The problem of replacing our dependence on fossil fuels is complex. In Thinking Critically About Sustainable Energy (TCASE) #12, a checklist was provided to allow assessment of energy transition plans. The sort of questions listed in TCASE 12 are critical for evaluating the feasibility of future scenarios, like the ones from the recent IPCC report on renewable energy.
However, we also need to assess the capabilities of individual technologies to mitigate CO2 emissions, effectively (and economically). The following is a list of criteria that can be used to determine the relative viability of various alternative technologies. This comes from the work I had published recently in the peer-reviewed journal Energy (with colleagues Martin Nicholson and Tom Biegler):
Proven: Has the technology been used at commercial scale?
Scalable: Can the technology be built in sufficient quantity to replace significant proportions of existing fossil-fuel generators?
Dispatchable: Can the output be allocated by the system operator to meet the anticipated load?
Fuel supply: Is the energy source reliable and plentiful, even when, as with some kinds of renewable energy, it varies with time?
Load access: Can the generator be installed close to a load centre?
Storage: Does the technology require electricity storage in order to deliver a high capacity factor?
Emission intensity: Is the emission intensity high, moderate or low (as defined in the table below)?
Capacity factor: Is the capacity factor high, moderate or low (as defined below)?
For a technology to be considered fit-for-service (FFS) as a baseload generator (i.e., a direct replacement for coal or combined-cycle gas power plants) it needs to be scalable, dispatchable without large storage and have a reliable fuel supply, low (L) or moderate (M) emissions intensity and a high capacity factor as defined in the table above. Load access is considered to be desirable for transmission cost reasons but is not essential to meeting baseload demand.
The technologies that score well enough to meet the FFS criteria are pulverised fuel black coal with carbon capture and storage (PF Coal/CCS), integrated gasification combined cycle coal with CCS (IGCC/CCS), combined cycle gas turbine with CCS (CCGT/CCS), nuclear power, and solar thermal with thermal storage and/or hybrid gas (STE).
Engineered geothermal systems (EGS or hot dry rocks: HDR) could also qualify, but is only at the pilot plant stage of development and furthermore there are inadequate reliable cost data for it. At present, the use of large-scale electricity storage is prohibitively expensive in most networks. There are significant economic issues in deploying storage, stemming from the high capital costs and complexity of operating in liberalized energy markets.
In our Energy paper (cited above), we did a meta-review of of 14 authoritative peer-reviewed studies, published during the last 10 years, of electricity generating technologies (for those that met the FFS criteria, as listed in the table above) to determine their life-cycle greenhouse gas emissions (expressed in units of kg CO2eq/MWh). The results are tabulated below (references in footnote).
The results of this survey represent the scientific/engineering/economic consensus of the world-wide, authoritative, peer reviewed energy literature. As such, you should bear these criteria and life-cycle analysis (LCA) figures in mind when discussing various alternative energy technologies. For a related discussion about cost, see here.
Footnote – references for LCA table:
Audus H, Freund P. Climate change mitigation by biomass gasification combined with CO2 capture and storage. UK: IEA Greenhouse Gas R&D Programme; 2005.
ExternE-Pol. Externalities of energy: extension of accounting framework and policy applications: new energy technologies. Final Report on Work Package 6, European Commission, http://www.externe.info/expolwp6.pdf; 2005.
Gagnon Luc, et al. Life-cycle assessment of electricity generation options: the status of research in year 2001. Energy Policy 2002; 30:1267e78.
IPCC. Carbon capture and storage, http://www.ipcc.ch/pdf/special-reports/srccs/srccs_wholereport.pdf; 2006.
ISA University of Sydney. Life-cycle energy balance and greenhouse gas emissions of nuclear energy in Australia, http://www.isa.org.usyd.edu.au/publications/documents/ISA_Nuclear_Report.pdf; 2006.
Lechón Yolanda, et al. Life cycle environmental impacts of electricity production by solar thermal technology in Spain. SolarPACES; 2006.
Meier Paul. Life-cycle assessment of electricity generation systems and applications for climate change policy. University of Wisconsin; 2002.
MIT. The future of coal – options for a carbon constrained world, http://www.ipcc.ch/pdf/special-reports/srccs/srccs_wholereport.pdf; 2007.
NEEDS. Technology assessment under stakeholder perspectives. Stefan Hirschberg. Feb 2009. http://www.needs-project.org/2009/16-02-2009/Hirschberg.ppt.
NREL. Biomass power and conventional fossil systems with and without CO2 sequestration, http://www.nrel.gov/docs/fy04osti/32575.pdf; 2004.
Succar Samir, Greenblatt Jeffery B, Williams Robert H. Comparing coal IGCC with CCS and wind-CAES baseload power options, http://www.princeton.edu/ssuccar/recent/Succar_NETLPaper_May06.pdf; 2006.
Tokimatsu Koji, et al. Evaluation of lifecycle CO2 emissions from the Japanese electric power sector in the 21st century under various nuclear scenarios. Energy Policy 2006; 34:833e52.
Weisser D. A guide to life-cycle greenhouse gas (GHG) emissions from electric supply technologies. Energy 2007; 32(9):1543e59.
World Energy Council. Comparison of energy systems using life cycle assessment, http://www.worldenergy.org/documents/lca2.pdf; 2004.
86 replies on “TCASE 13: Assessment of suitability of technologies for carbon dioxide mitigation”
Thanks, Barry. This is a significant resource.
Add land and materials requirements. Very important, not just for economics but also for environmental footprint.
Here’s an article from The Oil Drum that shows for example, that there’s not enough lead in the world to store a week’s supply of electricity for an electrified US economy. And that’s just for the USA. 16 *TONNES* of lead required per person in the US for 1 week of lead acid battery storage. We’re not going to do that folks, and even if we try it will be a massive economic and environmental insult.
Be sure to check out, “thinking about energy densities”
And, “materials required to build renewables”:
And let’s not forget how dangerous an energy technology is, per unit of electricity or other useful energy generated.
Just a quick question. The table on baseload technology assessment, I tried to find in your refs the info you used on assessing wave and tidal but could only find the IPCC 2007 assessment doc which wasn’t conclusive. If you have time could you point me to the info you used for wave and tidal.
Barry,you have included several fossil fuel technologies with CCS as FFS.As CCS is not,and never will be,scalable to the extent necessary to significantly reduce carbon emissions,what is your rationale for this?
