How NJ’s largest utility proactively dealt with the impacts of DER

Published on July 20, 2017 by Kim Riley

Public Service Electric and Gas (PSE&G) lays claim to being New Jersey’s largest utility — serving a combined 4 million electric and gas customers in the Garden State — and the oldest at 114 years.

The adage that with age comes wisdom surely befits PSE&G, which is embroiled in integrating greater levels of distributed energy resources (DER) into its distribution system.

For example, to meet the state’s strong growth and rising demand in the solar photovoltaics (PV) market, PSE&G proactively works to understand feeder and substation capacity to accommodate solar PV, and to avoid any possible negative impacts to grid reliability, voltages, thermal capacity and flicker, said Ahmed Mousa, PSE&G’s distribution manager.

“If you’ve been in New Jersey lately you’ll not miss the solar panels on roadways, residential rooftops, commercial rooftops, and on warehouses. We’re even promoting it on parking roofs, too,” Mousa said during a company-sponsored webcast this week.

The goal, Mousa said, is to encourage renewables while at the same time improve reliability for both the first and last customer.

PSE&G isn’t alone in this endeavor. Utilities across the United States are trying to embrace DER — including small natural gas-fueled generators, combined heat and power plants, and electricity storage in addition to rooftop solar PV and other advanced renewable technologies — to help facilitate the transition to a smarter grid.

As this happens, DER already have impacted the operation of the electric power grid in many settings and a combination of technological improvements, policy incentives and consumer preferences will continue to make the role of DER increasingly important, says the Electric Power Research Institute (EPRI).

Therefore, it’s important for utilities to remember that successfully integrating DER depends on the existing electric power grid, especially its distribution systems, which wasn’t designed “to accommodate a high penetration of DER while sustaining high levels of electric quality and reliability,” EPRI noted in its 2014 paper, The Integrated Grid: Realizing the Full Value of Central and Distributed Energy Resources.

“The technical characteristics of certain types of DER, such as variability and intermittency, are quite different from central power stations. To realize fully the value of distributed resources and to serve all consumers at established standards of quality and reliability, the need has arisen to integrate DER in the planning and operation of the electricity grid and to expand its scope to include DER operation” — or what’s known as the integrated grid, EPRI said in its paper.

And that’s exactly what PSE&G did in a recent collaboration with Siemens PTI.

Change in planning
Siemens PTI, the software arm of Siemens Power Transmission and Distribution Inc., provides power system simulator for engineering (PSSE) products for electrical transmission planning, develops tools for maintaining and integrating transmission operations, and supplies distribution planning software, among other products.

And planning is what Siemens suggests utilities address to more accurately and flexibly accommodate the rising amounts of DER.

In collaboration with Siemens PTI, PSE&G studied the impacts of DER on its system using a model and methodologies to estimate feeder and substation hosting capacity, as well as evaluation of flicker, to simulate the system performance compared with real-data collection, explained Hugo Bashualdo, senior manager of distribution planning and microgrids at Siemens PTI, during the webcast.

Bashualdo said their study considered: When different levels of solar PV are integrated at different feeders, how will that affect the quality and reliability of service to adjacent customers? And how might it affect other considerations for power generation, transmission and distribution?

Specifically, said Mousa, they wanted to verify the existing limits on the 13 kV loop feeders.

“Think of it as a switch that operates in response to a change in voltage,” he said. “It reacts if the voltage is too high or too low. It monitors load and can boost the voltage when it’s too low or decrease it if the voltage is too high. It allows us to maintain the proper voltage and offers flexibility between customers.”

Mousa said the utility wants to avoid any excessive movement of the feeder regulator, which can be very damaging to the system because it’s interconnected with a lot of other circuits.

In fact, the need for the joint study was due to several circuits exceeding their existing limits, with more requests coming in to interconnect to circuits that exceeded their limits, said Mousa, who’s responsible for managing the utility’s entire distribution system and the 69 kV transmission system.

“And the bulk of the PSE&G load is supplied via 13 kV loop feeders. We needed to determine the solar impact on nearby customers and the impact on capacitors and transformers’ load tap changers,” he said.

In a nutshell, according to Bashualdo, the analysis steps included using a GIS model to understand the solar impact, to determine the new limits for the loop feeders and to address if any thermal or voltage violations existed.

Phase 1 determined the solar capacity limit on 13 kV feeders and substation transformers for a typical sunny day, both with and without system improvements, he said. Then in a phase 1 extension, they included a weather impact study on whether fast and slow moving clouds had any impacts.

“In collecting data from GIS, we also collected data from each distribution site in the field,” Bashualdo said. “We wanted to verify our models and try to find out what other benefits solar PV could bring to the distribution system. That’s exactly what we did.”

Bashualdo thinks that clear processes for updating models and verifying data encourages staff ownership of accuracy. When models aren’t verified, engineering time is wasted, he says.

“Confirming field data about assets, loads and DER is an essential step that can be integrated into everyday operations and changes can be registered as they occur,” he said.

Mousa said the collected data will help the utility make informed DER decisions as it moves forward on other projects and plans more such studies.

And as DER more fully penetrate the power system, failing to plan for their impacts — across policy, rate regulations and secure communications systems, for example — could lead to higher costs and lower reliability, EPRI says.