Federal hydropower regulators have scheduled a workshop to explore potential opportunities for development of closed-loop pumped storage projects at abandoned mine sites, as required by the America's Water Infrastructure Act of 2018.
Enacted by Congress and signed by President Trump in October 2018, the Act amends
several portions of the Federal Power Act which govern how the Federal
Energy Regulatory Commission issues preliminary permits, hydropower
licenses, and approvals for qualifying conduit hydropower facilities. Among other requirements, the Act directed the Commission to issue a rule establishing an expedited process for
issuing and amending licenses for closed-loop pumped storage projects
under this section.
The Act also includes provisions designed to facilitate exploration of the use of abandoned mine sites for pumped storage projects. Section 3004 of the Act requires the Commission to hold a workshop within 6 months to
explore potential opportunities for development of closed-loop pumped storage
projects at abandoned mine sites, and issue guidance within one year to assist applicants for licenses or preliminary
permits for closed-loop pumped storage projects at abandoned mine sites. In November 2018, the Commission docketed its action on Closed-loop Pumped Storage Projects at Abandoned Mines Guidance as Docket No. AD19-8-000 and established a schedule for rulemaking, public comment, and issuance of guidance.
The Commission has now issued a Notice of Workshop in the abandoned mine pumped storage docket, scheduled for April 4, 2019. The notice states that the workshop will involve roundtable discussions by panelists, moderated by Commission staff. The agenda for the workshop includes discussion of how to identify sites for development of closed-loop pumped storage projects at abandoned mines, as well as the benefits and challenges associated with the use of abandoned mines for pumped storage. The agenda also includes time for soliciting feedback from the workshop panel and other participants on what types of information would be most helpful to include in the guidance mandated by the Act.
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Showing posts with label mine. Show all posts
Showing posts with label mine. Show all posts
Dominion affiliate proposes Tazewell pumped storage project
Monday, October 2, 2017
A Virginia-based utility company has applied to federal regulators for a preliminary permit to study the feasibility of a pumped hydroelectric storage facility in the coalfield region of Southwest Virginia. If built, Dominion Energy Services, Inc.'s Tazewell Hybrid Energy Center Project could use mine water sources for the initial fill and makeup water.
On September 6, 2017, Dominion Energy Services, Inc. filed an application to the Federal Energy Regulatory Commission for a preliminary permit, pursuant to section 4(f) of the Federal Power Act, proposing to study the feasibility of the Tazewell Hybrid Energy Center Project. As described in Dominion’s application, a September 7 press release, and a September 29 notice by the Commission, the Tazewell project would be a pumped hydroelectric storage facility. According to Dominion, the project would “be operated by Dominion Energy Virginia for hydropower generation during peak energy demand periods and pumping during off-peak energy demand periods.” Dominion points to grid benefits from pumped storage including integration of intermittent power generation sources, enhancement of grid stability and supply of other ancillary benefits. The applicant notes that the site “could support multiple configurations, including different-sized pumped-storage facilities,” a flexibility which Dominion said enables it to determine the best environmental, technical and economic solution.
The project would not use any existing dams or hydroelectric facilities, but would involve new dams and other facilities constructed for the proposed project. In its application, Dominion described two alternative configurations — a smaller Alternative 1 and a larger-capacity Alternative 2 – featuring an upper reservoir and a lower reservoir. Under either alternative, Dominion described potential water sources “for the initial fill and makeup water” as
Dominion’s press release mentioned that it is also conducting in-depth studies of another potential site for a pumped hydroelectric storage facility, the former Bullitt Mine near Appalachia, Virginia. That mine has been closed since 1997 and is currently flooded.
In its application, Dominion cited 2017 Virginia legislation that it said “encourages one or more pumped storage stations and includes a requirement that all or a portion of it be powered by renewable energy produced in the coalfield region.” That legislation amended existing law to allow a utility to petition the State Corporation Commission for approval of a rate adjustment clause to recover from customers the costs of “one or more pumped hydroelectricity generation and storage facilities that utilize on-site or off-site renewable energy resources as all or a portion of their power source and such facilities and associated resources are located in the coalfield region of the Commonwealth ... regardless of whether such facility is located within or without the utility's service territory.” The coalfield region is defined as including seven counties and one city: Lee, Wise, Scott, Buchanan, Russell, Tazewell and Dickenson Counties and the City of Norton.
