A very windy week at the end of December provides clear evidence of renewable generation being constrained. What implications does that have for the 'plan'?
I'm beginning to believe that a lot of this net-zero stuff is simply political posturing. So that our dear leaders can stand up in front of the world's media and claim they've installed 100% renewables. The fact that, as you have shown, most of this 100% is never used is something that's easy to characterise as a trifling detail that needn't concern the voters.
How many AAs would we need for 16TWh?
Assuming a 1.5V AA battery discharging at 100mA can yield 2Ah we have a capacity of 3Wh per battery.
16TWh = 16 * 10^6 * 10^6Wh requires ~5 trillion AAs. That's a lot of silenced drumming bunnies.
This equates to 125 million tonnes (25 grams each) or 1250 aircraft carriers.
Not trivial for a small island and I hope my arithmetic is correct!
Hi Chris and thanks for the reply. I was being somewhat tongue-in-cheek!
It seems like Nature has already found a good enough way of storing energy - fuels. However our technocratic leaders seem to have become obsessed with electricity, presumably because it is ostensibly a 'clean' and 'renewable' form of power. The problem of actually making and storing it doesn't fit the mass psychosis.
Of course, someone may come up with a breakthrough next week which allows battery energy densities comparable to our petrol tanks.
Getting real data on constraints is difficult. You can get an approximation by looking at the wind forecast vs outturn reports - any big change downwards from a high forecast to a lower actual almost certainly represents curtailment, though it is hard to be precise about how much (and that must be a real problem anyway - you can't estimate what wasn't produced with certainty).
A more nitty gritty approach is to look at output wind farm by wind farm, but that is painful in terms of accessing and downloading the data. However, it can be very revealing about what drives curtailments between one wind farm and another. There are various categories of wind farms contractually.
The simplest are those which are just paid market price for their output. These are wind farms that have no Renewables Obligation support, and either have yet to qualify for CFD support because they are not fully commissioned, or have not taken up their CFDs in the present strong market conditions that offer a much better return than their lowball CFD strike price (Triton Knoll, Moray East, Hornsea 2). These will have every incentive to curtail on the economics any time market prices are negative: they can simply buy back any forward sale of output at a negative price and bank the profit, rather than simply accepting the forward sale price at a lower margin. All they stand to lose are REGOs, although those have recently started to become of material value rather than being worth just a few pence per MWh.
Next are wind farms paid Renewables Obligations for every MWh they generate. In order to curtail they need to be compensated for the loss of any ROs they would earn. Different wind farms are entitled to different levels of ROs, so it will be the ones that are on the lowest RO band that are cheapest to curtail, and will be first in the pecking order where a constraint is operationally required because there is insufficient transmission capacity somewhere on the system (the constraint need not be in the immediate vicininty, but might be - more likely it will be the chokepoint of the Scotland-England transmission flows). Meanwhile the more expensive wind farms get to keep on producing. The market price tends to be set by the size of subsidies at risk (RO+REGO), and will be negative, and the curtailment payment will be of similar magnitude.
Wind farms on CFDs get paid their full strike price in compensation when market prices are negative, Their net proceeds are the strike price reduced by the negative market price, which will in most cases still leave them with a handsome income and thus no incentive to curtail. The first exception to this is that should day ahead intermittent market reference prices be negative for six or more contiguous hours no compensation is paid for the duration, and they have full market exposure to negative prices, and thus an incentive to curtail. Future rounds of CFDs will see the six hour minimum dropped, with any hour with negative prices offering no protection - potentially a big income hit compared with earning the strike price on more or less 100% capacity production on a windy day.
The other exception is when National Grid decides to persuade a CFD wind farm to curtail for operational or other reasons. It appears this has been happening with Beatrice quite regularly, despite the fact that it would be entitled to its full strike price - currently £175.47/MWh - if it carried on producing to offset any negative market price. I have yet to track down its compensation payments, but I plan to be asking questions as to why consumers have been paying out very large compensation when much cheaper compensation for RO generators on 1 or 2 ROCs/MWh ought to be available. The Beatrice accounts suggest the compensation has been more than generous. Perhaps they are being asked to free capacity so that National Grid can reduce its liabilities for failure to connect other wind farms at all.
