SEASONAL PUMPED HYDRO STORAGE IN NEW ENGLAND

Based on the plan of eliminating fossil fuel plants (they emit CO2 and particulates) and nuclear fuel plants (they are alleged to be dangerous) by 2050, the existing gas, nuclear, coal and oil generating plants would be decommissioned and no new ones would be built.

 

This would require huge build-outs of wind, solar, and storage systems, and increased electricity supply via external ties to adjacent grids. There is no way one can close down nuclear, oil, gas and coal plants, have a major part of NE electricity from wind and solar, and not have TWh scale seasonal storage.

 

The storage systems would serve to:

 

1) Provide the peaking, filling-in and balancing services, 24/7/365

2) Smooth the variability and intermittency of wind and solar, 24/7/365

3) Cover extended wind and solar lulls, which occur at random throughout the year  

4) Cover weekly, monthly and seasonal variations of electricity generation.

 

http://www.windtaskforce.org/profiles/blogs/wind-plus-solar-plus-st...
http://www.windtaskforce.org/profiles/blogs/wind-and-solar-energy-l...

http://www.windtaskforce.org/profiles/blogs/world-coal-consumption-...

Generation and Load of New England Grid in 2016, per ISO-NE Data

 

Table 1/2016 ISO-NE data	Generation	Generation	System Load	Generation
	GWh	%	GWh	% of system load
Total Generation	105572	100.0	124416	84.9
Gas	52059	49.3	52059	41.8
Nuclear	32745	31	32745	26.3
Renewables	10231	9.7	10231	8.2
- Refuse	3316	3.1	3316	2.7
- Wood	3200	3	3200	2.6
- Wind	2519	2.4	2519	2.0
- Solar	658	0.6	658	0.5
- Landfill Gas	496	0.5	496	0.4
- Methane	42	0.04	42	0.0
Steam	0	0	0	0.0
Hydro	7465	7.1	7465	6.0
Coal	2555	2.4	2555	2.1
Oil	517	0.5	517	0.4
Other (c)	0	0	0	0.0
Net Flow over External Ties			20803	16.7
- Québec			12285	9.9
- New Brunswick			4842	3.9
- New York			3675	3.0
Pumping Load			-1959	-1.6
Net Energy for Load		100.0	124416	100.0

H-Q Building New Plants, Upgrading Other Plants: Increased electricity supply via external ties would require additional HVDC lines to Quebec. These lines could also serve to balance a part of the variability and intermittency of wind and solar, similar to Denmark using Norway’s hydro system to balance its wind electricity. Any peaking, filling-in and balancing services provided by H-Q would mean a lesser capacity of NE storage systems.

 

Below items 1 through 5 show H-Q would be able to have at least 5000 MW x 8766 x 0.60 = 26,298,000 MWh/y, or 26.3 TWh, for export via new power lines that are being proposed, in addition to existing exports. If that electricity were not there, would various private entities propose HVDC power lines worth billions of dollars?

 

1) Hydro-Québec Production obtained the necessary approvals to build a 1,550-MW hydroelectric complex on the Rivière Romaine, north of the municipality of Havre-Saint-Pierre on the north shore of the St. Lawrence. The complex will consist of four hydro plants, Romaine 1, 2, 3 and 4, with total average output of 8.0 TWh/y; CF 0.60.

 

2) Other power plants up north are being refurbished (better water flow) and being upgraded with more efficient turbines, i.e., will produce more electricity.

 

3) Existing plants not being fully utilized (water over the spillways instead of through the turbines, especially in summer).

 

4) H-Q building future hydro plants and wind systems.

 

5) Quebec, New Brunswick and New York supply about 20.8 million MWh/y of electricity to the NE grid. See table 1.

 

With additional HVDC transmission lines, the above items likely would enable an external tie supply of about 2 x 20.8 = 41.6 million MWh/y by 2050.

