Digital and Network Technologies: The Importance of Good Timing

The increasing adoption of small grids, renewables, and digital transformation have put concurrency at the forefront.

Greening the power grid is about more than just transitioning to renewable energy generation. The distributed and discontinuous properties of solar and wind energy, especially residential rooftop solar, pose different engineering challenges to the power grid. Renewable energy sources, known in the industry as distributed energy resources (DERs), are eventually becoming digital technologies for automation and supervision of many parts of the grid that were not previously controlled. These smart grid technologies represent many important changes, including how closely network assets must be synchronized across the network.

DERs power supply chain failure

As DERs proliferate, the power supply chain shifts. The traditional central architecture – from large flowing power plants to customer substations – has been changed beyond recognition. While large power plants continue to provide the bulk of the energy, there are many DERs – from wind and solar farms to storage systems to electric vehicles (EVs) – distributed throughout the grid with rapidly increasing generation capacity. With so many new active players, energy can now flow in many different directions.

To integrate these new active players into network operations, utilities need control and automation applications. They also need line and load status data collected at all DERs and substation locations. More than ever, they need to deploy applications of digital monitoring, control and automation using IEDs (smart electronic devices). This in turn requires coordination of IED activities, data metering, and scheduling of DERs, all coordinated between DER sites, substations, and the control center. A common time reference across the entire network becomes critical to creating a network visualization and coordinating the temporal behavior of network assets, especially for time-sensitive applications.

For example, a synchrophasor phase measurement unit (PMU) – an application that measures energy flow at high sample rates – requires a time resolution of the order of 1 microsecond (millisecond) so that utilities can align line measurement data across the network to analyze network events. Applications such as digital fault recorders (DFR) need accuracy within 1 millisecond (millisecond) to correlate with lightning strike data to determine the origin of the fault. Other network applications, such as IEC61850 General Object Oriented Substation Events (GOOSE) and Sample Values ​​(SVs), also require precise time synchronization on the order of 1 ms and 1 ms, respectively.

See also: energy and utilities fighTing disturbances with data

Get in sync

Distribution system operators, who in the past only required minimal communication coverage in most medium and low voltage service areas, are facing the challenge of distributing time synchronization over their ubiquitous network assets.

Utilities are not new to synchronization. They have long relied on Time Division Multiplexing (TDM) technology to distribute frequency synchronization across their communications network because TDM network equipment needs frequency synchronization to properly transmit and receive digital network data.

With TDM equipment out of support, utilities are moving to IP Multi-Protocol Label Switching (IP/MPLS) networks to support IP/Ethernet and legacy TDM-based applications. Frequency synchronization continues to be required. The dominant method for distributing frequency synchronization is synchronous Ethernet. For network domains that do not support synchronous Ethernet, Timing over Packet (ToP) technologies are also a viable option. Common ToP techniques include adaptive clock recovery (ACR) and differential clock recovery (DCR). However, these technologies fall short of meeting the needs of the smart grid. The main drawback is their lack of the ability to distribute time synchronization across the network.

Time synchronization has received significant attention in the aftermath of the 2003 East Coast power outage in North America. As investigators reviewed event logs, they found conflicting timestamps on thousands of records across multiple networks due to inconsistencies that made it extremely difficult to reconstruct the incident and determine the root cause.

North American Electrical Reliability Corporation (NERC) responded to this situation, and recommended synchronizing the internal clocks of the turbulence meters within 2 milliseconds. While the sector in general has been slow to move forward with this guidance, the demands (and opportunities) of smart grids are renewing interest and bringing the issue back to the fore. New telecom network solutions are coming to the scene to ensure reliable and accurate time allocations across the network.

See also: The focus of modernizing the NIST Smart Grid framework is interoperability

IP/MPLS networks for time synchronization

The advent of digital substations supported by IEC 61850 brings time synchronization into the spotlight. To support the timing needs of digital substations, the utilities relied on Global Navigation Satellite (GNSS) systems, for example, Global Positioning System (GPS) as the source at each substation. However, it is not practical to equip every substation with the antenna and receiver infrastructure to receive GNSS signals, and the signals are subject to natural, accidental and intentional interference. Also, due to the proliferation of IEDs within smart grids, not every IED can be connected to a GNSS receiver to the Inter-range Instrumentation Group (IRIG) interface via copper cable.

Since any deterioration in timing synchronization will affect network applications and operations, it is important that utilities are able to distribute accurate time from their control centers to all substations across the WAN – as the substation’s backup clock with GNSS, the primary clock For substations, without.

Many utilities have already upgraded their WANs to IP/MPLS to provide substation connectivity. This makes WAN an attractive option for synchronization distribution of both frequency and time. In light of this, the International Electrotechnical Commission (IEC) has defined a new power utility automation profile based on IEEE1588, IEC 61850-9-3, to meet these needs of concurrent grid assets. The Institute of Electrical and Electronics Engineers (IEEE) also defines an energy profile in IEEE C37.238. And in cases where WAN supports ITU-T (International Telecommunication Union – ITU-T) communication profiles, it is still possible to bring time synchronization within substations with profile interoperability performed by the substation router.

IP/MPLS WAN combined with IEEE1588 enables it to meet NERC goals and digital substation synchronization needs. IEEE1588v2 defines a precision time protocol for synchronizing clocks in a packet-switched network. It accurately distributes timing information from a central source to all substations connected to the network, with the ability to help devices to automatically compensate for loss of accuracy caused by network weakness. It also provides multiple redundancy protection schemes for high flexibility in the concurrency and network layers. This way, it can act either as a primary timing source or as a GPS timing backup in case of signal loss.

Synchronization is not just an integral part of communication networks; It is fundamental to digital network operations. Network applications, including synchrophasor and GOOSE, require IEDs to have reliable access to accurate time. NERC has been recommending better synchronization for nearly two decades. The IEC also facilitated the introduction of synchronicity with their standard work. The increasing adoption of small grids, renewables, and digital transformation have put concurrency at the forefront. With the arrival of IEEE 1588 in IP/MPLS networks today, the timing couldn’t be better.