You know far more than me in this area... is there *anyone* in the relevant Gov Departments even remotely interested in entering contractual arrangements that *don't* end up with tax- and bill-payers being royally screwed?
Is it possible to produce truly ‘green’ hydrogen and store it securely?"
So what would we do with that hydrogen taken from storage in our 'all-electric' paradise?
Those who blithely respond "generate electricity with it" would be unaware of reality regarding our existing CCGT & OCGT plants.
Section 3.7.1.9 Gas turbines on page 32 of HSE's "Injecting hydrogen into the gas network – a literature search" informs:
"A particular concern regarding ignition is the presence of hydrogen; since this gas ignites easily, there is concern that even small quantities of hydrogen in natural gas would be catastrophic for turbine behaviour. To illustrate this apprehension one major turbine manufacturer allows only traces of hydrogen in the fuel gas, while another manufacturer allows only 8.5% of hydrogen"
I think "Is it possible to produce truly ‘green’ hydrogen and store it securely?" will be the 64 billion dollar (or maybe 64 trillion dollar) question.
BEIS seems set on the idea that ultimately we'll have to convert (surplus) renewable power into chemical energy in order to be able to store that energy across weeks / seasons.
Quite how you take huge spikes of surplus power randomly followed by huge shortages, to feed electrolysers that need constant power, I really don't know.
How you transport and store H2 safely in the immense quantities needed - salt domes being the only credible containment at sufficient scale but also only being possible in limited areas of salt geology - equally I don't know.
Gas turbine developments allowing operation on up to 100% hydrogen? In the works, apparently. They are certainly not going to be the GTs we are using today. Whether it's worth it because of the conversion inefficiencies? Whether industrial-scale fuel cell electrical generation would be better?
As the Hydrogen Science Coalition and others keep saying, if the aim is decarbonisation, 'green' hydrogen should first be reserved for the ammonia we need to keep feeding people, displacing grey hydrogen.
Whether next would be synthesis of methanol for fuel across seasons? - absolutely massive industry needed, more conversion inefficiencies, but at least methanol's a liquid at room conditions, so it's much easier to store.
Huge, huge problems to which I don't see any solid answers as yet.
"Some context to those numbers: Dinorwyg stores up to 9,200 MWh and took over a decade to build. In total across the UK we have about 23,700 MWh of pumped storage in 4 schemes."
Chris, the late Prof Sir David MacKay listed our 4x pumped hydro schemes' total capaciity as 26.7GWh.
"There’s only one problem: we don’t have anything near the amount of <B><I>energy</i></b> storage needed..... Sure, there are pumped storage schemes like Dinorwyg in Wales and Nant de Drance in Switzerland which could theoretically store energy for weeks or even across seasons."
Electricity, rather than energy.
Dinorwig stores 9.1GWh and can discharge at 1.8GW
Nant de Drance stores 20GWh and can discharge at 0.9GW
For comparison, Britain has ~40,000 GWh of natural gas underground + LNG storage.
The recently re-opened Rough field now stores 9,350GWh (at a lower pressure than originally), and it alone can discharge at 63.25GW
One of my guiding principles is to check back to the source(s), especially in contentious areas like renewable power. There are too many vested interests on all sides keen to represent the picture they very much *want* to see.
When I checked the pumped hydro schemes listed by Prof MacKay I confirmed the power numbers as listed in his book's table 26.4:
Ffestiniog 0.36 GW = 360 MW
Cruachan 0.40 GW = 400 MW
Foyers 0.30 GW = 300 MW
Dinorwig 1.80 GW = 1,800 MW 1,728 MW is listed on some websites while the Wiki page appears to show 6 x 300 MW machines. Close enough for Government work, as they say.
I make that total 2,788 MW. (That seems to agree v roughly with Drax, see below.)
I have no idea where Exelon's numbers might come from. Or what make of calculator they may have used to do their additions, with how fat the fingers.
That would increase the power at that location to 1,000 MW (if they get approval).