On your emission intensity criteria,no fossil fuel generation will ever be fit for service
As lead author on the paper referenced by Barry and the major researcher, it’s probably best that I answer some of these questions on the selected technologies for fit-for-service as baseload generators. First just to repeat the criteria:
“For a technology to be considered fit-for-service (FFS) as a baseload generator (i.e., a direct replacement for coal or combined-cycle gas power plants) it needs to be scalable, dispatchable without large storage and have a reliable fuel supply, low (L) or moderate (M) emissions intensity and a high capacity factor.”
@ Jeremy C
We used a number of sources to assess the selection criteria. As wave and tidal are not widely used, the sources were limited for reliable data. We elected to use the paper from IEA titled Projected costs of generating electricity. 2010. It can be found here:
The capacity factors for wave in the IEA document were between 35% and 56% and for tidal 30%. These are consistent with assessments elsewhere. This means that both wave and tidal power did not meet our FFS criteria of a high capacity factor (>70%) so were excluded from the study.
I suppose that the scalability of CCS is a matter of conjecture. Clearly the IEA does consider it scalable as it is expected to play an important role in reducing power-sector emissions by 2035 (IEA World Energy Outlook 2010).
In our paper we set moderate emission intensity at <300 kg CO2eq/MWh. All the CCS studies we analysed met this criteria.
Martin Nicholson, on 13 August 2011 at 11:08 AM — Clarifying. Thank you.
However, we also need to assess the capabilities of individual technologies to mitigate CO2 emissions, effectively (and economically).
Are you saying that only base-load generation can mitigate CO2 emissions? and therefor PV can never mitigate CO2 emissions(ie not significantly reduce CO2 emissions) whatever the cost?
Are you saying that hydro cannot mitigate CO2 emissions because it usually requires storage of water in dams or lakes?
Are you saying geothermal can not reduce CO2 emissions(not eliminate all emissions just significantly reduce )?
At present, the use of large-scale electricity storage is prohibitively expensive in most networks. There are significant economic issues in deploying storage, stemming from the high capital costs and complexity of operating in liberalized energy markets.
The UK article doesnt say pumped hydro is prohibitively expensive, but that OCGT back-up is a lower cost solution at present but with more renewable and additional INFLEXIBLE NUCLEAR in the future this will be challenging (in the UK because of limited sites).
Thanks for the reply, I haven’t access to the IEA book but will seek to track down a copy as I would’ve assessed wave and tidal differently under Fuel Supply and Capacity Factor but as you say sources are a bit limited and we will just have to wait a few years for more data to emerge from projects in the water. Though I notice MCT are ‘claiming’ a capacity factor of over 60% for their Sea Gen tidal turbine. How accurate that is……..
Neil Howes, on 13 August 2011 at 8:50 PM — It might be clearer, but solar PV only does something to shave off the daytime peak, under almost all scenarios. That portion is 25–50% of baseload, dpending upon season and locality. Of course, solar PV generation doesn’t quite match the daytime load curve, so I’ll be conservative and say that half might be met in sunny climes.
Hydro is most places is legacy hydro, already in place. New hydro facilities are being constructed in southeast and east Asia, but none elsewhere that I know of.
Geothermal is a boutique solution which has a very small place at the table.
Pumped hydro,even if suitable sites can be found, has become quite expensive in developed countries.
Modern NPPs are fairly nimble. For example, the Areva EPR is capable of cycling from 60% to 100% power isothermally and fast enough to do load following.
The analysis is very helpful.
A question. The analysis appears to cover only the generation of power, rather than its consumption. Regarding power sources that are inconsistent and undependable with respect to time and location, however, there is much history which shows this being done.
We need to eat, preferably three square meals a day, but in major food production areas, most of the food can be (and is) produced over only a portion of the year.
Classic passenger and freight transportation by ocean has relied on wind power up until not much over a century ago. But people and freight have traveled by sea for ages. The greatest advances were made possible by progress in navigation technology
When I was a kid just learning to read, I saw many patriotic posters asking: IS THIS TRIP NECESSARY? Transportation is a major consumer of energy, particularly of the fossil kind, these days. My wife just bought some Chilean merlot for tonight’s dinner: it is excellent and cheap. And we enjoy, quite inexpensively, fresh fruits and vegetables out of season, not to mention flowers on the tables. The granddaughter of some folks we know had a fancy wedding on an island in Thailand. (None of the wedding party nor of the guests are Thai; almost all are from the Chicago area.)
I really suspect that, without considering such nonlinearities, the problems are insoluble if we cannot avoid trend being destiny.
Once again: the analysis is very helpful.
Martin Nicholson on 13 August at 11:08 AM
“I suppose that the scalability is a matter of conjecture” re CCS.
A rather cavalier dismissal of this issue.It reminds me of Barry Brook’s attitude to the growth problem as evidenced in the previous thread.
So you think that covering the country in a spider web of compressors, pumps and thousands of kilometres of pipeline delivering carbon dioxide to inadequate underground storages of doubtful intregrity is simply a matter of conjecture?
This is about on a par with the renewables enthusiasts’ view that a base load electricity generating system can be built by covering the countryside in windmills,solar collectors,Heath Robinson energy storage contraptions and thousands of kilometres of high voltage powerlines with associated pylons.
As for the IEA,they are hardly a credible source.
I quote from the NGO Global Witness – ” The agency’s overconfidence despite credible data,external analysis and underlying fundamentals all strongly suggesting a more precautionary approach,has had a disastrous global impact “.
This was a reference to the IEA prediction of future oil production.But it would equally apply to their views on CCS given the culture of the organization and its origins.There are 28 member nations of the IEA,all of the OECD in fact ,and you would not find anywhere else such a collection of Business As Usual Believers as these countries under their present governments.
On 27/07/2011,economist and author Michael Hudson said in an essay – ” Whenever one finds government officials and the media repeating an economic error as an incessant mantra there always is a special interest at work “.
Now,economics is a wide field,and it would certainly cover the fossil fuel technologies you have come out in favor of.I put it to you that the special interest, which Hudson speaks of,in this case, in Australia, is the fossil fuel industry and its political supporters.
(deleted personal opinion on a person’s motives as per BNC Comments Policy.)
Please supply refs to back-up your opinion on scientific/engineering aspects.
Podargus, on 14 August 2011 at 6:48 AM — Unreasonable.
First, there are currently at least two underground pipelines delivering CO2 ovr long distances and neither causes any difficulties. Certainly that established technology scales.
Inadequate underground storage? I think not, but in any case that is simply conjecture on your part,; no citation. What is known is that CO2 has a certain small chemical affinity for some forms of rock; in the case of coal 2–3 molecules of CO2 replace every molecule of CH4. So long as the reservoir is not overstuffed the deep saline reservoirs should prove quite adequate.
Even better would be heavy pumping into mafic rock which will more adequately bind the CO2 as carbonate.