 

Electricity Generation in New England With Pumped Hydro Storage

 

Assumptions for Determining Storage Requirements: The calculated capacity of the storage system was based on:

 

- Refuse (municipal waste) generation increased to 5 times existing; would require an NE mandate.

- Wood generation not increased, because wood is already harvested near 50% of net biomass growth.

- NE hydro generation increased by about 20%, mostly by upgrading existing plants.

- External ties increased to 2 times existing.

- Increased wind and solar to provide remaining electricity supply for demand, including storage system losses.

 

Storage System Charging and Discharging: Based on ISO-NE generation and load data for 2016, the storage capacity to cover seasonal variations would need to be capable to provide about 8 TWh, delivered as AC.

- Generation from all sources, including the variable wind and solar, would be stored in the reservoirs.

- Water would be drained from the reservoirs, as needed for demand 24/7/365. See Storage Balance graph.

 

Based on the above-assumed generation, the system would be:

 

- Charged at about 3 TWh at the start of January

- Charged at about 8 TWh from the middle of May to the middle of June

- Fully discharged at the end of September

- Charged at about 3 TWh from the start of December to the end of January

 

1) Generation from all sources would have to cover electricity demand, plus an additional 21.9% to cover the round-trip losses of the pumped storage hydro plants.

2) Generation would drive motor-driven turbines to charge the upper reservoirs. The turbines would receive water, via pipes, from the lower reservoirs.

3) Discharge from the upper reservoirs would drive turbine generators to supply electricity to the grid. The water would drain, via pipes, to the lower reservoirs.

4) Items 2 and 3 would be on a 24/7/365 basis.

5) The storage systems would provide the peaking, filling-in and balancing services, as in Norway and Quebec.

 

H-Q Reservoir Hydro Storage and NE Pumped Hydro Storage: In Quebec, the H-Q reservoirs receive water from the watershed area surrounding each reservoir. Water is withdrawn from the reservoirs, as needed, to generate almost all of the electricity to satisfy the demand of the entire Province of Quebec, 24/7/365, plus to provide about 33 TWh/y for export. H-Q has about 37,000 MW of hydro plants. The active water storage of the reservoir plants is about 1/3 of total storage. The active storage is equivalent to about 176 TWh/y, about equal to Quebec’s annual electricity requirements.

 

In NE, with pumped storage, during windy and sunny days, wind and solar electricity generation, which could total at least 15,000 MW, must be stored. That means at least 15,000 MW of pump-turbine sets would be required to pump water from the lower reservoirs to the upper reservoirs. The estimated turnkey capital cost would be 15000 x $2 million/MW = $30 billion.

 

During high system demand days, usually during summer (water flowing from the upper reservoirs to the lower reservoirs), about 30,000 MW of turbine-generators sets would be required to generate almost all of the electricity to satisfy the NE demand, 24/7/365, plus an additional 21.9% to cover the round-trip losses of the pumped storage hydro plants, less whatever is supplied by other sources, and via external ties. The estimated turnkey capital cost would be 30000 x $2 million/MW = $60 billion.

 

The active water storage would be about 37 billion m3 for the upper reservoirs, plus 37 billion m3 for the lower reservoirs.

Total storage would be 3 x 37 = 112 billion m3 for the upper reservoirs, plus 112 billion m3 for the lower reservoirs.

The combined volume of the upper reservoirs would be 53,000 m long x 53,000 m wide x 40 meter deep = 112 billion m3

The combined volume of the lower reservoirs would be 53,000 m long x 53,000 m wide x 40 meter deep = 112 billion m3

 

The building of the reservoirs would require damming up dozens of NE valleys to create lower reservoirs and connect them to upper reservoirs. A large number of people, and the detritus of modernity, etc., would need to be removed and relocated elsewhere. The estimated turnkey capital cost would be $50 to $100 billion.

 

The estimated total turnkey capital cost would be 30 + 60 + (50 to 100) = $140 to $190 billion. This obviously is a ballpark number, but it gives some idea of the implications of closing nuclear and fossil plants. Any peaking, filling-in and balancing services provided by H-Q would mean a lesser capacity of NE storage systems.