But "The existing upper reservoir, which can hold 2.4 billion gallons of water, has the capacity to serve both power stations."
i.e. Cruachan + Cruachan 2 would still store 'only' about 7,000 MWh of energy.
Greater flexibility but same storage.
That same source says "Great Britain’s energy storage capacity will need to grow to around 30 gigawatts (GW) or more over the next 20 to 30 years, from 3 GW in 2020"
What are your thoughts on schemes such as the Norway link, where in theory during windy times the power goes to Norway and allows them to refill their hydro reservoirs. And then when it’s calm we buy their hydro power. It sounds like it is effectively wind storage. I think the current connection does 1.5GW. So assuming 50:50 storage vs usage that could be up to 6TWhr of storage?
I don't know the detail of the Norwegian hydro schemes, maybe some are pumped storage.
But even if they are all traditional dams with generators that can only generate, i.e. are not designed to reverse rotation to pump the water back up the hills.
When Norway receives power from the UK it can help Norway conserve its dammed water.
Or Norway can sell that power on to Europe, if the cost vs selling price is attractive.
I completely see and agree that interconnectors increase resilience in the power grid.
The problems are:
a) currently they have total *capacity* of a bit less than 10,000 MW but internally in GB I'm not sure the grid can take all that on top of normal loads;
b) the other end has to be willing and able to accept power through the interconnector - if they don't have load they cannot.
We've seen again just before Xmas how a big weather system can cover the whole of Northern Europe - we're all in surplus together, or all short of power together when that happpens.
I've yet to see anyone show that anyone's solved the hydrogen embrittlement problem. Hydrogen leaks out of steel pipelines and embrittles the steel in the process. Hydrogen also has a surprisingly low energy density, as well. It sounds great until you start digging into the entire lifecycle.
Oil refineries (hydrotreaters, reformers, hydrocrackers, pressure-swing absorption - PSA - units, etc.), steam methane reformers, ammonia plants and so on, have all been successfully (mostly) managing hydrogen embrittlement, high temperature hydrogen attack, hydrogen blistering, and so on, for decades. It takes specific metallurgy & possibly post-weld heat treatment + industry standards based on knowledge + hard experience + a competent static equipment inspection program to achieve it.
The thing that is not generally understood well enough is that our natural gas distribution system - not just the the high pressure pipelines but every single component in valves, instruments etc. - was not constructed to hydrogen standards. I attended an HSE Zoom call some months back where subject matter experts explained that the risks (of putting high-purity hydrogen through the existing gas network) could be managed adequately in the high pressure pipelines themselves. The risks in the multitiude of other components, not so much.
I'm beginning to believe that a lot of this net-zero stuff is simply political posturing. So that our dear leaders can stand up in front of the world's media and claim they've installed 100% renewables. The fact that, as you have shown, most of this 100% is never used is something that's easy to characterise as a trifling detail that needn't concern the voters.
How many AAs would we need for 16TWh?
Assuming a 1.5V AA battery discharging at 100mA can yield 2Ah we have a capacity of 3Wh per battery.
16TWh = 16 * 10^6 * 10^6Wh requires ~5 trillion AAs. That's a lot of silenced drumming bunnies.
This equates to 125 million tonnes (25 grams each) or 1250 aircraft carriers.
Not trivial for a small island and I hope my arithmetic is correct!
BTW I tend to agree about peer-review!
Hello Jim, thanks for your thoughts.
It's probably more useful to ask, how many Tesla "Megapacks" would be required for 16 TWh?
as these are marketed directly as utility-scale energy storage.
Each is 3 MWh according to the link: https://www.tesla.com/en_gb/megapack
For the moment I'll ignore limits on safe max charge and depth of discharge.
That's 16,000,000 MWh / 3 MWh = 5.3 million "Megapacks"
The biggest existing so far is the "Victoria Big Battery" with 212 units, according to the promo video.
So, just over 25,000 "Victoria Big Battery"s in *capacity* terms, but that wouldn't give the long duration required to bridge seasonal variations.
Hi Chris and thanks for the reply. I was being somewhat tongue-in-cheek!