Whether any of the abov e is economic remains to be demonstrated; the estimated costs from IEA appear to be quite high.
I wonder if some seemingly unessential travel is good for society’s mental health. Rioters in the news lately say they feel trapped in the one place. Same goes for parks, air conditioning, backyards and biodiversity which may seem wasteful but their absence causes problems. On the other hand the ZCA crowd have decided that hair shirt energy abstinence is good for our collective wellbeing. Presumably an allowed form of unessential travel might be a train trip to the next town. Tropical island dwellers don’t get to go skiing in the alps nor vice versa. We’ll spend our lives close to where were born.
Therefore I think we should plan for a moderate world population using a moderate amount of energy. It seems we are being railroaded into a larger population using progressively less energy. I suggest riots are an early warning sign of how that formula will work out.
David B Benson – Gee, a whole 2 pipelines!
Do you have the faintest clue as to how many (deleted expletive) pipelines would have to laid to your miraculous storages to make even a significant dent in carbon emissions ?
Why bother with this cornucopian airy fairy garbage when we already have a developed and developing technology which has zero emissions and a minimal waste storage problem which will diminish even further with the ongoing application of developed and developing technology.
(Snide remark deleted)The name of that technology is,wait for it —– nuclear.Heavens,who would have guessed ?
(Deleted personal opinion of other’s motives)
Please refrain from excessive language, pejoratives or speculation of other’s motives. This type of exchange does nothing to further communication and whips up angst and inflammatory comments.
David Benson it has been estimated that 4 million cubic kilometres of coal every year generates CO2 that would require 10.9 cubic kilometres of underground storage space at 0C, 200 bar compression. See just before the conclusion section in
If correct the waste from fossil fuel burning takes up a bigger space than the original fuel. We would soon run into Peak Cavities.
Another sign that energy rationing is coming ready or not
Podargus, on 14 August 2011 at 7:59 AM — I do indeed understand how many pipelines would be required and I do now have further evidence of your unreasonableness.
Just becuase somthing is technically possible, and safely so, does not make it economic. I already point that out.
I want a least-risk solution to the excess CO2 problem and I’m not ready to drop any potential alternatives just yet.
(Comment deleted – this reply to Podargus is no longer necessary as the comments refered to have already been edited.)
But to avoid further (pointless) exchanges, I doubt that CCS can ever be more than a boutique solution, only applicable under especial circumstances; that does not mean it should be banned. I’m perfectly willing to have further study or operational experience demonstrate I’m worng, either way, on this minor matter. So, I believe, are Barry Brook and Martin Nicholson; rationality, not emotions, is the order of the day.
Unfortunately, just now NPPs appear rather expensive (outside of China). Worse, there appears to be a considerable number with irrational fear of matters nuclear. I suggest that a fine way to encourage the nuclear option is to aid in removing those fears. (Comment deleted – see above)
John Newlands, on 14 August 2011 at 8:16 AM — I doubt that. Check out the amount of available mafic rock both on land and under the oceans.
However, do recall I stated it might be rather expen$ive.
David B. Benson, on 14 August 2011 at 2:53 AM said:
It might be clearer, but solar PV only does something to shave off the daytime peak, under almost all scenarios. That portion is 25–50% of baseload, dpending upon season and locality
My point was that if PV can contribute 25-50%. of baseload thats MITIGATION of CO2.
Hydro is most places is legacy hydro, already in place. New hydro facilities are being constructed in southeast and east Asia, but none elsewhere that I know of.
According to the IPCC report on renewable energy about 25% of hydro potential has been developed. Growth over last 20 years has been about 2.5%per year( higher than nuclear). I would not accept the argument that ” nuclear in most places is legacy nuclear, new most new facilities are being constructed in southeast and east Asia”
All: I went through the CCS stuff soemtime ago and probably earlier included most, if not all, of my references at one time or another on Brave New Climate. But for those who wish to check for themselves, here are some places start.
In situ peridotite weathering:
In situ basalt weathering:
Ex situ olivine weathering:
Click to access c03016.pdf
See references 7, 8 and 9 in
My conclusion was that all this was too expensive to bother with exploring further; others may differ.
However, my other conclusion was that, other than expensise, CCS is feasible and can be done safely.
Neil Howes, on 14 August 2011 at 8:33 AM — Baseload means that portion of the load which continues both daytime and nighttime. Obviously solar PV cannot contribute to that. SOlar PV can be used to shave off a portion of the extra load whch occurs in the daytime. SInce the potential power which could be produced by solar PV does not precisely match this extra load, solar PV might be capable of contributing to about half of that extra power requirement during sunny days. Measured as a percentage of the baseload, that’s around 10–20%, but6 not part of the baseload itself but rather the extra required during daytime.
There are many places in the world with further hydro potential if the populations there are willing to accept the environmental changes that dams, even just so-called run-of-the-river turbines, cause. In large part none of these sites are to be found in developed countries. In developed countries the best sites are already dammed, hence the term legacy hydro.
Big dams leave a big environmental footprint. We have our own problems here in the Pacific Northwest with dams and don’t want anymore. For elsewhere, consider the difficulties caused by the Egyptian Aswan High Dam and the Kariba dam on the Zabezi River:
WHiel the IPCC statement might be strictly true, it does not follow that rivers and streams should be so molested. Think ecosystem services.
@ Neil Howes, on 13 August 2011 at 9:18 PM
“The UK article doesn’t say pumped hydro is prohibitively expensive, but that OCGT back-up is a lower cost solution at present.”
The UK article does say in Box 3:
“Pumped hydro has found it difficult to compete for contracts in the current liberalised energy market against smaller, less expensive OCGTs due to their high capital and maintenance costs.”
I suspect that statement would tend to imply that pumped hydro was prohibitively expensive relative to OCGT. Of course as the price on carbon rises and OCGT used as back-up for variable energy sources generates significant GHG emissions, then it may not be so relatively prohibitively expensive in the future.
It is certainly true that the authors of the UK paper did say that the new nuclear plants would provide “an inflexible output of energy”. Perhaps this is just a function of the particular plants on order. As I understand it, nuclear plants do not have to be inflexible and many are used for load following with significant ramp rates both up and down. A matter I am sure has been discussed on this blog site many times before.
“We are pleased to announce the release of our draft full commission report for public comment. This draft report represents the work and recommendations of the Blue Ribbon Commission on America’s Nuclear Future (BRC) to date.” from
I’ve read the summary, the introduction and chapter 10 beginning on page 112.
While particular to (unfortunate) situation in the USA, everybody planning a nuclear future ought to read this for the issues surrounding the eventual disposal of the residual wastes. Of particualr interst to me were the presentations of nuclear waster volume and radoactive hazard of wastes generated by fast reactors, found in chapter 10.
