11-23-2022

The Electric Distribution System – Where The Grid Meets The Customer

Energy Article

This is the fourth in my series of articles focused on the Modernization of the Electric Grid, and it presents a discussion on the largest, yet often unappreciated, portion of the grid – the electric distribution system. The transmission system (the focus of articles two and three), with its huge and highly visible infrastructure components (and equally huge investment costs!) connecting large regions of the country, garners much of the attention of society. The distribution grid has much smaller components, is more spread out and diverse in construction, and can seem to just fade into the “noise” of all the other municipal and utility streetside wires and equipment. For example, how many people can really tell the difference between an old telephone wire, fiberoptic line, cable TV wire, traffic signal wire, or a 25 thousand-volt (KV) primary distribution line? Yet, the distribution system is massive – multiple times larger than the transmission network – and its impact on quality of service for all customers is also much more significant. And when it comes to grid modernization, the distribution grid is where all the excitement is!

The distribution system radiates out from the transmission-supplied substations and provides grid connection to all customers through equipment, wires, and cable located above and below ground in our cities and neighborhoods. Primary circuit voltages (distribution voltages are considered a “medium voltage” class) range from around 5 KV up to 35 KV. Pole top and pad mount transformers provide a step down to the “low voltage” class levels used in our homes and businesses (120 V and 240 V for homes, and up to 480 V for commercial and industrial uses).

The size of the distribution system is far larger than the transmission grid, as it extends over almost every street in any town to reach every customer premise. The diversity of equipment types and ages on the distribution system is also far greater than on transmission facilities. Many parts of the system exceed 50 years of age (I remember when I thought that was pretty old!), as typically conductors and equipment only get replaced when they either fail or are deemed no longer reliable. Distribution facilities also get upgraded or replaced when they happen to be in the way of road and highway upgrades, or when circuit capacity needs to be increased for new customers or increased load.

Some other factors that set the distribution system apart from the parent transmission grid are:

  • It’s location. The distribution system is everywhere around us and can be easily forgotten at times. Of course, in major urban areas, the facilities are all underground, in manholes and vaults that we walk and drive over every day. Any work done on the system usually impacts traffic, and nearby homes and businesses, whether it involves the need to add new structures or equipment, the need to cut trees for proper clearances, or especially when there is a need to temporarily cut power for worker safety. Distribution facilities also share many structures with other utilities, like telephone, cable TV, and municipal traffic signals.
  • It’s design. The distribution system is mostly radial, meaning the circuits originate from the substation and radiate outward to multiple endpoints. A fault near the head of the circuit will cause interruption to everyone downstream on that circuit. (The transmission grid is designed in a way that provides at least two sources to the vast majority of substations, so a failure of one line will typically cause no more than a flicker to the customers.) There are now significant parts of the distribution system that have a looped design, where circuits can provide a backup supply for each other, in either a manual or automatic fashion. These schemes add cost and complication to the system but have provided enormous reliability benefits. Prioritizing where these investments are made has always been an important responsibility for distribution engineers.
  • It’s fragility. OK, it’s not really “fragile” everywhere, but much of the system is very exposed to dangers and forces that can cause disruption to service. Major wind events and ice storms have always wreaked havoc on the distribution system, especially where there is a significant tree canopy. Trees are often the most significant cause of power outages for many utilities, and the costs of regular vegetation management can be huge. Animals like squirrels and birds also cause outages, despite a wide variety of measures to prevent their unfortunate electrocution. And since most poles are installed along our streets and highways, they are exposed to inevitable vehicle accidents.
  • It’s operating limitations. Because customers are connected directly to the distribution system, there are more stringent requirements for keeping facilities in service and restoring them quickly after an outage event. Crews must often perform construction and maintenance work on the system while it remains energized, which calls for specialized training and rigorous safety protocols. It is also on the distribution system where voltage and power quality are managed to stay within acceptable ranges, avoiding damage to customer equipment and appliances.  Equipment like voltage regulators and capacitor banks are carefully located, with coordinated operational settings, on most distribution circuits to perform this task. They must be designed to handle both peak and light load conditions, and in a growing number of cases, forward and reverse power flow.

The introduction of distributed energy resources (DERs) like solar, wind, and battery storage, coupled with the additional loads of transportation and heating electrification, is presenting big challenges for the distribution system, and the need for significant changes to its design and operation. None of this is happening evenly across the country, or in any kind of planned fashion, so utilities are in a difficult position. They must react expediently to a variety of new interconnections across their territories, while at the same time proactively planning for broader system changes. Most of these changes will require significant investment, often needing long-term planning and budgeting, and approvals from external regulating authorities.

