Smarter Metering

Technologies for T&D Networks

 “Smart metering” has demonstrated how advances in technology may be used to solve a utility's changing needs in a dynamic market- place. But where smart metering is effective at the end-customer metering point, new technologies in multifunction “smarter meters” provide a broader range of benefits at any metering point within a utility network.  

This paper describes how new communications technologies  including local mastering, gateway functionality, web based presentment, e-mail data transfers and Ethernet support of SCADA protocols  have been used by power utilities around the world to provide integrated network control and monitoring.

With these technologies, communications costs to remote substations are drastically reduced while still increasing the number of monitored points and improving network awareness. It is shown how these communication links can provide billing data, operational data to supervisory control and data acquisition (SCADA) systems, and regulatory compliant power quality information so that the needs of multiple departments are met within a single device.            

Finally, case studies are presented that illustrate how utilities leverage smarter meters to automate tasks such as local aggregation and advanced transformer compensation to simplify network analysis and billing. By providing distributed intelligence, local control and the communications infrastructure to reach more metering points, Smarter metering enables utilities to increase awareness, reduce risk, and lower operational costs.          

I. History of Smart Metering           

Since the introduction of solid-state metering in the early 1990s, features have been added to tariff meters to provide more valuable information to electric utility companies than simple energy accumulation.

Multifunction meters register active, reactive and apparent energy, time-of-use (TOU) meters track energy consumption at different tariff rates, and remote communications options (fixed network or wireless) have been added for automated meter reading (AMR). A device with the embedded intelligence required to offer these combined features has often been dubbed a “smart meter”.               

Smart metering is typically applied at the end customer metering point, be it industrial, commercial or residential, and primarily for billing purposes only. While this covers the largest number of monitoring points in a utility’s network, no additional features are provided where energy flows are largest and operational data is most critical: within the transmission and distribution network.                

Recently, “smarter”, more powerful meters have begun to emerge that offer better interface technologies. These provide access to more information than their earlier “smart” counterparts:    

SCADA data, power quality and reliability data, loss calculations and error correction, and other troubleshooting data. These new communication technologies can be used to connect to remote mission critical transmission and distribution (T&D) stations, or between devices within these stations.          

II. New Communication Technologies             

To the substation:        

Slow, not broadband, power line carrier (PLC) and serial data modem lines have long been used for remote access to substation data. While effective for basic SCADA telemetry, these media are limited to relatively low throughput rates, generally below 9600 bps. Capacitor traps for PLC systems are expensive to install and maintain, and modem lines are susceptible to electro magnetic noise leading to suboptimal communication rates. For both of these traditional media, complex data types such as digital waveform recordings lead to long connection times and limit a utility’s ability to read all of their installed meters in a timely fashion.                 

With the growth of wide area networks and the world-wide web, TCP/IP has emerged as a high throughput transportation mechanism suitable for many new media and embedded protocols.  Ethernet connections (either twisted pair copper or fibre optic) provide dedicated 10 or 100 Mbps channels capable of addressing all devices within a substation simultaneously. With a data transfer rate 1000 times faster than dial-up modem, TCP/IP can support complex data types without introducing communications bottlenecks. Fibre optic links provide the additional benefit of galvanic isolation, removing a potential failure point from the system.                

For remote substations, TCP/IP can be utilized over satellite radio links or broadband power line carrier. In either case, the telecommunications industry has provided the necessary equipment to transmit and decode these signals, simplifying installation and removing integration conflicts.       

The TCP/IP address of the end device is all that is needed to configure the system. Finally, email may be used as a transportation mechanism. Relying on TCP/IP for transmission of the individual packets, e-mail allows data to flow seamlessly through firewalls without compromising security.

The information technology (IT) industry has developed systems to accommodate the flow of email traffic while maintaining the security of their networks. Email is preferred in many cases by IT departments than TCP/IP connections alone because of the enhanced security it offers.  Smarter meters supporting TCP/IP provide access to all of these communication architectures and the development efforts of the entire communications industry.

Within the substation:              

Ensuring a high throughput communications    pipeline to the substation is the highest priority in ensuing timely access to metering data. But within the substation, new technologies are also                present to reduce the installation cost and improve access to other substation devices.       