It’s conceivable that in future the carbon price could be low but the raw gas price could be high. That seems to motivate WA’s decision to mandate a 15% local set-aside for gas
I’m not sure how that will apply to the big floating platform that will have no pipeline to shore.
When gas becomes prohibitively expensive some other way will have to be found to integrate intermittent energy sources. That is why the 20% renewables target is short sighted because it locks in gas backup. As Garnaut says the carbon price is all that should be needed. If 20% is too high we may have more wind and solar installations than we can integrate when gas is gone or unaffordable. It may be cheaper to store excess coal power and pay a modest carbon tax.
A taste of very high gas prices may be the Japanese now paying $1,000 spot price per tonne of LNG with heating value of ~55 GJ or $18/GJ. No carbon tax involved. I believe Victorian piped gas (with a decade or so remaining) is now around $7/GJ. We may end up with some ‘stranded’ wind while it is still connected to the grid because it’s too expensive to integrate via gas.
John Newlands, on 14 August 2011 at 10:42 AM
If 20% is too high we may have more wind and solar installations than we can integrate when gas is gone or unaffordable. It may be cheaper to store excess coal power and pay a modest carbon tax.
Its hard to see a problem integrating a mix of solar, wind biofuels and hydro accounting for 20% of energy use. What would be providing the other 80% if no NG was available? Either coal or nuclear have some flexibility. On the NEM grid extreme demand where prices are the maximum $10,000/MWh occurs < 1% of the time, but accounts for most of the profits of peaking plants. That would allow a very small amount of very expensive NG( or bio-gas) to provide for extreme peak demand.
Mafic rock consists of volcanic flows of zero porosity. You just can’t pump CO2 into it at reasonable pressures. Although it might be possible to find some crushed or thin-layered forms near surface, its reaction with billions of tons of gaseous waste will create billions of tons of liquid/solid pollutant. Not welcome in the near surface.
Do there exist suitable formations? Each of the layers one might see on a seismic section represent an ancient environment. Those layers with porosity are in equilibrium with their pore fluids, that is, until humans interfere with the balance. Addition of liquid CO2 to the saline forms a corrosive acid that is guaranteed to attack the matrix, regardless of what it is (eg) . Any representation of CCS as a means of avoiding polluting one environment glosses over the fact that it will certainly destroy another environment somewhere else.
Can CO2 be sequestered forever? As the crumbling reservoir settles more in some places than others, the roof above it cracks, allowing the liquids to mix upwards. Although the reservoir may have been sealed when selected, the overpressure of pumping and subsequent collapses makes the survival of the seal doubtful. In the absence of a seal <a href="(eg, “>liquids normally circulate through the layers, evaporating at the surface and being replenished from rain or sea. Hey presto, CO2 returns to the greenhouse. As far as safety goes, eventual escape into the environment can be eruptive, threatening livestock and humans.
While today’s planners do not have to pay for tomorrow’s disasters, consideration of the above would not come in to deciding whether the CCS process is economic. Ethical considerations seem to be another matter.
RC I’ve seen empirical evidence to back what you say. Some olivine in mafic rocks is weathered to the carbonate magnesite which is not that soluble, therefore a carbon sink. However acid rainwater may then release the CO2 to form the carbon free hydroxide brucite, not that dissimilar to antacid tablets.
@ Neil Howes, 14 August 2011 at 8:33 AM:
If Neil is seriously suggesting that new hydro, including additional pumped storage is appropriate in the Australian context, it is up to him to support this by nominating a few studies, or at least to nominate some proposed locations for these new dams, pumping stations and transmission lines. The only location where I could conceive that there would not be immediate and sustained public uproar would perhaps be pumped salt water storage using the height of the Nullarbor cliffs, but previous discussions on this site on this topic essentially came to a dead end regarding cost/benefit issues.
I’d love to see trials done closer to civilisation and research centres, eg Manly, but there is no enthusiasm for this from other sources, so I don’t expect to see any action within at least a decade. Perhaps Eraring Energy will proceed to full commercial implementation of pumped storage with the additional benefit of provision of attemperating water during peak summer operation as well as time shifting load for several hours’ operation at a couple of hundred MW. The documentation for this proposal is not, as far as I know, public. I am not familiar with engineering details.
Until Neil comes up with either a reference to studies or nominates candidate locations, his contribution on this subject remains unfounded and should be ignored.
@ John Bennetts:
Ye gods! Now you’ve done it. There’s nothing more fun for Neil Howes than posting endless variations of proposals for extravegant hydro dam uprates, pumped storage systems, and associated wind farm developments in the Australian context. Hope you like that sort of thing, John. You have (ahem) “sown the wind”.
John Bennetts, on 14 August 2011 at 3:37 PM
I wasnt suggesting any new hydro just using existing dams more efficiently. Peter Lang did a good study of a 9GW pumped hydro using existing Blowering and Tantangara storages.
Another alternative is to uprate hydro generators in TAS from 2.2GW now operating at CF0.5 to 5GW operating at CF0.25.
In any case NEM already has about 7GW hydro capacity, including 1.2GW (pumping) of pumped hydro. The Blowering/Tantangara proposal would increasing pumping capacity from 1.2 to 8GW and total pumped storage from 20GWh to 500GWh. Existing hydro already had a storage capacity of 24,000GWh when dams are full, more than enough to correct seasonal variations in wind and solar, and to back up periods of low wind and high cloud cover.
Whatever provides most of the energy, there will still be value in having considerable gas fired peak capacity for those rare periods of exceptional demand. We are not going to over-build nuclear(or renewables) to operate 30-40 hrs during periods of exceptional demand.
Too late, Neil.
The Tantangara Transfer has grabbed some of the water that you want to use for Canberra’s gardens. Construction is under way. Completion next year.
And your next project is…?
How easy is each technology to audit? This criterion is absent from the list in the article. Since any mitigation technology could be claimed by emitters as a “carbon credit”, its acceptability stands to represent many millions of dollars.
Currently we hear people speaking about “carbon credits” as though they can only be found in developing countries. However, it may simply be that if a dodgy technology is used in a developed country, calculations based on its effectiveness could be exposed as fraud by a vigilant auditor. If that is true, we are more likely to hear of these mitigation technologies running at high effectiveness in developing countries, but nowhere else.
Even if a mitigation technology actually is effective, then it should be installed promptly in the vicinity of the emissions, leaving no justification for emplacement remote from local auditors. If we consider emission of carbon waste as a crime against the environment, then the purchase of foreign carbon credits amounts to a criminal in this country paying a criminal in another country not to do what neither of them have should have been doing in the first place.
