Storms keep coming, power goes out too often, and energy prices are high says Jefferson County, New York. It is the textbook cry for a microgrid solution.
The northern New York community described its problems in a feasibility study filed with the NY Prize, a state-sponsored competition to spur microgrid development.
The community is pursuing an ambitious $28.77 million microgrid, one that promises to cut energy costs by 10 to 15 percent for participants.
Proposed for Watertown, the microgrid is one of 83 that won seed money ($100,000 each) in an early stage of the NY Prize.
Project planners say the microgrid – with 25 distributed energy resources (DERs) — will help the community avoid brown outs and improve energy reliability and cost stability.
The community faces classic energy woes.
First, as a border town to Canada, it knows storms all too well.
Second, businesses and other facilities report high energy costs. They are unable to manage their energy use as efficiently as possible because they lack data about their energy usage patterns and trends. The feasibility study says that only one commercial customer has an interval meter and unfortunately, it was never installed to register usage.
Three, the community is no stranger to power disruption.
Area businesses report regular system outages that can cause productivity delays and retooling of equipment which can take three to four hours at a cost of $5,000 to $7,500 per hour. And power spikes have destroyed local business IT servers, according to the feasibility study.
The microgrid solution
Those served by the microgrid would include: Watertown’s Fire District Station 3, three buildings at the Jefferson County Community College, and eight manufacturing facilities located in the Jefferson County Industrial Park. In the event of a disaster, the microgrid would enable the community college to shelter and feed 600 town residents in addition to those residing within the microgrid footprint.
The microgrid would strengthen the regional electric grid by reducing demand at critical times. In addition, with its innovative low-cost energy infrastructure, the microgrid could provide its members, especially in the industrial park, with predictable budget stability, according to the study.
The community microgrid’s 25 DERs would include a 2,600 kW natural gas combined heat and power (CHP), 4,920 kW solar photovoltaics (PV) and 4,800 kW of battery storage.
As is commonly the case with US microgrids, the facility would interconnect to the central grid during normal operating conditions and help serve its needs.
Each of the DER’s has a specific contribution to the microgrid operation:
- CHP generation provides baseload power and energy needs, resource adequacy, demand response, and spinning reserve
- Solar PV provides daytime peak power and summer peak shaving, and frequency regulation and reactive power through smart inverters
- Battery storage systems provide resiliency, frequency regulation, voltage support, and back-up power
During periods of normal operation, the natural gas and PV systems would produce electricity for the utility grid. As designed, the system would have sufficient generating capacity during a major outage to meet the average demand for electricity from the ten facilities served by the microgrid. Back-up diesel generators and battery units would produce power only during an outage, when the microgrid would operate in islanded (non-grid) mode. The project team also notes that the system would be able to provide ancillary services to the main grid, including frequency regulation and reactive power support.
The CHP and battery units would have black start (emergency startup) capability and would be housed in containment platforms to shield them from extreme weather. While the solar panels would be exposed to snow storms and icy conditions, the overall microgrid design controls for this problem. The project team notes that the microgrid would be “always self-sustaining with regard to energy requirements and is capable of full operations of the host facilities at all times regardless of the status of the [main grid].”
The microgrid design incorporates the Eaton Power Xpert Energy Optimizer controller to synchronize generating devices with each other as well as with back-up devices and the utility. The central controller, via device controllers at each building, would also provide system status, set point values, alarm notices, and act as an historian to collect detailed data logging and operational information. A managed network switch would communicate with a wireless transceiver at each building location to form a microgrid LAN to coordinate communications with all microgrid devices.
This infrastructure would incorporate a combination of physical and wireless interfaces. For wireless, the team plans to build an intelligent mesh network. There are many advantages of using a mesh network, according to the team, including eliminating any single point of failure. Devices would have inherent ‘smart capabilities’ to ‘self-heal’ themselves in an event of a device failure. Also, this protocol would allow microgrid operators to easily communicate accurate real-time information to county officials and microgrid members through personal computers and mobile phones.
The Eaton controller also would island or disconnect the microgrid assets from the utility in the advent of a power outage or other energy event, and continue independent island operation to maintain voltage and frequency. The controller would reconnect and synchronize microgrid components with the utility as central power is restored and the facilities transition to a grid-connected mode.
Finally, the project recognizes that cyber security is a primary concern. Separate metering and sensory components would create privacy and cyber security for each microgrid participant. The microgrid would not share a member’s data with other members. A cloud based analytics and reporting system would secure data.
The project team proposes a microgrid business model that uses a standard power purchase agreement. Each member would rely on on-site energy but could also acquire energy from other DERs within the microgrid, as required. The team notes that this arrangement creates a stable, predictable energy budget for the life of the agreement.
The team recognizes that financing a community microgrid can be a many-headed hydra. At first pass, microgrid members would in essence pay for the project via energy payments over its 20-year life. However, if the member users cannot maintain their commitment their revenue would have to be replaced. Hence, the microgrid team is attempting to leverage private capital through various methods.
Because the underground infrastructure would be used not only by this project, but for others as well, the team has proposed splitting the underground infrastructure and the DER financing. This would allow the transmission infrastructure to receive separate grants or low interest loans from the US Department of Agriculture rural financing arm. The team says this would reduce overall component costs.
The DERs would be owned by a private Special Purpose Entity (SPE) consisting of the prime system energy integrator such as team member Entecco and funding entities such as the New York Green Bank. Jefferson County (or a county entity) could own the transmission infrastructure with a lease back to the SPE.
The project partners include Eaton, Entecco, Tecogen, Kraft, Cisco, Capital Innovations, Jefferson County, and Jefferson County Local Development.
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