Storage System Capacity: It is assumed the storage system would consist of a number of 100 MW pumped storage plants, each with upper and lower reservoirs.

NOTE: This assumption is purely hypothetical, because, as shown above, about 15000 MW of pumping and about 30000 MW of electricity generation would be required. However, the assumption enables the calculation of the water volume of the active storage.

Static head is 85 meter; charging head 89.25 m; discharging head 80.75 m.

Efficiency = 0.98, transformer x 0.95, motor x 0.95, turbine = 0.884

Water storage increases by the equivalent of 5/0.884 = 5.66 TWh from end Jan. to end May, or 4/12 x 8766 = 2922 h, to deliver 5 TWh as AC to the HV grid.

Water storage decreases by the equivalent of 8/0.884 = 9.05 TWh to 0 TWh, to deliver 8 TWh as AC to the HV grid.

 

NOTE: If delivering 100 MWh from the storage system to the HV grid, about 100/0.884 = 113 MWh has to be in storage, which requires a supply from the HV grid of about 113/0.884 = 128 MWh. The AC-to-AC round-trip efficiency is 100/128 = 0.781, which is average for pumped storage.

The addition of pumped storage systems requires an additional 21.9% of electricity to the system load. Energy systems analysts often do not mention this inconvenient fact. See table 1.

 

Pumping

This calculation assumes a steady supply of water during the 2922 hours of filling time. The below calculation shows 29 x 100 = 2900 MW of pumping capacity is required.

 

In reality, this is not the case, because on windy and sunny days, wind and solar electricity generation could total at least 15,000 MW and the pumping capacity would need to match that level of generation.

From HV grid, ideal = QdgH = 100 m3/s x 1000 kg/m3 x 9.81 m/s2 x 89.25 m = 87.6 MW

From HV grid, actual = QdgH/eff = 87.6 x 1/0.884 = 99 MW

From HV grid to one plant = 99 MW x 2922 h = 289,257 MWh

From HV grid to all plants to deliver 5 TWh as AC to HV grid = 5 TWh/(0.884 x 0.884) = 6.39 TWh. See above note.

Plant capacity factor = 0.75, assumed

Number of plants = 6.39 TWh/(289257 MWh x 0.75) = 29 plants  

Water addition to reservoirs = 29 x 0.75 x 100 m3/s x 3600 s x 2922 h = 23 billion m3.

 

Reservoir Storage and Size

Active storage = 9.05/5.66 x 23 = 37 billion m3

Total storage = 3 x 37 = 112 billion m3

Combined water volume of all reservoirs = 53,000 m x 53,000 m x 40 meter = 112 billion m3 

 

Reservoir Hydro Plant		Discharging	Charging
Flowrate, Q	m3/s	100	100
Density, d	kg/m3	1000	1000
Gravity, g	m/s2	9.81	9.81
Head, static, H	m	85	85
Head, flowing, adjusted	m	80.75	89.25
Ideal
Power to HV grid = QdgH	kW	79215750
Power to HV grid	MW	79.2
Power from HV grid = QdgH	kW		87554250
Power from HV grid	MW		87.6
Actual
Turb eff		0.95	0.95
Gen eff		0.95	0.95
Transformer eff		0.98	0.98
Power to HV grid = QdgH*eff	MW	70.1
Power from HV grid = QdgH/eff	MW		99.0
Reservoir Charging
Electricity from reservoir	MWh	5000000
Discharging factor		1.13
Adjusted electricity from storage		5653231	5653231
Charging factor			1.13
Adjusted electricity for charging			6391804
Charging time	h		2922
Electricity from HV grid	MWh/plant		289257
Equivalent plants required			22
Plant capacity factor			0.75
Plants required			29
Water addition to reservoirs	m3		23244595159
Water addition to reservoirs	billion m3		23

 

Seasonal Reservoir Status: 

- Initially the reservoir contained 88.5 billion m3, the water equivalent of 3.39 TWh, to deliver about 3 TWh as AC to the HV grid.