On September 6, 2017, Dominion Energy Services, Inc. filed an application to the Federal Energy Regulatory Commission for a preliminary permit, pursuant to section 4(f) of the Federal Power Act, proposing to study the feasibility of the Tazewell Hybrid Energy Center Project. As described in Dominion’s application, a September 7 press release, and a September 29 notice by the Commission, the Tazewell project would be a pumped hydroelectric storage facility. According to Dominion, the project would “be operated by Dominion Energy Virginia for hydropower generation during peak energy demand periods and pumping during off-peak energy demand periods.” Dominion points to grid benefits from pumped storage including integration of intermittent power generation sources, enhancement of grid stability and supply of other ancillary benefits. The applicant notes that the site “could support multiple configurations, including different-sized pumped-storage facilities,” a flexibility which Dominion said enables it to determine the best environmental, technical and economic solution.
The project would not use any existing dams or hydroelectric facilities, but would involve new dams and other facilities constructed for the proposed project. In its application, Dominion described two alternative configurations — a smaller Alternative 1 and a larger-capacity Alternative 2 – featuring an upper reservoir and a lower reservoir. Under either alternative, Dominion described potential water sources “for the initial fill and makeup water” as
(1) Mine ID P03_903 and (2) Mine ID P03_017. The initial fill water for the Project's reservoirs will be supplied by one or more of these water sources via a proposed pump and water conveyance system… Although the upper reservoir would be located on Oneida Branch and the lower reservoir would be located in West Fork Cove Creek, it is anticipated that the proposed Project will use mine water sources for the initial fill and makeup water.Dominion says it will evaluate the feasibility of relying on mine water sources under the preliminary permit.
Dominion’s press release mentioned that it is also conducting in-depth studies of another potential site for a pumped hydroelectric storage facility, the former Bullitt Mine near Appalachia, Virginia. That mine has been closed since 1997 and is currently flooded.
In its application, Dominion cited 2017 Virginia legislation that it said “encourages one or more pumped storage stations and includes a requirement that all or a portion of it be powered by renewable energy produced in the coalfield region.” That legislation amended existing law to allow a utility to petition the State Corporation Commission for approval of a rate adjustment clause to recover from customers the costs of “one or more pumped hydroelectricity generation and storage facilities that utilize on-site or off-site renewable energy resources as all or a portion of their power source and such facilities and associated resources are located in the coalfield region of the Commonwealth ... regardless of whether such facility is located within or without the utility's service territory.” The coalfield region is defined as including seven counties and one city: Lee, Wise, Scott, Buchanan, Russell, Tazewell and Dickenson Counties and the City of Norton.
FERC authorizes mine drainage microhydro
Friday, September 5, 2014
The Federal Energy Regulatory Commission has issued a hydropower license to a project whose turbines generate electricity from acid mine drainage. The micro-hydropower license issued to the Antrim Treatment Trust illustrates this unusual approach to the twin challenges of mine remediation and renewable energy.
In the 1980s, Antrim Mining, Inc. operated a surface bituminous coal mine in Pennsylvania. When water draining through the mine and into streams and rivers was found to exceed pollution limits, the Commonwealth of Pennsylvania charged the company with violations of mining and reclamation law. The charges led to a series of settlements through which Antrim agreed to improved water treatment facilities, including an off-the-grid hydroelectric facility. This micro-hydro plant would be powered by treated effluent flowing downhill out of lagoons. Antrim created the Antrim Treatment Trust to manage treatment of the mine water in 1991, then went out of business.
In an attempt to reduce the cost of treating the site's severe acid mine drainage, the Babb Creek Watershed Association identified micro-hydropower as an option for the site. In 2008, the association received an Energy Harvest Grant from the Pennsylvania Department of Environmental Protection. This $428,710 award was designed to support the installation of two hydroelectric turbines on the treatment plant's discharge, which was completed in 2012.
While the Federal Power Act requires most hydropower projects to secure a license from the Federal Energy Regulatory Commission, some off-grid hydropower projects that do not use the waters of the United States do not require licensure. In 2010, the Antrim Treatment Trust filed a Declaration of
Intent for a 40-kilowatt grid-connected project, but quickly revised its project to be off-grid after the Commission issued an order finding that a license was required for the grid-connected project. Once the project was off-grid, the Commission ruled that no license was required.
