By Ron Farquharson and Ken Caird
The following list represents the key substation equipment frequently targeted for on-line monitoring:
- Transformers
- Load Tap Changers (LTCs)
- Bushings
- Capacitors
- Station Batteries
- Communication Equipment
Figure 1 shows in more detail the type of parameters that can be monitored for a typical circuit breaker. Figure 2 shows parameters for a typical power transformer. Both diagrams also show that multifunction IEDs interface to sensors for processing of the data and then pass the data on to either the substation LAN or through an RTU. The intent of these diagrams is to illustrate the use of IEDs that perform not only equipment monitoring but also other already required functions to minimize the hardware instrumentation costs. In addition, the LAN and IED protocols are assumed to be industry standard to allow maximum flexibility for the user. Note that some basic sensors can be connected directly to a typical RTU and require no further processing at the substation.
Monitoring Sensors, Devices and Technologies
Referring to Figures 1 and 2, some of the devices currently available for monitoring the indicated parameters are as follows:
- Water in oil (transformer)
- Gas in oil (transformer)
- Temperature (LTC, transformer tank, and winding)
- Gas Pressure (breakers, transformers)
- Insulation properties (transformers, bushings, CT/PTs, cables)
- Partial Discharge (transformers)
- SF6 Gas Leakage
- Breaker motion speed and velocity profile
In addition, there are equipment monitoring devices that measure multiple parameters to provide a more complete view of the condition of a specific type of equipment:
- Load Tap Changer monitors
- Transformer monitors
- Circuit Breaker monitors
- Battery monitors
There are generally multiple suppliers of each type of equipment--many with a slightly different approach to accomplishing the needed monitoring. The selection and location of the devices will depend on the risk analysis in terms of failure modes, effects, and criticality as well as an overall economic analysis for monitoring and diagnostics that includes such factors as NPV of deferred capital costs for replacements or upgrades.
The Need for Diagnostics Tools
The above sensors and IEDs provide the monitoring DATA which still requires time consuming interpretation by experienced apparatus specialists. Not only does the utility lack the resources to spend in this evaluation, but there are fewer apparatus specialists available to perform the work.
Therefore it is becoming imperative that the utility use an expert system to automatically provide diagnostics KNOWLEDGE of the condition of the equipment along with any recommended ACTIONS.
Few expert systems are available today, and a great deal of research and development is underway at many universities and manufacturers. In general, the available systems are now becoming viable for broad implementation.
Substation Network Architecture and IED Integration Considerations
The current problem with the vast majority of these systems is that they are heterogeneous in nature. Most use proprietary protocols for communications, and the PC software used by each company is unique and proprietary to each device. Thus, the user has to become familiar and trained on a number of proprietary systems when one wishes to monitor a number of different pieces of equipment.
These systems provide 'Islands of Automation' with the major drawback that a common database or a single view of the substation is not provided.
Plus, the user and applications are missing valuable diagnostic data from equipment such as relays, meters, remote terminal units (RTUs), and digital fault recorders.
Utility systems operation personnel have been using Substation Control Systems (SCSs) and earlier remote terminal units (RTUs) for years to monitor and control their electric networks. Since SCSs integrate data from multiple IED sources, such as RTUs, relays, meters, power quality monitors, PLCs, and digital fault recorders into a single computer platform for data processing and operator display, the SCS becomes the logical platform for the integration of equipment monitoring data as well.
In addition to integrating network-monitoring equipment into an SCS, many different types of equipment monitoring could also be integrated onto the same platform.
Devices such as these could be added to the SCS:
- Breaker monitors
- Transformer monitors
- Dissolved Gas monitors
- Winding Temperature monitors
- Partial Discharge monitors
- LTC monitors
- Bushing monitors
Now that all data from both network and monitoring devices is located in a common database, powerful diagnostic and asset management programs can be ported onto the SCS computer to transform all this data into relative information of the status and health of the monitored equipment. In addition, an integrated SCS with this capability can be easily interfaced to a Computerized Main-tenance Management System for automatic generation and tracking of maintenance work orders. Figure 3 shows an example of architecture for an integrated SCS.
Standard Protocols and LANs
As mentioned above, each separate monitoring device could potentially have a different proprietary protocol or LAN, making integration very time consuming and expensive. A key to success in integrating the equipment monitoring function is the use of standard protocols and LANs, such as DNP, IEC 870-5 (select profile), or UCA with MMS once it is standardized. Whether or not to support standard protocols such as these must be considered a key evaluation criteria by the selecting utility in order to ensure that the immediate and future integration costs are kept to a minimum.
Note also that the decision to go with a LAN architecture can bring substantial additional benefits over the conventional RTU centric approach.