- From the end January to the end of May, about 23 billion m3 was added to the reservoir, the water equivalent of 5.66 TWh, which topped off the reservoir at 111.5 billion m3.

- From the end of May to the end of September, the reservoir provided 37 billion m3, the water equivalent of 9.05 TWh, which reduced the reservoir to 74.5 billion m3, to deliver about 8 TWh as AC to the HV grid.

 

Reservoir Status	TWh eq	Change	Status
		billion m3	billion m3
Initial			88.5
Increase	5.66	23	111.5
Decrease	9.05	-37	74.5

APPENDIX 1

100% RE folks often talk about wind and solar being so competitive with fossil and nuclear. They likely have near-zero experience designing energy systems, but pontificate anyway, and get listened to by legislators and bureaucrats. What they do not mention is the various costs charged to the public, which make wind and solar appear less costly/kWh than in reality, such as:

 

1) Any direct subsidies (cash grants, rapid appreciation, low-cost loans, etc., to generator owners, which enable them to bid on electricity supply contracts that appear competitive with fossil fuels, hydro and nuclear.

 

2) The costs of externalities, such as:

 

– Any peaking, filling-in and balancing performed by the other generators
– Any battery systems to stabilize distribution grids with many solar systems.
– Any measures to deal with DUCK curves, such as utility-scale storage and demand management
– Any grid expansions and augmentations to connect distributed solar systems

 

Those costs, as c/kWh, are not easily quantified, and as a result they are charged to ratepayers via rate schedules, and to taxpayers. Ultimately, they are reflected in the increased costs of goods and services, which usually act as a headwind to economic growth. There is no free lunch.

 

For example, to bring wind electricity from the Panhandle in west Texas to population centers in east Texas, $7 billion of transmission was built. The entire cost was “socialized” as a surcharge on residential electric bills.

 

http://www.theenergycollective.com/energy-innovation-llc/2420282/ra...

http://www.windtaskforce.org/profiles/blogs/subsidized-solar-system...

http://www.windtaskforce.org/profiles/blogs/the-true-cost-of-solar-...

http://www.windtaskforce.org/profiles/blogs/the-true-cost-of-wind-e...

http://www.windtaskforce.org/profiles/blogs/a-very-expensive-offsho...

APPENDIX 2

New England Will Have Brownouts and Higher Electricity Prices: During the bitter cold stretch that started right after Christmas and continued into 2018, ISO-NE had a tough time keeping the electricity flowing to homes and businesses throughout New England.

 

Facing a shortage of natural gas because of a dearth of pipeline capacity, they relied on old oil and coal plants to provide enough electricity.

 

With oil supplies rapidly running low, ISO-NE, responsible for ensuring the region’s electricity supply, said keeping the whole system up and running proved “extremely challenging” as operators “worked around the clock to keep the power flowing and the grid stable.”

http://www.sunjournal.com/maine-may-face-brownouts-higher-electric-...

APPENDIX 3

Norway Electricity Generating System

 

Norway electricity generation was about 149 TWh in 2016, about 143.4 TWh, or 96.3% from reservoir hydro plants and run of river hydro plants. Norway total hydro reservoir capacity is 84.3 TWh.

https://www.ssb.no/en/energi-og-industri/statistikker/elektrisitet/aar

http://wwwdynamic.nordpoolspot.com/marketinfo/rescontent/norway/res...

 

All those plants are connected to the high voltage network. Modulating the water flows through the turbines performs the peaking, filling-in and balancing, PFB, functions.

 

The combined storage reservoirs act as a giant battery that is continuously charged with rainwater and runoff and discharges water through turbines, as needed to meet electricity demand 24/7/365, year after year.

