller (PLC). This configuration provides the basis for building a wide range of real-time supervisory monitoring and logging, control and information management systems, including integration of data from protective relays and other Intelligent Electronic Devices (IEDs).
B.C. Hydro installed its first digital control section at Goward Substation on Vancouver Island in 1992. At that time there was a need for a substation-based system which could not only satisfy the needs of the day, but grow to meet information technology demands of the future. To date, B.C. Hydro has developed 20 such installations.
Substation Integration Concepts
The main features exhibited by the BC Hydro Integrated System are:
Data in Digital Form
Since IED outputs are in digital form, it is only sensible to maintain the data in that form. This is the format that is most easily communicated, stored processed, viewed and displayed. Digital format eliminates the need for expensive analogue processing devices and their inherent maintenance costs.
Eliminate duplication of Data
The goal here is simply to:
Information Networked between Multiple Devices
By means of a combination of master-slave and peer-to-peer communication between devices which share information and distribute commands.
Information Processed to Meet Varied User Needs
Examples of this concept can be best illustrated by examples:
Distributed Protection Systems
No control and information system can be allowed to compromise the protection functions. As well, the use of protection relays for local/remote and data acquisition cannot be allowed to prejudice the security of the protection.
The protection devices must remain independent of other functions despite communication status, network status or IED status.
Synchronized Clocks
Multiple, independent digital devices with internal clocks require a synchronizing source. This becomes obvious when attempting to correlate fault and event reports within and between stations. Today a variety of low-cost GPS receivers provide this facility with extremely high accuracy and stability.
Integrated Strategies
To apply the concepts described above to a particular utility system, strategies must first be developed. They must take into account the realities of the particular system, things like age, technology operational procedures, etc.
Some or all of the following strategies were used in implementing substation integration: (The extent to which they are applicable to others' systems will vary)
New Control and Data Acquisition Program
Today's systems are based on a decentralized open architecture consisting of intelligent electronic devices (IED's) linked together by a high speed local area network (LAN). This provides access to station information in a selective, organized manner, not only to SCADA, but also to various telephone line or corporate wide area network (WAN) users. The system architecture is shown in Fig. 1.
Data Acquisition System (DAS)
In today's installations, the DAS is required to:
During the years following the Goward installation, DAS system users have been identified. Further investigation with the participation of identified users has provided a clear idea of user requirements for a wide range of data and information. Data required by users and the reporting method include:
BENEFITS OF STATION INTEGRATION
The overall benefits fall into the following four general areas:
Reduced Capital and O & M Costs
There is considerably less hardware to install and maintain, but only if multifunction devices such as microprocessor-based protective relays and PLC's are applied. In the past, there was a tendency to provide "exclusive" solutions. By this we mean that each user was provided with equipment for their own exclusive use. Some metered quantities were measured three times. They could be displayed in two or more locations locally and remotely (SCADA). Each user had independent control; locally the operator was provided with trip/close access to the breaker separately from the protective device and again independently for remote control.
Today's integrated systems attempt to provide "inclusive" solutions. In any substation, trip/close access to the breakers is provided for the protection relay. This is basic and fundamental in any location. Today's protective relays go beyond the exclusive solution of providing protection. Access can now be made over communications interfaces to provide manual local and remote trip/close access to the breaker via the protective relay. Nothing could be more economic. This minimizes the amount of equipment needed.
The same applies to metered quantities. The vast majority of required data can be provided by today's protective relays and shared by all users over a high speed local area network (LAN).
The result is:
Enhanced Information
Because all data are in digital form and are shared from the source upwards, all users benefit. Information is provided on a much more timely basis, and raw data is processed at the substation before distribution. As well, information can be targeted to selected groups or individuals.
The user groups who benefit most from station integration include:
Automated/Adaptive Protection and Control
Coordination of PLCs, RTUs and digital relays can provide real time automation and control functions. These include:
The infrastructure created by station integration enables creative solutions to specific problems at least cost and effort.
New Challenges
Substation integration remains a challenge even with today's technology. But the lack of a standard for communications between digital devices remains the biggest challenge facing utilities. B.C. Hydro has persisted with their original solution using Modicon Modbus Plus (MB+) for the LAN protocol.
This has served us well and we plan to continue with its use. Besides MB+, we are planning to use Ethernet (TCPIP) in future installations where data transfer is excessive. This will be achieved by off-loading all data transfer functions onto Ethernet, retaining the robust MB+ for critical control functions. All the necessary hardware and software systems already exist to achieve this, we are prepared to retrofit any existing installation if data acquisition exceeds the capacity of the MB+ LAN.
Within any organization, change is inevitable. The effect of changing jurisdictional boundaries, reporting procedures, working relationships must be taken into consideration.
Finally, the need to continuously train both users and maintenance staff must be recognized and dealt with.
ACCESS TO SUBSTATION DATA
BC Hydro recently introduced a common, company-wide desk-top service (CDS) program. This has greatly facilitated individual access to station data in a predictable manner.
All BC Hydro staff have PCs with certain common software packages including:
We are also looking at providing station DAS access by Intranet where stations are connected to the corporate wide area network (WAN) and via Internet where only phone lines exist.
Today, enhancements in control software help reduce costs and increase revenues by better distributing real-time data throughout the organization. These features use the latest in Intranet/Internet technology together with the most stringent security requirements. Real-time production information is used more efficiently to speed up cycle/response times, improve quality of the product and reduce costs of application development and maintenance.
CONCLUSION
BC Hydro management's view for the "Horizon Network Structure" is that it should provide a total station management system to include power system condition monitoring, equipment condition monitoring, sharing of information, and expanded capability for monitoring and automation. The goal is to minimize expensive power carrying capital additions, deliver a better product and increase our quality of customer service.
J.C. McGough and J.C. Fong are with BC Hydro. This article is based on a paper originally presented at the Canadian Electricity Association's Electricity'97 Conference and Exposition held this past April in Vancouver, B.C. ET