It seems like Nature has already found a good enough way of storing energy - fuels. However our technocratic leaders seem to have become obsessed with electricity, presumably because it is ostensibly a 'clean' and 'renewable' form of power. The problem of actually making and storing it doesn't fit the mass psychosis.
Of course, someone may come up with a breakthrough next week which allows battery energy densities comparable to our petrol tanks.
Getting real data on constraints is difficult. You can get an approximation by looking at the wind forecast vs outturn reports - any big change downwards from a high forecast to a lower actual almost certainly represents curtailment, though it is hard to be precise about how much (and that must be a real problem anyway - you can't estimate what wasn't produced with certainty).
https://www.bmreports.com/bmrs/?q=foregeneration/dayaheadwindnsolar
A more nitty gritty approach is to look at output wind farm by wind farm, but that is painful in terms of accessing and downloading the data. However, it can be very revealing about what drives curtailments between one wind farm and another. There are various categories of wind farms contractually.
The simplest are those which are just paid market price for their output. These are wind farms that have no Renewables Obligation support, and either have yet to qualify for CFD support because they are not fully commissioned, or have not taken up their CFDs in the present strong market conditions that offer a much better return than their lowball CFD strike price (Triton Knoll, Moray East, Hornsea 2). These will have every incentive to curtail on the economics any time market prices are negative: they can simply buy back any forward sale of output at a negative price and bank the profit, rather than simply accepting the forward sale price at a lower margin. All they stand to lose are REGOs, although those have recently started to become of material value rather than being worth just a few pence per MWh.
Next are wind farms paid Renewables Obligations for every MWh they generate. In order to curtail they need to be compensated for the loss of any ROs they would earn. Different wind farms are entitled to different levels of ROs, so it will be the ones that are on the lowest RO band that are cheapest to curtail, and will be first in the pecking order where a constraint is operationally required because there is insufficient transmission capacity somewhere on the system (the constraint need not be in the immediate vicininty, but might be - more likely it will be the chokepoint of the Scotland-England transmission flows). Meanwhile the more expensive wind farms get to keep on producing. The market price tends to be set by the size of subsidies at risk (RO+REGO), and will be negative, and the curtailment payment will be of similar magnitude.
Wind farms on CFDs get paid their full strike price in compensation when market prices are negative, Their net proceeds are the strike price reduced by the negative market price, which will in most cases still leave them with a handsome income and thus no incentive to curtail. The first exception to this is that should day ahead intermittent market reference prices be negative for six or more contiguous hours no compensation is paid for the duration, and they have full market exposure to negative prices, and thus an incentive to curtail. Future rounds of CFDs will see the six hour minimum dropped, with any hour with negative prices offering no protection - potentially a big income hit compared with earning the strike price on more or less 100% capacity production on a windy day.
The other exception is when National Grid decides to persuade a CFD wind farm to curtail for operational or other reasons. It appears this has been happening with Beatrice quite regularly, despite the fact that it would be entitled to its full strike price - currently £175.47/MWh - if it carried on producing to offset any negative market price. I have yet to track down its compensation payments, but I plan to be asking questions as to why consumers have been paying out very large compensation when much cheaper compensation for RO generators on 1 or 2 ROCs/MWh ought to be available. The Beatrice accounts suggest the compensation has been more than generous. Perhaps they are being asked to free capacity so that National Grid can reduce its liabilities for failure to connect other wind farms at all.
You know far more than me in this area... is there *anyone* in the relevant Gov Departments even remotely interested in entering contractual arrangements that *don't* end up with tax- and bill-payers being royally screwed?
"Hydrogen for Energy Storage?
Is it possible to produce truly ‘green’ hydrogen and store it securely?"
So what would we do with that hydrogen taken from storage in our 'all-electric' paradise?
Those who blithely respond "generate electricity with it" would be unaware of reality regarding our existing CCGT & OCGT plants.
