Grid Automation

The Grid Automation Systems market research delivers current market analysis plus a five year market and technology forecast.  The research is available in multiple editions including worldwide and all regions.

Grid Automation Is Adapting to the Energy Transition

The ARC Grid Automation market report provides critical insight into the challenging issues faced by utilities and grid automation suppliers as the world struggles with the energy transition. The grid automation report covers measuring devices, control and protection devices, control and data gathering communications, and a wide class of operational execution systems. The report scope includes DMS, ADMS, TMS, EMS, OMS, WAMS, VVC, LFA, forecasting, GIS, and the services that go with these products. Grid automation spans a wide range of suppliers and technologies, but fundamentally it is focused on reliability, cost of power, and meeting environmental goals. Grid regulators and operators will be introducing new energy, ancillary service, and capacity markets and new policies that will drive investment in new generation, storage, transmission, distribution, and demand response software and hardware.

Grid Automation Strategic Issues

In addition to providing a five-year market forecast, the Grid Automation Market Research provides detailed quantitative current market data and addresses key strategic issues as follows.

Make Cybersecurity a Top Priority

The ability of a cyberattack to gain access to a grid asset, block, or modify data from a substation, a microgrid, or a field device is an obvious concern for the utility and the asset owner. Part of the solution is physical security, but the screening and training of responsible personnel is essential. Protection relays act locally, but their programming might be subject to tampering, particularly if this programming is done remotely. Wind turbines can be remote and are typically completely accessible for programming changes including updating firmware from secure remote locations. Control system networks for substations and microgrids should generally be isolated from corporate business networks and remote access security should follow industry guidelines and best practices, as well as comply to all NERC requirements. Attacks on critical IT infrastructure, such as the recent Colonial Pipeline ransomware attack are also of great concern and plans must be put in place to quickly recover from failures and malicious damage.

Preparing for a cybersecurity attack must therefore be an integral part of IT and OT organizations. And it must be fully embedded within the organizational psyche—from the boardroom and senior executives to the newest employee.

Embrace Grid Interactive Customers

If you are a utility, you should pay extra attention to providing reliable communications from local solar or wind farms or microgrids using IEC 61850, if possible whether these are private or utility-owned. The US is moving from DNP3 to IEC 61850 which has become the latest world standard for substations. Plan for expandability as solar and wind farms can evolve into microgrids. Microgrids are well-suited for rural sites with unreliable power and often involve renewable energy and grid scale batteries. Some rural locations can remain powered if larger segments of the grid are unpowered. In the US, the FERC 2222 (and 2222-A) regulations will open new opportunities for small customers and microgrids to compete in utility markets. These customers will need to have SMART meters with an effective AMI in order to automate demand response devices. Utility business models are evolving, and new energy broker functions are needed. Utilities and grid operators are supporting IEC 61850 for substation automation, but they need to ensure accurate, reliable, and secure two way communications. Utilities are interested in helping end users manage loads automatically. This means that they will need equipment that can support specific communication standards and protocols. In this regard, buyers should push for DER equipment that supports IEEE 2030.5, IEEE 1547, and OpenADR. These standards will require DER equipment to behave in a uniform way to connect or disconnect from electric grids and allow bidirectional communications that allow DER assets to participate in the new markets that will be created. 

Healthcare, educational, and military facilities have been implementing DER for decades, but increased local generation-bidirectional power flow is more common, and the rules and market rewards of interaction will get more complex. Grid operators must be able to monitor and predict microgrid and customer load/export behavior. Microgrids must have consistent grid codes so that they smoothly and predictably transition to various modes of operation including modes that might be created by new market opportunities and grid regulations.
 

Implement/Upgrade to a Fully Digital Substation

Most, if not all new substation installations worldwide will be implemented as digital substations using process bus technology that connects IEDs with fiber optic Ethernet. The days of analog signals for critical measuring and safety devices has passed. That is not to say that analog signals are not involved, as they too can be collected and communicated via IEC 61850 process bus technology or via SCADA systems. SCADA systems at the substation level are also a part of the digital substation; SCADA connectivity to remote control centers is still common even though fast, secure, bi-directional 61850 communications from substation to and from grid control centers is possible. Retrofitting substations to process bus technology should be a planned activity with a final architecture in mind. New equipment can be compliant to process bus technology. Existing SCADA systems should be able to communicate with process bus protocol without major changes and IED devices can be gradually transitioned as older equipment is replaced. Based on a sound business case, any major upgrade to feeders and loads might be an opportunity to digitize the whole substation. In the configuration of IEDs, use a standard template to ensure that all the capability is configured and all the data that might be of use at grid control centers is collected.

Digital substations enable electric power utilities to increase productivity, reduce footprint, increase functionality, improve asset reliability, and crucially improve safety for service personnel. Digital substations exploit the benefits of digital protection, control, and communication technologies, mirroring the trend toward digitalization as seen in many other industries. This is done in part by replacing copper signal wires with fiber-optic connectivity. Upgrading devices to IEDs that support IEC 61850 communications is also an important step in the digital substation. Additionally, home computers and mobile devices like smart phones and tablets can provide local and remote workers alike with data on demand to optimize overall substation performance, often letting authorized personnel work from an offsite office. Two-factor authentication and other security methods are needed to ensure such access remains secure. This trend toward digitization also applies to other areas of the substation. Within medium-voltage switchgear panels for example, the horizontal exchange of IEC 61850-8-1 GOOSE (generic object-oriented substation event), and sampled analog values reduces wiring and accelerates testing and commissioning. Digitalized technology can continuously monitor mission-critical functions of power transformers and high voltage switchgears, while performing real-time simulations and diagnostics to support the proactive management of the asset's lifecycle, if possible.

Digital substations are not a new idea to the power industry, but the technology has been slow to adopt because of old processes, regulations, and an aging transmission grid. Times are changing, owing to advances in fiber-optic communications and digital technologies. Owner/operators are advised to plan for updating all digital substations.