By Sam Sciacca, IEEE P2030 Task Force 1 Working Group
Over several decades, electric utilities have installed hundreds of thousands of devices that monitor the vital signs of their transmission and distribution systems. The proliferation of detailed information about voltage, current and other system parameters can tell utilities a lot about the stability and efficiency of their transmission and distribution networks.
A mid-sized utility has between 2,000 and 5,000 intelligent electronic devices (IEDs) online today and is adding about 100 per year as new substations are installed. This installed base of IEDs someday will accelerate smart grid deployment considerably. In the meantime, it could be doing much more to increase virtually any utility’s current return on investment (ROI).
Most IEDs have been deployed by a utility department that had a pressing need for certain information. But these IEDs usually can provide a wider range of information than described in the original justification for their deployment. The deploying department also could select from communications links suitable for the type and demand for the data. These alternatives range from continuous communication such as supervisory control and data acquisition (SCADA) to periodic assessment such as condition-based monitoring to event driven on-demand dial-up such as fault records. Historically, Internet connections directly to these IEDs have not been employed widely because the cost of IP connectivity to each substation could not be justified or was not needed by the deploying department. In addition, a long-range smart grid strategy probably had not been developed by the utility.
The departments that purchased, installed and maintained the IEDs exercise nearly complete control over their use and the data they collect. But this siloing of data in some instances has reduced the potential ROI that could be contributed by the IED. For example, measurements of bus voltages collected for predictive breaker maintenance by a circuit breaker IED at every substation would be of great value in other operational aspects from an enterprise perspective. Similarly, planning departments could use protective-relay IEDs that monitor and record current levels on all three phases to better balance the system if this data were available enterprisewide.
Enterprisewide access to all IED data also can help the utility in important functions such as fault isolation, power factor correction and the tactical location or relocation of transformers and other hardware.
Even when data-sharing benefits can be demonstrated, it often is difficult to implement because of pre-existing access, management and use protocols within the organization. Once the data from an IED is integrated into a SCADA system and is being monitored more or less continually, the SCADA system administrator becomes a stakeholder and wants to have a say in, for example, when a particular IED is shut down for maintenance. The department that owns the IED is typically unwilling to give up that control because it is of mission-critical importance to them. In a siloed organization, a good dose of turf protection can be included among the reasons.
The communications link is another challenge. The wealth of IED data is of little use for smart gridlike integration until it is formatted in Internet Protocol. But the solution here is straightforward if not easy because it can be addressed by purchasing the required equipment.
As the dependence on data from IEDs increases within the utility, it becomes increasingly critical that the reliability of the data be maintained. The term cybersecurity has been used much in the industry during the past five years and conjures up images of malicious hacking of IEDs by outsiders. The larger issue is cyberintegrity. Although it includes defending against hackers, cyberintegrity focuses as closely on containing and tracking malicious internal threats and costly mistakes. Changing a password or improperly configuring a device’s firmware can inadvertently keep legitimate users from accessing data or cause the device to provide incorrect data. A properly implemented cyberintegrity system will take into account all stakeholders’ needs. Departments that have installed and maintained IEDs for decades do not have to lose the level of authority required to execute their particular missions for the utility.
Once a utility’s IEDs are transmitting their data to a secure, centrally controlled system, the utility will have created a shadow version of a smart grid. Most if not all of the information needed to respond to changes in demand from the other half of the smart grid–from the substation to the customer–will be in place.
This growing dependency and multidepartmental use of IED data will cause a systemwide change in IED management. Instead of IEDs’ being managed by ownership, IEDs must be managed centrally as a distributed asset. Central management will ensure that all stakeholders using the data are represented in the operation, maintenance and selection of the IEDs.
Retrofitting existing IEDs with secure IP-enabled communication links will benefit ROI and speed the transition to the smart grid while accommodating the future installation of IEDs with new functionality better adapted to the Internet.
Utilities have worked to improve cyberintegrity since 2003 when the North American Electric Reliability Council (NERC) ratified the first NERC critical infrastructure protection (CIP) program. NERC CIP establishes standards in eight areas to protect all aspects of an electric utility’s capital investment. Several apply to protecting power plants and other buildings and others apply across the board, including provisions for identifying critical cyberassets, developing security management controls, implementing training, conducting incident reporting and response planning, and crafting and implementing recovery plans.
The IEEE has been in the vanguard of cybersecurity efforts. IEEE 1686 was the first standard that specifically addressed features in an IED for cyberintegrity. IEEE on March 23 approved a project that will lead to a standard that will harmonize cyberintegrity practices for utilities.
The increasing dependency on communication technology and the growing pressure of a secure utility infrastructure has prompted several standards bodies to develop cybersecurity standards. Until recently, however, little effort has gone into the harmonization or rationalization of these standards to the substation applications. The IEEE PC37.240 project will help remedy that situation.
Utilities have done a good job building a shadow smart grid that can increase their ROI in the short run and provide a cost-effective evolutionary path to the smart grid in the long run. All the tools are available to utilities to connect departmental IEDs into a network operated by the enterprise. The data collected from the IEDs will have many benefits, such as isolating faults and reconnecting the remaining network as efficiently as possible.
Industry initiatives have clarified the technology path to a secure, IP-connected grid operated by the enterprise. The biggest challenge will be a cultural change that will clear the way for departmental islands of automation to be linked and operational authority vested in a single entity. Utilities must rethink how they will deploy hardware so all stakeholders are satisfied that their data requirement will be met reliably.
There are even greater benefits in the future. When data is available to a larger community, people become creative and develop solutions that were not dreamed possible before.
Sam Sciacca is a senior member and co-chairman of the IEEE P2030 Task Force 1 Working Group. He has more than 25 years’ experience in substation and distribution automation. He is on the IEEE Standards Associations Standards Board and is a member of the Power System Relaying Committee and IEEE Substations Committee. Sciacca is president of SCS Consulting LLC, a global solutions provider for electrical utilities.
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