Section 3.7.1.9 Gas turbines on page 32 of HSE's "Injecting hydrogen into the gas network – a literature search" informs:
"A particular concern regarding ignition is the presence of hydrogen; since this gas ignites easily, there is concern that even small quantities of hydrogen in natural gas would be catastrophic for turbine behaviour. To illustrate this apprehension one major turbine manufacturer allows only traces of hydrogen in the fuel gas, while another manufacturer allows only 8.5% of hydrogen"
Hello Ron,
I think "Is it possible to produce truly ‘green’ hydrogen and store it securely?" will be the 64 billion dollar (or maybe 64 trillion dollar) question.
BEIS seems set on the idea that ultimately we'll have to convert (surplus) renewable power into chemical energy in order to be able to store that energy across weeks / seasons.
Quite how you take huge spikes of surplus power randomly followed by huge shortages, to feed electrolysers that need constant power, I really don't know.
How you transport and store H2 safely in the immense quantities needed - salt domes being the only credible containment at sufficient scale but also only being possible in limited areas of salt geology - equally I don't know.
Gas turbine developments allowing operation on up to 100% hydrogen? In the works, apparently. They are certainly not going to be the GTs we are using today. Whether it's worth it because of the conversion inefficiencies? Whether industrial-scale fuel cell electrical generation would be better?
As the Hydrogen Science Coalition and others keep saying, if the aim is decarbonisation, 'green' hydrogen should first be reserved for the ammonia we need to keep feeding people, displacing grey hydrogen.
Whether next would be synthesis of methanol for fuel across seasons? - absolutely massive industry needed, more conversion inefficiencies, but at least methanol's a liquid at room conditions, so it's much easier to store.
Huge, huge problems to which I don't see any solid answers as yet.
"Some context to those numbers: Dinorwyg stores up to 9,200 MWh and took over a decade to build. In total across the UK we have about 23,700 MWh of pumped storage in 4 schemes."
Chris, the late Prof Sir David MacKay listed our 4x pumped hydro schemes' total capaciity as 26.7GWh.
https://www.withouthotair.com/c26/page_191.shtml
The Coire Glas project - 1.5GW / 30GWh - is due for completion due late 2029 / early 2030
https://www.inverness-courier.co.uk/news/coire-glas-pumped-hydro-scheme-gets-approval-from-scottish-government-215721/
Hi Ron,
Re: the existing schemes' combined capacity, I covered that in my 2nd post: https://chrisbond.substack.com/p/part-2-of-uk-plc-power-decarbonisation#:~:text=Of%20the%20four,the%20red%20text.
Coire Glas, ok thank you, future capacity.
"There’s only one problem: we don’t have anything near the amount of <B><I>energy</i></b> storage needed..... Sure, there are pumped storage schemes like Dinorwyg in Wales and Nant de Drance in Switzerland which could theoretically store energy for weeks or even across seasons."
Electricity, rather than energy.
Dinorwig stores 9.1GWh and can discharge at 1.8GW
Nant de Drance stores 20GWh and can discharge at 0.9GW
For comparison, Britain has ~40,000 GWh of natural gas underground + LNG storage.
The recently re-opened Rough field now stores 9,350GWh (at a lower pressure than originally), and it alone can discharge at 63.25GW
https://mip-prd-web.azurewebsites.net/DailySummaryReport
Yes, 'renewable' electrical energy generated mainly by windmills cannot currently be stored directly at the scale needed.
As you say, chemical energy in the demon forms of fossil oil, gas and (whisper it) coal, can be stored.
Hi Chris
Regarding Britain's PH discharge capacities, have you looked at Elexon's "Installed Generation Capacity Aggregated (B1410)" page recently?
https://www.bmreports.com/bmrs/?q=foregeneration/capacityaggregated
If you select '2023' & view it, "Hydro Pumped Storage" discharge capacity is shown as 5063MW (!!)
Selecting '2022' & view it, "Hydro Pumped Storage" discharge capacity is shown as 1928MW
I took a screen capture 2nd January 2022 for 2022's figures, and "Hydro Pumped Storage" discharge capacity was at that date shown as 4190MW
Selecting '2021' & view it, "Hydro Pumped Storage" discharge capacity is shown as 4309MW.
I've flagged it with them, and am awaiting their response.