John Bennetts, on 14 August 2011 at 5:51 PM
Too late, Neil.
The Tantangara Transfer has grabbed some of the water that you want to use for Canberra’s gardens.
Pumped hydro doesnt consume water just shifts it back and forwards between reservoirs.
Martin Nicholson, on 14 August 2011 at 10:05 AM said:
It is certainly true that the authors of the UK paper did say that the new nuclear plants would provide “an inflexible output of energy”. Perhaps this is just a function of the particular plants on order
Variable costs for nuclear are about 10% of total cost. So if power from a nuclear plant costs 10 cents/KWh, it costs 9 cents/KWh for every KWh not used. That 9 cents gets tacked onto the price of KWh’s actually used. Finances make nuclear inflexible.
Roger Clifton, on 14 August 2011 at 2:16 PM — Please go back to my (easily overlooked, I fear) comment:
David B. Benson, on 14 August 2011 at 8:39 AM
to discover that indeed, mafic rock, ultramafic preferred, is quite suitable for permanent CO2 removel via carbonization.
As for deep saline formations, I already pointed out that a minor chemical affinity for CO2 to be semi-bound to the rock; it is most unlikely to escape no matter what. Of course, one needs two wells; the first pumps in the CO2, the other pumps out the displaced saline solution. That waste needs to have whatever methane in contains refined out for beneficial use and the remainder disposed deep in the ocean.
Looks expen$ive to me, but I see no future hazards, especially for the mafic rock method. Of course both techniques requite some form of pilot study and so far none is being conducted for the specific purpose of CO2 removal. However, in west Texas and in the Slapnir[sic?] oil fields, CO2 injection for the purpose of enhanced oil recover has been done for some time. In neither location is there any indication (so far) of CO2 leakage to the surface.
Neil Howes @ 14 August 2011 at 4:21 PM,
Pumped hydro schemes like those already existing in the NEM and the proposed Tantangara-Blowering scheme
https://bravenewclimate.com/2010/04/05/pumped-hydro-system-cost/ are not suitable for energy storage for renewable energy see: https://bravenewclimate.com/2010/04/05/pumped-hydro-system-cost/#comment-133008
Harry, the reference to ‘inflexible” in the UK paper was to NPP ability to load follow and had nothing to do with finances. Full quote:
“The government has also recently given approval for new nuclear reactors, which provide an inflexible output of energy due to the
complexities of shutting down generation. Balancing supply and demand in a network containing large quantities of both inflexible base-load nuclear power and variable wind power would be extremely challenging.”
I would encourage people to follow the link, provided in the last sentence of the lead post, or repeated here:
This post deals with the economics of low-carbon baseload power. See especially the second figure, which shows the effect of carbon prices on the cost of power from different sources.
The figure, in combination with Australia’s proposed carbon price of $20+, bodes well for the eventual widespread adoption of nuclear power in Australia.
Martin Nicholson, on 15 August 2011 at 8:27 AM — I take that quote as failing to understand the difference between load-following and cold stop shut down. Every PWR and BWR is capable of a certain amount of load-following. The US Navy’s shipboard reactors load follow frquently; the civilian counterparts in the US much less so, but the French seem to do more of it. Cold stop shut down is rathr more complex and the big break, for at least the nearby BWR, is between @0% and 0% power. The latter is only done as necessary for refueling.
The existing Gen II PWRs and BWRs probably suffer some thermal stress when doing such primitive load following. The modern Gen III+ are isothermal over a fairly large range, up to 40% for the Areva EPR.
So I conclude that the writer of the cited UK paper is simply poorly informed; there is quite a bit of that regarding matters nuclear, I fear.
David, I suspect you are right. There is a very interesting paper on this subject here:
Click to access 0203_Pouret_Nuttall.pdf
I would be interested to hear comments on this paper from those with technical knowledge about the internal workings of NPPs in terms of power control.
The same economic constraints apply to any capital intensive technology such as wind, solar etc. In the UK Climate Change Committee’s “maximum” renewables scenario, more than 25% of generation capacity is spilled even with lots of interconnects to Norway, western Europe and Ireland.
I’ve never really “got” the argument that nuclear is inflexible compared with, for instance, wind.
Martin Nicholson, on 15 August 2011 at 9:02 AM — Ok, I’m reading. From various comments here earlier on Brave New Climate from ex-navy operators, the first error is on page 3, even though reference  is cited. For the navy’s PWRs, adjusting the pressure, hence flow, of water through the core is primary, used for fine adjustment. When a larger change is required, the control rods are also manipulated. Since the basic operational principles apply to all PWRs and BWRs I have strong reason to believe, from considering the steam turbine side, that the adjustments done are similar for the civilian reacor fleet. The main difference is that ordinarily, in the USA anyway, the civilian operator is almost always working around a control point close to 100% power; not so in the navy.
So I’m not already not overly filled with confidence although it is quite likely I’ll agree with their conclusion based on economics and current system operator requirements.
Martin Nicholson, on 15 August 2011 at 9:02 AM — Next installment:
(1) The description of the operain of PWRs and BWRs is facutally correct; I don’t know enough about the other designs to comment [& so didn’t even read those parts.]
(2) The claim, on page 19, that German wind is allowed to operate at all times is not factual. If the wind dies, the German system operator displatches some cold thermal units (after these make steam; 4–7 hour startup times are acceptable). There is then a minimum economic generation time for the (now hot) thermal units. Those generators then operate for at least that long, even if the wind has picked up again. The wind turbines are not allowed to overgenerate.
Martin Nicholson, on 15 August 2011 at 9:02 AM — Third & last installment: (1) The only thing I learned was the extent to which boron introduction is used to control PWRs & BWRs. (2) In the USA, the market order is such that wind power (in the absense of much solar PV) receives the best figure of merit since the marginal costs are almost zero, or anyway, much lower than NPPs. (3) Yes, if the market is a poorly designed as in Britian then NPPs are going to be almost solely consigned to base load withut load following. A better market design, although not necessarily that of the dictatorial EDF operator in France, may produce price advantages to the NPP operator to perform load following. (4) The central issue for Britian (as I take it) is whether ‘load-following’ NPPs + wind power alone will produce a stable, reliable power grid. That was not addressed in the paper. I have my doubts, but will treat the matter in a later comment independent of this rapid review of a most minor paper.
Thanks David – much appreciated.
It seems while ever we don’t have cost effective large scale energy storage then the issue of using NPPs for load following or spinning reserve will become a bigger issue as we move away from fossil fuels.
If others have further comments on the issue of using NPPs for load following or spinning reserve, I would be pleased to see them.