The Antrim treatment plant seems to have then operated one turbine, but left the second turbine non-operational. A 2012 article in the Williamsport Sun-Gazette suggested that with both turbines running and selling power into the electricity grid, the treatment plant could cut $12,000 in annual power costs and make $10,000 per year in new revenue. But this could require a FERC license, because the project would become connected to the utility grid.
The Trust appears to have decided that these economics were worth pursuing, because in 2013 it filed an application for a project license for a 40-kilowatt project. In the application, Antrim Trust proposed to bring a second identical turbine (currently in place but non-operational) online by installing additional indoor wiring with appurtenances within the existing powerhouse and treatment plant, and operate both turbines as a grid-connected project using the treated and/or untreated water.
As licensed, the Commission estimates the annual cost to develop and maintain the proposed 40-kW project is $9,356 or $37.42/megawatt-hour (MWh). The project will generate an estimated average of 250 MWh of energy annually. Based on Commission staff’s view of the alternative cost of power ($56.93/MWh), the total value of the project’s power is $14,233 in 2013 dollars. To determine whether the proposed project is currently economically beneficial, staff subtracts the project’s cost from the value of the project’s power. Therefore, in the first year of operation, the project is expected to cost $4,877 or $19.51/MWh less than the likely alternative cost of power - demonstrating economic benefit.
Micro-hydropower projects can make economic sense in some mine drainage situations and other places where water treatment is required and a suitable vertical drop or pressure is available. In Antrim's case, the project's success can partially be explained by the existence and purpose of the Trust, as well as the DEP grant to support project construction. If treated and untreated mine drainage can be used to generate hydroelectricity, what other unusual sources of power will arise?
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| The power of falling water, in the White Mountain National Forest in New Hampshire. |
In an attempt to reduce the cost of treating the site's severe acid mine drainage, the Babb Creek Watershed Association identified micro-hydropower as an option for the site. In 2008, the association received an Energy Harvest Grant from the Pennsylvania Department of Environmental Protection. This $428,710 award was designed to support the installation of two hydroelectric turbines on the treatment plant's discharge, which was completed in 2012.
While the Federal Power Act requires most hydropower projects to secure a license from the Federal Energy Regulatory Commission, some off-grid hydropower projects that do not use the waters of the United States do not require licensure. In 2010, the Antrim Treatment Trust filed a Declaration of
Intent for a 40-kilowatt grid-connected project, but quickly revised its project to be off-grid after the Commission issued an order finding that a license was required for the grid-connected project. Once the project was off-grid, the Commission ruled that no license was required.
The Antrim treatment plant seems to have then operated one turbine, but left the second turbine non-operational. A 2012 article in the Williamsport Sun-Gazette suggested that with both turbines running and selling power into the electricity grid, the treatment plant could cut $12,000 in annual power costs and make $10,000 per year in new revenue. But this could require a FERC license, because the project would become connected to the utility grid.
The Trust appears to have decided that these economics were worth pursuing, because in 2013 it filed an application for a project license for a 40-kilowatt project. In the application, Antrim Trust proposed to bring a second identical turbine (currently in place but non-operational) online by installing additional indoor wiring with appurtenances within the existing powerhouse and treatment plant, and operate both turbines as a grid-connected project using the treated and/or untreated water.
As licensed, the Commission estimates the annual cost to develop and maintain the proposed 40-kW project is $9,356 or $37.42/megawatt-hour (MWh). The project will generate an estimated average of 250 MWh of energy annually. Based on Commission staff’s view of the alternative cost of power ($56.93/MWh), the total value of the project’s power is $14,233 in 2013 dollars. To determine whether the proposed project is currently economically beneficial, staff subtracts the project’s cost from the value of the project’s power. Therefore, in the first year of operation, the project is expected to cost $4,877 or $19.51/MWh less than the likely alternative cost of power - demonstrating economic benefit.
Micro-hydropower projects can make economic sense in some mine drainage situations and other places where water treatment is required and a suitable vertical drop or pressure is available. In Antrim's case, the project's success can partially be explained by the existence and purpose of the Trust, as well as the DEP grant to support project construction. If treated and untreated mine drainage can be used to generate hydroelectricity, what other unusual sources of power will arise?
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