Hello Ron,
One of my guiding principles is to check back to the source(s), especially in contentious areas like renewable power. There are too many vested interests on all sides keen to represent the picture they very much *want* to see.
When I checked the pumped hydro schemes listed by Prof MacKay I confirmed the power numbers as listed in his book's table 26.4:
Ffestiniog 0.36 GW = 360 MW
Cruachan 0.40 GW = 400 MW
Foyers 0.30 GW = 300 MW
Dinorwig 1.80 GW = 1,800 MW 1,728 MW is listed on some websites while the Wiki page appears to show 6 x 300 MW machines. Close enough for Government work, as they say.
I make that total 2,788 MW. (That seems to agree v roughly with Drax, see below.)
I have no idea where Exelon's numbers might come from. Or what make of calculator they may have used to do their additions, with how fat the fingers.
Also of interest, I looked at Cruachan 2, e.g. https://www.drax.com/about-us/our-projects/cruachan-2/
That would increase the power at that location to 1,000 MW (if they get approval).
But "The existing upper reservoir, which can hold 2.4 billion gallons of water, has the capacity to serve both power stations."
i.e. Cruachan + Cruachan 2 would still store 'only' about 7,000 MWh of energy.
Greater flexibility but same storage.
That same source says "Great Britain’s energy storage capacity will need to grow to around 30 gigawatts (GW) or more over the next 20 to 30 years, from 3 GW in 2020"
Mixing up energy and power yet again.
Hi Chris
"Mixing up energy and power yet again."
Drax/Crauchan adverts appear on twitter, and they (of all people) are getting rightly ridiculed for their error.
What are your thoughts on schemes such as the Norway link, where in theory during windy times the power goes to Norway and allows them to refill their hydro reservoirs. And then when it’s calm we buy their hydro power. It sounds like it is effectively wind storage. I think the current connection does 1.5GW. So assuming 50:50 storage vs usage that could be up to 6TWhr of storage?
Hello Alastair, thank you.
National Grid ESO has published an interconnectors register which includes
NATIONAL GRID NORTH SEA LINK LIMITED NS Link 1,400 MW import 1,480 MW export
see https://www.nationalgrid.com/national-grid-ventures/interconnectors-connecting-cleaner-future/north-sea-link
I don't know the detail of the Norwegian hydro schemes, maybe some are pumped storage.
But even if they are all traditional dams with generators that can only generate, i.e. are not designed to reverse rotation to pump the water back up the hills.
When Norway receives power from the UK it can help Norway conserve its dammed water.
Or Norway can sell that power on to Europe, if the cost vs selling price is attractive.
I completely see and agree that interconnectors increase resilience in the power grid.
The problems are:
a) currently they have total *capacity* of a bit less than 10,000 MW but internally in GB I'm not sure the grid can take all that on top of normal loads;
b) the other end has to be willing and able to accept power through the interconnector - if they don't have load they cannot.
We've seen again just before Xmas how a big weather system can cover the whole of Northern Europe - we're all in surplus together, or all short of power together when that happpens.
I've yet to see anyone show that anyone's solved the hydrogen embrittlement problem. Hydrogen leaks out of steel pipelines and embrittles the steel in the process. Hydrogen also has a surprisingly low energy density, as well. It sounds great until you start digging into the entire lifecycle.
Hello Eric,
Oil refineries (hydrotreaters, reformers, hydrocrackers, pressure-swing absorption - PSA - units, etc.), steam methane reformers, ammonia plants and so on, have all been successfully (mostly) managing hydrogen embrittlement, high temperature hydrogen attack, hydrogen blistering, and so on, for decades. It takes specific metallurgy & possibly post-weld heat treatment + industry standards based on knowledge + hard experience + a competent static equipment inspection program to achieve it.
The thing that is not generally understood well enough is that our natural gas distribution system - not just the the high pressure pipelines but every single component in valves, instruments etc. - was not constructed to hydrogen standards. I attended an HSE Zoom call some months back where subject matter experts explained that the risks (of putting high-purity hydrogen through the existing gas network) could be managed adequately in the high pressure pipelines themselves. The risks in the multitiude of other components, not so much.