Some of these benefits are as follows:
- Reduced station wiring and installation costs
- High speed data exchange
- Elimination of duplicate equipment (PLC, DFR, SER, RTU)
- Integrated database support
- Reduced O&M costs with single point of display and configuration
- Additional high value applications
- Virtual connection
- Peer to peer operation between IEDs (i.e., interlocking)
- File transfer of large records
- Interface to corporate network
System Requirements
A survey of North American utilities found that the most requested features of an equipment monitoring and diagnostics systems or asset management system are the following:
- Reduce workload and things to manage (i.e., We don't have the manpower to do all the things we should be doing).
- Improve their understanding of the operating capabilities of their existing assets (i.e., exactly how large a load can this transformer handle at this temperature)
- Reduce Costs: 'Just in Time' Maintenance of Equipment; Logistical Optimized Center of Maintenance
- Guidance to Maintenance Staff (i.e., provide knowledge base to assist less experienced staff, replace loss of knowledge through early retirement of experienced maintenance personnel)
- Develop a system that you do not need an expert to interpret (i.e., provide information not data)
When asked what was wrong with existing equipment monitoring and asset management systems, utilities had the following to say to vendors:
- Look at simpler methods
- Reduce costs
- Optimize the parameters measured (i.e., capture all needed data at minimum cost)
- Provide integrated solutions (no proprietary stand-alone solutions)
What is Lacking
It can be seen from the previous market analysis that what is really needed is an equipment monitoring and asset management system, which can do the following:
- Integrate equipment for different functions and different suppliers
- Support 'plug and play' devices which are easily integrated into the system by the user
- Provide an open architecture allowing integration of equipment and software from multiple vendors
- Operate reliably for the full design life of the monitoring equipment in the harsh substation environment
The Solutions
Substation Control Systems (SCSs) supplied by leading substation automation systems vendors provide a platform for integration of multi-purpose intelligent electronic devices (IEDs) into a single integrated control and data acquisition system.
Economic Benefits
The alarming of the maintenance personnel only when equipment needs maintaining allows utilities to move from a periodic-based maintenance schedule to a just-in-time maintenance program. Implementation at a utility in the Midwest US has allowed that particular utility to move from a 5-year breaker maintenance schedule to a 12-year average maintenance schedule. This same utility routinely checked 92 LTCs annually; now with continuous monitoring, they get about 5 LTC maintenance alarms annually. This utility calculated a payback of less than 2 years for its substation diagnostic system and has now implemented its system at 75 substations while maintaining or enhancing its system reliability.
The benefits include the following:
The economic evaluation process may involve a number of analysis tools, such as Fixed Charge Rate Analysis or Discounted Cash Flow Analysis for broad implementations. However, where sites fall into a special category such as system critical sites or sites with troubled equipment or where the loads are especially critical, the normal economic evaluation may not apply.
Almost every utility has critical sites where the demand for reliable operation overrides a standard economic evaluation. These sites are the probable first candidates for equipment monitoring and diagnostics.
Conclusion
Rather than purchasing a separate substation equipment diagnostic system and SCS, equipment monitoring devices can be integrated into an SCS to provide a total substation Asset Management system with a much greater return on investment.
The Asset Management system will allow the electric utilities to:
To summarize, the electric utility in the next millennium will almost certainly have to follow the path already taken by many other deregulated industries to support the drive for efficiency with significantly increased access to information on their total operation. At the substations, this will mean acquiring timely and detailed knowledge of all aspects of the power transmission and distribution network including the condition and capabilities of the primary equipment. This will best be accomplished with integrated solutions that satisfy ALL protection, control, automation, and diagnostic functions that utilize a flexible range of existing or new multifunction IEDs using standard LAN protocols and providing the user with a consolidated knowledge of the system -- not gigabytes of raw data.
Ron Farquharson and Ken Caird are with GE Harris. This article was reprinted with permission from GE Harris' Newsletter 'Synergy'.
- reduced inspection costs
- reduced failure related repair or replacement costs
- enhanced system reliability: fewer unplanned outages
- better planning for scheduled outages
- deferred planned upgrade or replacement capital costs
- reduced insurance premiums
- personnel safety
- environmental safety
- retention of knowledge of most skilled staff (expert system)
- wide access to key knowledge
An integrated substation control system that incorporates the equipment monitoring and diagnostics function will help electric utilities change their maintenance philosophy from a time-based preventative system to a reliability-based predictive system. The utility is able to operate the primary equipment at the most optimal level of performance and improve the overall system reliability. This is proven to be the best direction because maintaining assets based on criticality and condition of the equipment represents the best value to a utility in terms of achieving a balance between performance, reliability, and costs.
- Maintain safe and reliable equipment operation
- Operate assets at maximum performance for current conditions
- Extend maintenance intervals without decreasing system reliability
- Defer the cost of replacement or upgraded equipment