On load following: I once posted this statement from the technical brochure for the Atmea Reactor (Areva) on another thread.
Click to access BIVOLET%20ATMEA09.pdf
‘Load Following: 100 – 30%, 5%/min, including automatic frequency control, instantaneous return to full power capability, and effluent reduction by variable temperature control.
Don’t know how it is done, or whether we should trust Areva. There was some discussion last time. I don’t remember if there was a definitive conclusion, but it certainly sounds like new NPPs have significant load-following capability.
A simplified grid with just NPPs + wind as generators —
To simplify as far a possible to make an important point, take the demand to be constant, L for load. LAter we’ll alow for variable load, still writing just L. In either case the producers generate G according to the power grid equation
G = L
since the grid has (essentially) no ability to store energy in face of voltage and other constraints.
Now assume two generators to make up G, a NPP providing NG and a wind farm providing WP. The equation becomes
NG + WG = L
with the NPP operator facing the rearranged equation
NG = L – WG.
In this sense wind generation can be viewed as negative load. In the past, with little wind power and with wind generators incapable of being controlled, wind power was just negative load. We explore some of the consequences.
(1) Even with constant load L the NPP operator faces a varying load since WG varies according to the vagaries of the wind. If the NPP operator can load follow fast enough there is no difficulty [I assume to very minor ups and downs of the wind supply are not an issue. For those and more major changes in the wind, follow the green line in the following link.]
But in looking at the large scale strucutre of WG, we generally see a slow ramp-up. Those, taking almost 10–12 hurs are no difficulty for a Gen III or Gen III+ design NPP with its load following capability. However, there are sometimes some faster ramp-ups. Just now I see two with the majority of the ramping within 3 hours. That’ll take a rather flexible NPP. During other seasons of the year it is the ramp-downs which are rapid; those imply that the NPP has to quickly ramp-up, the harder task.
Now add the diurnal cycling of the actual load L. Just now (this week) BPA is generating at maximum with surely both interties wheeling as much power to California as is possible; it is summer in this hemisphere. So in the simplified world of just NPPs and wind, the NPP operator has to face the combination of the variability of load L less the generation provided from the wind farm, WG. The combined variability may well be more than the ability of the NPP. If so, additional system component will be required.
WHile the wind is sufficiently predictable 24 hours in advance, over the longr term there is no way of knowing just when the wind is going to pick up or slow down, in comparison to the diurnal cycle, at least around here. [Yes, this past week it appears that the wind comes up in the afternoon; it doesn’t do that in at least other seasons.]
Now for some evidence. Nothing responds faster than hydro generators, AFAIK. BPA claims to have some difficulty using up to 12 GW of hydro to act as balancing agent (backup) for less than 5 GW (nameplate) of wind power. In the last year about 1.5 GW (nameplate) left the BPA balancing authority to join the PacificCorp balancing autority to the south. [Nothing physically moved; this is an admistrative move to, in effect, a different system operator.] Whether this will resolve BPA difficulties I have yet to determine.
But is does seriously suggest that existing Gen III+ NPPs may not be able to cope with much wind generation. Of course, a thorough system study using historical data for each proposed balancing authority 9system operator) area would have to be conducted to see if that is correct.
But more, modern wind generators have many desirable control features:
IEA Wind Power Study
Click to access T2493.pdf
which can then be used to slow down rapid run-ups. However, ramp-downs, hence NPP ramp-ups, are caused by wind failure and nothing can be done about those except provide alternate generation (or shed load) if too rapid for the load following of the NPP.
The UK DECC white paper on electricity market reform is here: http://www.decc.gov.uk/en/content/cms/legislation/white_papers/emr_wp_2011/emr_wp_2011.aspx
It discusses the need for a “capacity mechanism” of some type and is asking for submissions with a more complete study to be out by next year. Presumably this could improve the economics of load following nuclear – at least the anti-nukes think so because they have been bitterly complaining about it.
Has anyone given thought to my suggestion that as more heavy industrial functions are taken over by nuclear power, such as fertiliser production, smelting, desal, fuel synthesis and so on, the portion of power generation utilising baseload power will inevitably grow, until the requirement for peaking power is a much lower portion of the whole than it is today? How does this affect things?
SteveK9, on 15 August 2011 at 10:42 AM — Wow! Just what the load follower ordered. As Areva even built a prototype yet?
Finrod, on 15 August 2011 at 11:14 AM — Still requires some means of delivering power for the daytime runup. If a smaller fraction of the total then this could be met, in principle, by shallower cycling of the NPPs on the grid.
quokka, on 15 August 2011 at 11:09 AM — The economics of load following and reserve are in priciple simple; pay the operators enough and they’ll fall all over each other to be the first to wnat to do it.
Fortunately, the regulations governing many system operators are such that producers are required take turns doing those services as penalty duty…
Martin Nicholson, on 15 August 2011 at 10:27 AM — You are welcome. I’m not that concerned about load foloowing in light of SteveK9’s reminder. Possibly that smae design can be used for spinning reserve as well; the advert has that implication.
Here’s my 2c worth:
Keeping it simple for a start and think conceptually, the best option is lowest cost baseload for at least 50% of generation plus higher cost flexible plants for shoulder and peak. That is what we have now. This is what the market has given us as the least cost option. If we want to change to low emissions electricity generation it seems likely that a similar arrangement would still provide the least cost option.
If we allow nuclear to be competitive with coal so that nuclear is built instead of coal for baseload plants from now on, then at some distant time in the future (20 to 30 years away), nuclear will be providing most of our baseload generation. From then on, new plants will need some load following capability. It is not until we are starting to build low emission, flexible generators instead of new CCGT and OCGT plants, that we need to be concerned about load-following nuclear. Who knows what will be the least cost option by then. All we need to focus on now is replacing our baseload plants with low-cost, low-emission generating plants.
By the way, I would not see us needing to build large pumped hydro plants, like Tantangara-Blowering, until nuclear is providing most of our baseload generation. That time may be 20 or 30 years away. Then it will be time to start thinking about what is the best option going forward. Will it be load following nuclear, pumped hydro, solar thermal with higher efficiency CCGT back up, or some other technology?
We should not be concerning ourselves with that question now. The only reason we are spending so much time on it is because we’ve become distracted by focusing too much on how to make intermittent renewable generators viable.
Peter Lang, on 15 August 2011 at 11:52 AM — Yes, but the problem is that currently (after figuring in the so-called incentives) wind power is least (LCOE) cost. But then some balancing agaent (backup) must be found. The effect here in the Pacific NOrthwest is to encourage building many CCGTs; at least 6 big ones are coming online soon.
