National Grid's Blueprint for DG Interconnections
National Grid has experienced enormous growth in distributed generation (DG), interconnecting more than 62,000 customers and representing more than 1.38 GW of capacity systemwide. Over the last two years, the utility has been interconnecting DG customers at the same pace as new gas service.
Initially, National Grid was not equipped in parts of its service territory to process such volume within the timelines specified in the interconnection tariff. A rush of demand led to long wait times and required quick corrective action to rightsize the team and respond better to customer needs. National Grid evolved technical standards, policies and processes to enhance the customer’s experience and to help meet regulatory and legislative renewable energy goals.
“It was very clear that we needed to take action,” said Carol Sedewitz, National Grid’s vice president of electrical asset management. “This leap in demand forced us to think creatively about how to process interconnection applications efficiently, both from a time and cost perspective. We’re better off today because of this challenge.”
Four-Point Plan
The utility instituted a four-point plan that would soon yield shorter wait times and lower interconnection costs:
• Increased staffing — quadrupled the distributed generation team to respond to customer demand
• Single point of contact – established a single point of contact for customers and regulators to resolve concerns
• Technical collaboration — formed partnerships with industry organizations and key developers to identify solutions to major concerns
• Education and outreach — enhanced understanding of DG interconnection process through webinars and seminars.
As utilities prepare to face increasingly severe and frequent storm events, their customers are doing the same. Streamlining and improving processes will help to accommodate an anticipated increase in campus and facility microgrid projects aimed at making large customers more resilient in the face of a storm. This increased demand coupled with an ambitious state energy policy across the Northeast U.S. will mean more aggressive timelines than ever for interconnecting distributed energy resources.
Eliminating Barriers
Technical collaboration with industry groups, solar developers and regulators helped National Grid to identify a major barrier to project completion for its customers. Most of the capacity installed in the utility’s service territory is coming from large, complex projects. Systemwide, approximately 56% of the proposed capacity is submitted from less than 3% of the applications. Historically, these installations required direct transfer trip (DTT) — a costly upgrade — based on utility standards for risk of islanding.
Through communication with inverter manufacturers and collecting information from risk-of-islanding studies on proposed projects, National Grid gained experience and an understanding of various inverters. The utility found most inverters — those that are UL 1741 certified — do not require DTT and, instead, can use reclose blocking.
Where screens for islanding show possible islanding risk, in lieu of DTT for most UL 1741 certified facilities, National Grid now installs utility-owned point-of-common coupling (PCC) reclosers and activates reclose blocking on midline devices. The PCC recloser provides the utility visibility during remote switching as well as a layer of protective functions for utility faults. These additional safeguards can help to reduce the utility’s concerns for adverse events on the system while lowering installation costs for the customer.
By identifying and offering a viable risk-of-islanding mitigation alternative to DTT, National Grid has significantly reduced the time, cost and effort needed to modify its substations. With this barrier removed, most projects now avoid an estimated US$350,000 in utility costs and 12 months of installation time. National Grid revised its cost estimates for approximately 90 projects that originally had triggered the need for DTT, removing approximately $32 million from its work scope. This process improvement has been responsible primarily for helping to reduce the utility’s average installation cost of solar facilities greater than 1 MW by $165/kW.
Additionally, the elimination of DTT and the use of the PCC reclosers with reclose blocking led to other cost savings from the customer’s side:
• Supervisory control and data acquisition (SCADA) requirements are included in National Grid’s device, removing the need for a remote terminal unit (RTU) for generation-only sites. This can result in a cost savings of $50,000 to $60,000.
• Negating the need for a RTU eliminates the associated telecommunications data circuit. This can result in a recurring cost savings of approximately $300/month for the life of the installation.
• There is a potential to eliminate some requirements from lengthy witness testing, which costs approximately $3000 to $6000.