Injecting power onto a distribution circuit creates the occasional condition of reverse power flow, which can typically be accommodated with certain design changes on that circuit. However – and this is important – the distribution system has evolved for over a century with the assumption of one direction power flow, so this change is not always trivial. Moreover, having power injected into many locations across the distribution system, each operating independently (and intermittently!), makes for a much more complicated environment requiring broad design changes for circuits and substations, and new processes and tools for engineers and operators. With that in mind, here are a few important distribution functions and some specific concerns related to this emerging environment:

  • Distribution Planning And Forecasting – Utility engineers have always relied on substation meters to monitor loading on transformers and circuits, and then use that information to forecast loads in the future. That was under the paradigm that there was only customer load (no generation) downstream of these meters. Circuits were designed to handle the peak load conditions that would typically happen just a few days each year, usually on the hottest summer days. With the introduction of intermittent generation scattered around the distribution system, utility planners and operators need to find other ways of determining exactly how much customer load is on each circuit at any given time and to be able to predict the maximum and minimum amounts of power being injected to the circuits throughout the day. Engineers must now also plan for days with light customer loads and maximum solar or wind output, to ensure that reverse power conditions do not overload portions of the grid.
  • Operations Management– Distribution System Operators (DSOs) at any electric utility have the responsibility for the day-to-day management of the distribution system. This includes responding to trouble and outage events, where they dispatch crews to isolate faulted portions of the circuit and reconfigure the system to restore as many customers as possible before completing repairs. DSOs also support routine maintenance activities on the system by setting up safe work zones for crews, ensuring that de-energized equipment and line sections remain that way while crews are working. If crews are working on energized equipment, DSOs can also ensure that upstream circuit breakers or reclosers are in more sensitive fault response settings, which will trip the circuit faster when a fault occurs and prevent any automatic back feeds from operating. Once again, the introduction of DERs on the system is complicating this responsibility, requiring better awareness of grid conditions and more sophisticated modeling tools to rapidly respond to contingency events in a way that not only restores power to customers but also ensures that circuit reconfigurations can handle both load and generation resources without overloads or other negative impacts.
  • Voltage Management – High or low voltage, or fluctuating voltage, are some of these other “negative impacts” that can occur on the distribution system, especially with the introduction of intermittent DERs. When voltage is outside of acceptable ranges, customer (and utility) equipment can be damaged, resulting in expensive repairs and a big public relations challenge for the utility. As mentioned above, utility engineers have traditionally used equipment like capacitors and regulators to manage voltage, and these have worked very well for one way power flow. They are designed to react after generous time delays (30-90 seconds) to minimize excessive mechanical operation, as well as avoiding visible “flicker” to customers. Intermittent DERs, particularly solar PV, can change output much faster than these time delays on partly cloudy days. Large battery systems, when used to support the broader grid with services like frequency support, can be extremely variable, switching from charging to injecting power, and then back again, every few seconds.

Tackling these issues will require a variety of serious investments, in the distribution system itself and in the IT systems that DSOs and planning engineers use to manage the grid. Individual project investments in the distribution grid are small relative to transmission projects, but because the distribution system is so much larger, the accumulation of investments is still daunting. Additionally, the large number of projects presents serious challenges for utility companies that will need to plan, design, and manage this work.

Many portions of the grid will need capacity upgrades to accommodate power injection into weaker sections of circuits that are more distant from the substation source. Increasing the size of overhead wires and underground cables, without interrupting power to customers, is expensive and labor-intensive work. Adding new circuits, and associated equipment, to already cramped electric substations, requires significant planning and possible expansion of the fence line. Capacity upgrades will also be needed for many of the pole tops and pad mounts distribution transformers supplying residential customers, both for increased reverse power flow and for the addition of a significant EV charging load.

Investments in new and upgraded IT systems are key enablers of distribution grid modernization. A more complicated system will take improved models (referred to more broadly as “digital twins”) and new software that leverages those models to allow planning engineers and DSOs to design and operate the network safely and efficiently.  Tools like Advanced Distribution Management Systems (ADMS), Volt-Var Optimization (VVO) systems, and DER Management Systems (DERMS) will become absolutely critical for day-to-day operations in the very near future. (In a future article, I will focus on the importance of the utility digital twin, and the tools it will enable.)

The need for more rapid and frequent voltage sensing and management of the system will require new equipment designed for such purposes.  Dynamic VAR (DVAR) devices and battery storage coupled with smart inverters are capable of this support but are still in the early stages of adoption at a larger utility-size scale needed and will need to be coordinated with the slower-response capacitor and regulator devices. Sensors that monitor voltage, current, and power flow will continue to be added to many more locations on the distribution system.  Environmental sensor data will also be used, monitoring local temperatures, humidity, and even cloud movement, to help operations engineers predict near-future grid conditions.

These are just a few examples of the many innovations and improvements that are already being made in distribution systems across the Country. Many companies are still in early stages, but efforts will be ramping up quickly as the increasing penetration of DERs makes this work unavoidable. The investment opportunities for utilities are significant, and the corresponding opportunities for the array of engineering, design, construction, and project management support industries is truly massive. The benefits to the grid also extend well beyond the accommodation of renewable generation. Like the transmission network, the distribution system has become a critical component of societal infrastructure and is long overdue for these important investments which will make the grid much more reliable and resilient in the long run.

About The Author

Don Kane is a professional engineer with 34 years of experience in electric distribution planning and operations at a large, investor-owned utility. He has specialized in system modeling, forecasting, reliability improvement, and general grid modernization. Don is presently a senior engineer in the Environment and Energy group.

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