Irrespective of the excess CO2 produced, and even irrespective of the unregualted NOx produced, the natgas would be better saved for utilization as a tranportation fuel and for making nitrogen fertilizer. IMO.
Further to the question of why hydro and geothermal did not make the cut in the above analysis, I’ll cite from our paper:
In short, conventional geothermal and hydro DO meet the FFS requirements, but only in specific geographic locations. As such, they generally fail the scalability criteria (for most countries, there being exceptions like Iceland, NZ, Norway, etc.). Hydro is a more widespread option overall, but it better used for intermediate and peak power demands in most places.
On the question of nuclear load following, this is not an issue (from a technical standpoint) for a fast neutron reactor (Xe-135 poisoning being irrelevant – there are plenty of spare neutrons, and its cross-section is only large relative to other isotopes in a thermal spectrum). It is also a limited issue for LFTRs because they would use continuous online fission product removal. As such, both technologies would be ideal load followers, if the economics of doing so was right.
Peter Lang, on 15 August 2011 at 7:48 AM
The Tantangara-Blowering pumped hydro project would not be suitable for energy storage for intermittent renewable energy generation.
First, to be viable, the sell price of electricity from the pumped hydro scheme needs to be about four times the buy price – so the electricity needs to be generated by low-cost, baseload power stations.
If most energy is from wind and solar, we would expect low prices during periods of surplus and high prices during low output and high demand( as we have now for wind sold through NEM).
Second, the pumped hydro scheme needs to generate for around 8 to 12 hours every day to earn enough revenue to pay for the capital cost. So it needs a reliable, constant supply of power for about 6 to 8 hours every night when demand is low and electricity is cheap. Intermittent generation throughout the year would not earn enough revenue to pay for the plant. (see Reviewer 1’s comments in the article at the top of this thread).
The revenue will be determined by GWh/ stored x the price difference of GWh sold, less GWh used for pumping. Presently the NEM price ranges from $15 to $10,000/MWh (ie about a 700 fold difference). Another source of revenue is selling insurance to customers to protect them from very high prices( a major source of revenue for present Snowy Hydro).
Third, it is not possible to frequently reverse the direction of the water flow in the tunnels, as would be required if used to store energy from intermittent renewable generators. The tunnels contain 20 million tonnes of water. The flow rate at full power is 3 m/s. Consider the power required to stop 20 million tonnes of water flowing at 3 m/s and pump it back in the opposite direction.
I agree with this but its not necessary, load balancing can be performed using some turbines pumping and some generating or other turbines at other locations just generating a variable rates. Pumps can also be designed to operate under variable loads.
Fourth, for intermittent renewables we’d need much greater storage capacity. The storage required for 5 hours of generation at full power (8 GW) is 40 GWh. That is what is needed to allow the pumped hydro to pump every night and generate every day at peak times for the life of the project. Contrast this with the situation if we wanted to use intermittent renewable energy generators instead of reliable baseload generators. The plant would need enormous storage to allow it to generate during long periods when the renewable energy plants are generating insufficient power. We’d need sufficient storage to cover for days, months and decades of below average generation.
If you click onto the OzEA open science link above you can see that with distributed wind and solar the storage requirements are not ridiculously high, probably about X10 more than existing 20GWh pumped storage. For seasonal balancing can use some of existing hydro 24,000GWh storage . A small (15%) over capacity would be adequate for year to years variations. Aluminium smelting could have some flexibility in output, product is easy to stockpile.
Fifth, we cannot use the full storage capacity of Tantangara Reservoir for pumped hydro. Tantangara’s main purpose is to capture spring run off and divert it to Eucumbene Reservoir for long term water storage.
40GWh is only 8% of the 500GWh potential storage. During periods of spring runoff less surplus energy could be stored if Tantangara was at full capacity which would result in less wind storage for a brief period. Less water could be released from other dams that are not at 100% capacity and Tantangara water could be used in preference to other hydro during high demand periods in spring. All water used could still eventually be returned to Tantangara and diverted to Eucumbene for storage.
You are still misunderstanding this issue. Your assumptions are not what happens in practice. For the pumped hydro to be viable we need low energy prices every night from about 11 pm to 6 am. And, importantly, we need steady power throughout that time, and we need it every night.
Also, wind energy costs much more than baseload energy (you need to include the subsidies in the cost). The wind farm has to be paid for. The average LCOE for new wind plants is about $150/MWh ($175/MWh according to the Productivity Commissions (from memory)). And the pumped hydro scheme needs to be paid for. It needs steady reliable power while demand is low, i.e. from about 11pm to about 6 am. That is every day. Not just when the wind blows. There is no point having high wind power during the day time. It cannot be stored because the pumped hydro scheme is generating or in spinning reserve. For wind power to be of any value it would need to be a reliable, steady source of power every night from 11 pm to 6 am.
Read Reviewer 1’s comment in the Tantangara-Blowering article. It explains this. I’ve also explained it about ten times so far on various threads over a period of a year or so. The power for pumping needs to be provided EVERY night. Not just when the wind blows. The fact that prices vary from -$100/MWh to $12,000/MWh is irrelevant. You cannot control when the price spikes occur. This point is a red herring.
This is like the perpetual motion argument. Except you have one tunnel for generating and the other tunnel for pumping. So you have half the capacity. You still need to stop and start the momentum of 20,000 tonnes of water each time the wind power changes. Work it out. If you are not using the full capacity of the plant for pumping at night and generating in the day, you generate less electricity over a year. So you cannot pay for the plant. It’s as simple as that.
I don’t accept that. But not interested in getting into that discussion again at the moment. It is a diversion.
You continue to misunderstand this. Looked at simplistically, Tantangara fills in spring and early summer and empties throughout the year as the water is diverted to Eucumbene. By late winter it must be nearly empty so it can catch the next spring run off (It’s not quite like this because it has other functions as well, but lets keep it simple). If we want to use some of the storage for pumped hydro we need to buy that volume of storage capacity. A volume equivalent of 0.6m depth at full supply level, will give 40 GWh of storage. That is what is needed for the pumped hydro scheme to provide 40 GWh of peak and intermediate power every day. That is what is needed to make the scheme financially viable. You cannot make the scheme viable with intermittent wind generation.
Furthermore, if you want to use the full storage capacity of Tantangara for pumped hydro, then you lose all the water the Tantangara is designed to capture and send to Eucumbene for long term storage. The water would be spilled down the Murrumbidgee River. It does not generate and cannot be stored for irrigation. This has the following consequences:
1. The Snowy Hydro’s average capacity factor over the long term would be reduced, so Snowy Hydro will earn less revenue and/or the price of its electricity would have to be increased.