 

The HV networks of Denmark, Germany and the Netherlands are connected to the HV network of Norway with HVDC lines. During periods of higher winds, electricity (usually at near-zero or negative wholesale prices) is sent via these lines to Norway, which merely reduces the water flow through the turbines.

 

Norway uses the “saved” water to generate electricity when wholesale prices are high, such as during wind and solar lulls and higher demands. Germany would like to send its excess electricity from North Germany to South Germany but HVDC lines, already 15 years overdue, do not exist, mostly due to NIMBY concerns.

 

Quebec Electricity Generating System

 

Quebec electricity, generated and purchased, was about 217 TWh in 2016, of which about 172 TWh/y from 36911 MW of 63 large hydro plants.

 

- Reservoir, 28 plants, capacity 26843 MW, production about 124.7 TWh in 2016

- Run of river, 35 plants, capacity 10068 MW, production about 47.3 TWh in 2016

 

The active water storage of the reservoir plants is about 1/3 of total storage. The active storage is equivalent to about 176 TWh/y, about equal to Quebec’s annual electricity requirements.

 

The active storage could generate another 176 - 124.7 = 51.3 TWh/y, however, this is dependent on environmental impacts, recreation, water levels, flow rates, navigation, flood control, and the weather.

 

All plants are connected to the high voltage network. Modulating the water flows through the turbines performs PFB functions.

The combined storage reservoirs act as a giant battery that is continuously charged with rainwater and runoff and discharges water through turbines, as needed to meet electricity demand 24/7/365, year after year.

 

http://www.hydroquebec.com/learning/hydroelectricite/gestion-eau.html

https://en.wikipedia.org/wiki/Hydro-Québec

 

In 2016, Quebec total net exports were 32.6 TWh, of which 20.8 TWh, directly or indirectly, to New England (per ISO-NE) and 11.8 TWh to other states, such as New York State. Revenues were $1.568 billion; average sales prices 4.8 c/kWh.

http://www.hydroquebec.com/sustainable-development/energy-environme...

The active storage is 129.7/336.7 = 38.5% of the total storage, for the 5 listed hydro plants.

All H-Q active storage could generate 176 TWh/y, about equal to Quebec's consumption

http://www.hydroquebec.com/learning/hydroelectricite/gestion-eau.html

 

Storage Capacity	Total	Generation	Active
	billion m3	billion m3	%
Caniapiscau	52.6	39.0	74.0
Manicouagan	137.9	35.2	25.5
La Grande 3	60.0	25.2	42.0
Robert-Bourassa	61.7	19.4	31.5
Aux Outardes 4	24.5	10.9	44.5
	336.7	129.7	38.5

 

New England Electricity Generating System

 

NE generated about 105.6 TWh in 2016, and imported about 20.8 TWh (Quebec 12.3 TWh; New Brunswick 4.8 TWh; NY 3.7 TWh). Fuel sources for generation were: gas 49.3%; nuclear 31%; hydro 7.1%; refuse 3.1%; wood 3%; coal 2.4%; wind 2.4%; solar 0.6%; oil 0.5%.

 

Modulating the outputs of the gas turbines, which requires more Btu/kWh and emits more CO2/kWh, performs most of the PFB functions. The modulating would increase as more wind and solar is added to the system.

 

NE wholesale prices have averaged about 4.5 to 5 c/kWh since 2009. Closing down gas, nuclear, coal (all of which generate at less than 5 c/kWh), and oil plants, would create a huge generation deficiency that likely would need to be offset mostly by increased build outs of wind, solar, refuse, hydro, plus increased imports via tie lines, plus large-scale storage systems. The PFB functions would be performed by storage systems to accommodate the variability and intermittency of wind and solar.

 

- Wind; ridgeline about 9 c/kWh, heavily subsidized; offshore about 19 c/kWh, heavily subsidized.

- Solar; large-scale, field-mounted about 13.5 c/kWh, heavily subsidized; residential rooftop about 19 c/kWh, heavily subsidized.