Ethernet and modem gateways allow one smarter meter to act as a communication hub, routing messages to other devices in the substation over inexpensive RS-485 serial connections (Figure 1). 1). Using such an architecture, only one device needs to be equipped with either the Ethernet or modem hardware, reducing the overall cost of the metering equipment and allowing access to 32 downstream devices or more. When using an industry standard protocol such as Modbus or DNP, the downstream devices are unaware that the request has been passed through a gateway and behave as though communicating directly to the master software or RTU. Older devices can thus be integrated into a newer communications architecture.                

Figure 1. Using gateways to communicate with devices inside a substation.

Another means of integrating legacy devices is through local mastering. In this application, a smarter meter is used as an RTU; requesting information from other devices and passing it backbup to the master software. This opens up possibilities for local data control, such as aggregating feeder readings from multiple devices before transmission back to the master software. 

 Finally, for data acquisition systems that include transducers without communications capability, smarter meters are available with onboard analog inputs that can directly interface with the output signal of each transducer. Values can be aggregated from multiple transducers and scaled appropriately before transmission to the master software.

Figure2. New communication technologies simplify collection of data from existing and new substation devices.

III. Extended Interoperability and Data         

Access New communication technologies can solve many problems related to data acquisition and speed, but the benefits to utilities are only realized if the information is presented in a ready to use format. Integration with existing utility systems is key to meeting this need.         

For each user, system or department, smarter meters present information in the appropriate format over appropriate media. SCADA and Operations systems require industry-standard protocols such as IEC 61850, IEC 60870-5-101, DNP or Modbus. Various device vendors make          these protocols available over TCP/IP for high speed direct integration into existing SCADA systems.     

Billing systems may require information on energy consumption or demand in protocols such as DLMS, IEC 60870-5-102 or MV90. Again, some software vendors now support data acquisition over TCP/IP using these protocols.  In addition to these more traditional uses of data, key account managers may wish to view load profiles, power quality information or alarm conditions. For each of these, the data format and media is customizable, ranging from pager alerts to emailed reports, to web-accessible graphical views.    

Finally, other utility departments may wish to view the information contained in a smarter Mmeter. By providing a secure web server on the device, authorized persons can view critical information in real-time from any computer any where in the world        .

IV. Case Studies              

Using Ethernet to provide data to multiple users

After liberalization, a major utility needed to provide daily settlement data to the independent system operator (ISO). The utility chose smarter meters with TCP/IP support and gateway functionality. Forty gateway meters connected to the existing Ethernet wide area network provided high-speed access to over 260 new tariff meters.    

By using TCP/IP, there is no concern that the utility or ISO data retrieval will interfere with each other and the utility network now supports complex power quality data at any of its monitoring points.     

Using satellite to overcome geographical challenges

An electrical utility with a 70,000 square kilometre service area needed access to remote        substation data. Due to limited existing infrastructure, TCP/IP over satellite links provides access to real-time SCADA data. Transient events, sag/swell events and transformer loading alarms for the substation are sent by e-mail over satellite to PCs and pagers.                  

Using local mastering to increase efficiency

Managers at a switchyard needed combined instrument / transformer loss compensation and power factor monitoring, plus aggregation and scaling of real-time data. By monitoring transformer and instrument losses on the secondary side, installation costs are reduced without sacrificing accuracy.       

The switchyard is a 500kV transmission facility with 10 bays, handling power flowing to and from four different independent power producers, a nuclear facility, and several other      substations. Substation bays operate as four loops, with smarter meters configured as Mod-bus Master devices, each gathering real-time data from its loop to perform scaling and aggregation before passing values to a central RTU.

The network fully integrates with the existing billing system and provides a valuable backup function if the RTU or communication links fail, the data can be retrieved manually from the onboard non-volatile memory of each meter. When generators go online and merchant sites produce their own power, the breakers close and the meters go offline.  

             Figure 3 Information flow from smart meters    

V. Conclusion  

Applying the new technologies of the telecommunications industry to metering systems allows utilities to increase network awareness and control. Combining these technologies with powerful multi-function metering platforms provides opportunities for utilities to reduce operational risk, solve business needs, and improve network reliability.

Figure 4 Benefits of new “smarter meter” communications technologies