Piloting More Savings
National Grid has identified another costly upgrade and is piloting a solution to reduce this cost to customers and save on interconnection time, as well. In general, once the aggregated capacity of the proposed DG on a substation transformer exceeds 67% of the transformer’s minimum load, the next DG customer is required to cover the cost of a critical substation upgrade — transmission ground fault protection, or 3V0. On average, 3V0 installations represent an approximate $400,000 portion of project costs. National Grid is piloting a program whereby the utility completes the substation upgrades prior to any one customer interconnecting and then charges customers only their appropriate share as they interconnect to that substation.
“Distribution substations were not designed for reverse power flow from the levels of DG integrating with the system,” said Neil LaBrake, director of retail connections policy and standards at National Grid. “The DG projects frequently require costly system upgrades when the transmission voltage-sensing equipment requires space in the substation, control house additions and digging within the substation. All of these currently require significant time to build and design.”
An overall asset strategy for 3V0 upgrades throughout National Grid’s U.S. network is evolving from planning criteria to engineering detailed evaluation and construction opportunities. National Grid aims to reduce the cost and timelines for installing transmission ground-fault protection such as 3V0 with these initiatives.
Simplifying the Process
In addition to finding cost savings, National Grid has used its education and outreach strategy to streamline the process for large, complex installations. As the volume of applications increased, National Grid found the customer-generated witness test procedures for all types of generation varied in format, technical content and complexity. This variance delayed reviews, increased the risk of human error and made communication about complex interconnection requirements frustrating.
In response to these challenges, the utility developed a National Grid witness test template that provided easy-to-understand test format guidelines and expedited the interconnection process. Available to customers on National Grid’s website, the template enables customers to see the minimum requirements for typical witness tests in a simple format.
Customers can enter standard minimum information quickly and efficiently, and use the template to write their test procedures in a format that more clearly communicates the detail expected for relay settings and test steps. For example, the witness test template shows at least two tests are required to proof out the 5-minute reconnect time required by the Institute of Electrical and Electronics Engineers (IEEE) 1547 standard: one test to show the facility waits 5 minutes to reconnect, and a second test to prove the facility is looking for healthy utility voltage and frequency during that 5 minutes before reconnecting.
The complex requirements for interconnection affect the safety and reliability of the power grid. Testing is key to proving installations operate effectively and avoid equipment damage by tripping for faults, reducing power-quality issues, and ensuring campus or facility microgrids avoid inadvertent islands of utility equipment. This template will help to streamline the witness test process for facility microgrids and other customer installations for years to come.
Keeping Pace with Change
National Grid’s expanded staff continues to look for ways to improve the customer’s DG interconnection experience through cost savings, shortened timelines and less process friction.
“We recently launched an online application portal that we’re really proud of,” said Kevin Kelly, National Grid’s director of customer energy integration. “Customers are now able to enter their project information online, directly track the status of their project throughout the interconnection process and make electronic payments. Additional functionality is being developed to help further compress lead times. We have already reduced approximately three days from the application review stage of the process.”
Because of its collaborative efforts with regulators, industry and others, National Grid intends to continue with active participation in established policy and technical working groups. Customers are quickly becoming more sophisticated in their energy choices and the demand for utilities to keep pace with their expectations will not slow down. Providing a streamlined single point of contact, maintaining communication with regulators, increasing education and outreach, and partnering to develop technical solutions will help utilities to meet and exceed customer expectations. ♦
Jeannie (Piekarz) Amber has reviewed distributed generation protection for the past four years in the retail connections engineering department at National Grid. She has helped to interconnect several facility microgrid sites, such as hospitals and industrial plants, as well as countless standalone inverter-based projects. She holds BSEE and MSEE degrees from Clarkson University and serves as secretary for the revision of IEEE 1547.1.
Vishal Ahirrao is the manager of customer energy integration at National Grid, located in Waltham, Massachusetts, U.S. Ahirrao holds a BSEE degree from Savitribai Phule Pune University and an MS degree in electrical and computer engineering from the New York Institute of Technology. After six years in the renewable energy field, he has helped customers to connect more than 500 MW of solar.
Check out the February 2018 issue for more articles, news and commentary.