APPENDIX 4

MIT Professor Steven Chu, former US-DOE Secretary, stated:

 

- Whereas, the turnkey capital costs of battery systems likely would be about 50% less over the next decade, that storage approach would never be cheap enough to accommodate the big seasonal shifts in renewable power production.

- Battery systems could prove viable for storing solar electricity produced during midday hours for use during late afternoon/early evening hours, and “maybe” for up to a week later, but not over seasonal time­frames.

- New technologies are needed to convert “low-cost” renewable energy into chemical fuel whenever excess solar and wind electricity is available. Low-cost hydrogen from renewables, stored underground, may become an economically feasible approach. See note.

- Fuel cells hold more promise for urban power storage, particularly those based on liquid hydrocarbons. However, whereas technically feasible, they are not economical at present.

http://www.powerengineeringint.com/articles/2018/01/former-obama-en...

 

NOTE: One approach would be to produce electricity with base-loaded nuclear plants, and produce hydrogen with electricity and store it in underground caverns all over the world. This would need to apply to at least 70 - 80% of total primary energy, not just the 40% used for producing electricity.

APPENDIX 5

Hydro-Quebec Electricity Generation and Purchases: Google this URL for the 2017 facts. The H-Q electricity supply is an order of magnitude cleaner than the Vermont supply.
http://www.hydroquebec.com/sustainable-development/energy-environme...

 

	2017
	GWh
Hydropower generated	177091
Purchased	44006
- Hydro	31610
- Wind	9634
- Biomass and waste reclamation	2021
- Other	741
Total RE generated and purchased	221097

 

NOTE: Gentilly-2 nuclear generating station, plus three thermal generating stations (Tracy, La Citière and Cadillac) were shut down.

 

Hydro-Quebec Export Electricity: H-Q net exports were 34.4 TWh/y in 2017; provided 27% of H-Q net income, or $780 million, i.e., very profitable.

H-Q export revenue was $1,651 million in 2017, or 1641/34.4 = 4.8 c/kWh. See page 24 of Annual Report URL.

This is for a mix of old and new contracts.

Revenue = 1641

Net profit = 780

Cost = 1641 - 780 = 861

Average cost of H-Q generation = 861/34.4 = 2.5 c/kWh

GMP buys H-Q electricity, at the Vermont border, for 5.549 c/kWh, under a recent contract.   

GMP sells to me at 19 c/kWh, per rate schedule.

H-Q is eager to sell more of its surplus electricity to New England and New York.

 

It is entirely political what consumers PAY for that electricity.

That is implemented by rate setting, taxes, fees, surcharges, etc., mostly on household electric bills, as in Denmark and Germany, etc.

 

http://news.hydroquebec.com/en/press-releases/1338/annual-report-2917/

http://www.hydroquebec.com/data/documents-donnees/pdf/annual-report...

http://www.windtaskforce.org/profiles/blogs/green-mountain-power-co...

http://www.windtaskforce.org/profiles/blogs/increased-canadian-hydr...

 

GMP buys at 5.549 c/kWh, per GMP spreadsheet titled “GMP Test Year Power Supply Costs filed as VPSB Docket No: Attachment D, Schedule 2, April 14, 2017”. That is at least 50% less than ridgeline wind and large-scale field-mounted solar, which are heavily subsidized.

http://www.hydroquebec.com/sustainable-development/energy-environme...

APPENDIX 6

This study shows 100% wind, solar and hydro, as advocated by Jacobson and others, would yield an inoperable electrical system in the UK. The lack of firm and dispatchable ‘backup’ energy systems – such as nuclear or power plants equipped with carbon capture systems – means the electricity supply would fail often enough that the system would be deemed inoperable. Even with 77% wind, solar and hydro, plus nuclear and biomass, about 9% of the year demand would not be met. Clearly, significant storage systems would be required.

 

NOTE: Electrical systems typically have 99.97% reliability or better, i.e., demand is not met only 0.03% of the year.

http://www.imperial.ac.uk/news/185146/running-renewables-sure-about...