Measuring Smart Distribution

By Robert W. Uluski, Electric Power Research Institute

No portion of the electric power grid has been impacted more significantly by the smart grid concept than the electric distribution system.

Distribution system operators once lacked visibility of the electrical conditions on distribution feeders. At most, operators could monitor conditions at the substation end of the feeder. This was not necessarily bad because distribution systems were fairly predictable in loading and voltage levels. As utilities seek to manage and improve the performance of an increasingly complex distribution network, however, there is growing need for improved visibility. A smarter distribution system can help meet that need.

New monitoring and control facilities are providing opportunities to enable utilities to improve distribution system performance, efficiency and reliability significantly without compromising operating requirements.

Controls, Communications

Past and present distribution networks include controllers, such as relay intelligent electronic devices (IEDs), line reclosers and capacitor bank controllers. The industry has identified and is implementing uses for these existing controllers. For example, many utilities use existing line reclosers and sectionalizers to implement self-healing networks.

Customers and utilities are installing a whole new generation of controllable devices such as smart inverters. These new control capabilities enable utilities to manage dynamic conditions caused partly by the distributed energy resources (DERs). Regulations that govern the use of DERs (e.g., IEEE 1547) prevent the use of customer-owned DERs for voltage regulation. There is ongoing effort (e.g., IEEE 1547.8), however, to enable DERs to play a much larger role in improving the operation and performance of the distribution system.

Demand response (DR) facilities provide another level of control for smart distribution systems. Utility companies can use DR capabilities to release feeder capacity distribution system emergencies, enabling load transfers that otherwise would be blocked because of overloads.

Utilities require robust and reliable communication facilities to acquire measurement data and to initiate remote control actions. Distribution system communications are challenging because of the wide coverage area, many communicating devices and obstructions. Many utilities are seeking to leverage advanced metering infrastructure (AMI) communication networks and public and private infrastructure (e.g., cellular networks). Numerous challenges must be overcome, however: overall system security, performance during power outages and overall data throughput.

Advanced Distribution Applications

Volt-VAR control is an operating requirement for all electric distribution utilities. This topic, however, has taken on a new dimension. Volt-VAR control has become volt-VAR optimization (VVO), which can help electric utilities improve efficiency, reduce demand and promote energy conservation.

Many utilities are considering conservation voltage reduction (CVR), the intentional lowering of voltage to the lower portion of the acceptable range of service delivery voltage. Many appliances use less electricity with slightly reduced voltage. Electric utilities have used voltage reduction many years during temporary power shortages, such as loss of a major generating facility during a heavy load period. Distribution utilities are considering activating CVR during nonemergencies to reduce demand during peak-load periods, and some utilities are considering running at reduced voltage around the clock to improve overall energy efficiency.

Numerous utilities have demonstrated that CVR is an effective energy efficiency tool that does not affect electricity consumers adversely. The industry, however, has learned that circuits are not created equally from a voltage-reduction standpoint. Some feeders show significant efficiency improvement when voltage is reduced. Others exhibit a less-prominent effect because of differences in load mix and circuit characteristics. Leading research institutions such as the Electric Power Research Institute (EPRI), Pacific Northwest National Labs (PNNL) and the National Electric Energy Testing Research and Applications Center (NEETRAC) are developing ways to predict CVR behavior so utilities can prioritize their VVO investments.

Impact of DER, Renewables

Volt-VAR control strategies face new challenges from ever-increasing penetrations of distributed generating sources. Reverse power flows caused by these sources can produce voltage rise problems that might be difficult to address using conventional mechanisms. As an example, when two feeders feed off the same substation bus, one can experience low-voltage conditions from normal voltage drop and the second can experience high-voltage conditions from reverse power flow. The smart distribution VVO system must detect such conditions and then perform control actions to mitigate these problems.

Growing deployment of renewable generating resources has imposed additional challenges on distribution systems because of the generating units’ variable nature (see Figure 1). When output from a solar generator suddenly drops as a result of cloud cover, the lost generator output must be made up by additional load contribution from the substation. The feeder might experience a significant voltage drop until the utility’s voltage regulators react and boost the voltage. Sudden increase in solar power output when the sun reappears has the opposite effect. Such voltage swings might impact service quality and might increase voltage regulator operations greatly, resulting in increased maintenance and loss of life for this equipment. Inability to deal effectively with such variations limits the amount of DERs a feeder can accommodate.

One approach to mitigate this problem is using at each generator smart inverters that respond quickly to sudden variations in power output. The smart inverter might supply reactive power when generator output power drops off to compensate for the voltage drop associated with additional load supplied from the substation. Figure 2 shows the results, which include smaller voltage variations, fewer voltage regulator tap changes and a flatter voltage profile.

Fault Location, Automatic Restoration

Electric utilities are giving particular attention to reliability improvement and the self-healing grid. Numerous developments have been made in fault anticipation, the detection of equipment problems before faults occur, and fault location. When faults occur, electric utilities can identify fault location with precision using information from substation protective relay IEDs, faulted circuit indicators (FCIs), outage management systems and short circuit models. These new fault-locating facilities will enable utilities to locate permanent faults and recurring temporary faults that have not yet caused an extended outage.

Many utilities are implementing systems that automatically detect faults, isolate the damaged portion of the feeder and restore as much service as possible within seconds as part of their strategy to achieve a self-healing grid. One problem with these systems is that service restoration often is blocked because of heavy loading on backup feeders. The next generation of automatic restoration systems should take advantage of other advanced control facilities being deployed as part of the smart grid. For example, when encountering a load transfer limit, the automatic restoration system might initiate actions to free up capacity on the affected feeders, enabling the load transfer to proceed. Capacity release strategies might include initiation of DR actions, activation of CVR and temporary reduction of fast-charging activities for electric vehicles (see Figure 3).

Making the transition from manual, paper-driven processes to computer-assisted decision support and control systems is no easy task. The biggest challenge is revamping long-standing operating practices to accommodate the new systems and information. Significant updates to operating procedures are needed, along with new skill sets, training and personnel certifications. In addition, more engineering support might be needed in the operations environment to help deal with new concepts such as system optimization and dynamic control.

These changes appear to be worth the trouble and will help ensure that the smart distribution system satisfies the needs of 21st-century electricity consumers.

Robert W. Uluski is a technical executive with the Electric Power Research Institute.

More PowerGrid International Issue Articles
PowerGrid International Articles Archives
View Power Generation Articles on
Previous articleCalifornia’s Electric Policy is Not a Model for the United States
Next articleMaking Sense of Meter Data—Plunging Into Business Analytics

No posts to display