2. The scheme would be less dependable. We’d need more OCGT to cover for the risk of less water and less generation. (cost and CO2 consequences)
3. the scheme has less water for irrigation
Neil, anyway you look at this, pumped hydro cannot be justified or financed as a support for wind generation. It’s not even close. In fact, as Reviewer 1 pointed out, the scheme would not even be bankable with reliable baseload like coal or cheap nuclear at the moment, let alone with intermittent renewable energy. This is confirmed by the fact it is not being built at the moment and also by Martin Nicholson’s and others comments earlier on this thread regarding OCGT being the preferred to pumped hydro in UK.
I made the point in a previous comment that Tantangara-Blowering would not be viable until nuclear was providing most of the baseload generation. Once we get to the point that nuclear is providing most of the baseload generation then any more nuclear capacity would need to either be load-following or have energy storage such as pumped hydro. Nuclear is generating 75% of France’s electricity by having some load following capability plus having significant hydro and pumped hydro capacity and a little gas and coal capacity. I suggest that France’s proportions of electricity generation technologies is about ideal.
This shows what proportions of the various technologies are generating the power in France now, today, or any previous day you select.
In short, pumped hydro cannot be justified or financed as a support for wind generation or intermittent renewable energy technologies in Australia. Not even close.
If you think differently, I suggest you need to support your contention with the financial case. We’ve been round and round these same points for a year, but you haven’t yet produced any costings to support your arguments.
[…] the BNC comments David Benson wrote a brief tutorial on grid balancing, focusing on the nature of load following that will be required of nuclear plants […]
David B. Benson, on 15 August 2011 at 3:04 AM said:
“… and in the Slapnir[sic?] oil fields, CO2 injection …”
Bill Woods, on 16 August 2011 at 5:20 AM — Thank you.
The attitude of some renewables fans is evident in the various recent posts favouring a wind/pumped hydro mix.
First, the complete lack of consideration of costs borne by other parties and the assumption that all decisions made by those who carry the costs must favour wind generators. This goes beyond selfish to the surreal.
Second, the assumption that water can be pumped both up and down the same conduit at the same time… impossible as well as being pointless. It is still pointless when it morphs into water being pumped uphill in one part of the system and being drawn down for generation in another, to balance wind power. What? Think about it…
Third, what’s this about making aluminium and placing it in a stockpile? Not content with distorting the economics of the power industry to suit their wishes, it appears that the aluminium industry is next in line for a takeover by the wind proponents. I marvel at this capacity to contemplate forcing their product onto the market by demanding uneconomic distortions of that marketplace to accommodate an unreliable product, while at the same time completely ignoring the costs of their actions.
No, the aluminium industry is not a balancing plaything for the wind industry. It makes aluminium, which it sells. If it holds a stockpile, that involves financing charges for holding that stock. Those who think that building a stockpile of aluminium to “balance” wind power’s unreliability should buy the stockpile with their own money, provide for storage and handling and pay for market costs and risks. Till that happens, I suggest that management of the aluminium industry should be left to those who own the business.
The smelters in NSW and, quite possibly, the world over, do have flexibility to load shed for short periods – say, up to an hour – at the request of a generator, via a contract arrangement, for which the generator pays. The owners of the smelters may also choose to avoid or reduce loads during peak periods in order to free that power in the market or avoid paying higher prices in the market, depending on the terms of their long term power supply contracts, which in Australia are very heavily guarded confidential secrets.
Recapping, certain wind proponents demand that all others modify their systems, at no cost to the wind generators, so that wind can do as it pleases. Those systems and customers which are going to have to take their orders from wind include:
Private retail customers, who will receive supply on an availability basis, rather than to follow demand
Small businesses – ditto
Heavy industry – Involuntary load shifting, increased probability of loss of supply
Aluminium smelters – as above
Operators of power grids – but at whose cost?
Operators of all other forms of electricity generation – ramping up and down to fill in for wind involves significant efficiency losses and, for fossil fuelled sources, increased CO2 emissions.
Constructors of transmission systems (through massive overbuild chasing geographic spread and reduced variability)
And now, to top it off, tens of billions of dollars’ worth of pumped hydro.
Is there no end to this arrogance?
This morning, on Channel 7’s Today Show, a professor stated during an interview that wind is 9 times the cost of baseload power. I may not agree with this figure in detail, but at least this demonstrates that some believe that, when it comes to wind power, cost does matter.
I invite you to tune into the Radio National Ockham’s Razor programme, hosted by Robyn Williams, on Sunday 4th September.at 8.45 am. Most of the talk [13 minutes] deals with the inadequacies of the renewables [sun and wind ] and the need to introduce nuclear into our future energy mix as our main base load supply. The Canadian Society of Senior Engineers and Keith Alder [former head of Ansto ] and John Reynolds [executive director of the Victorian Chamber of Mines] give nuclear the big thumbs up. I also call for bipartisanship between Labor and the Coalition on nuclear power and for each party to stop using the issue to wedge the other. If the date for broadcast should change, I shall let you know.
Great summary John B.
I can now quantify the costs of ramp up / ramp down / hot & cold start for a 500 MW coal plant. The following article analyzes these costs, accounting for increased maintenance and capital cost, forced outage, startup fuel and auxiliary power, efficiency loss, and water chemistry cost:
Make Your Plant Ready for Cycling Operations
This is written from the point of view of the plant owner. The costs are broken out in Table 2 on page 3 (for 500 MW coal):
1-23 hours offline: Hot start = $93,900
24-120 hours offline: Warm start = $115,700
More than 120 hours: Cold start = $173,900
Load follow down to 180MW: $13,300
Next questions: what frequency of outage of what duration is imposed by a coal plant supporting wind or solar or pumped hydro?
Thanks to Peter Lang for pointing me to this reference.
John Morgan, on 16 August 2011 at 12:18 PM — Could estimate for wind by following the green line on
@Peter Lang, on 15 August 2011 at 10:30 PM
Thank you for spending the time to clarify you thoughts.
There seem to be three issues that are important for the economics of the Tantangara/Blowering pumped storage proposal.
1) The available storage capacity of Tantangara. The active storage volume is 240,000ML. If in fact it takes most of the year for this volume to be transferred to Eucumbene, thats a transfer rate of 700ML/day, or 20,000ML/month. The 8GW pumped hydro would be moving 3500ML/h. Thus the pumped hydro scheme would greatly enhance the capture of Murrumbidgee water because even if some water was in danger of overflowing Tantangara in spring runoff, it can rapidly transferred to Blowering and later returned to Eucumbene via Tantangara. Thus Tantangara could operate at an average of 50% capacity all year allowing up to 100,000ML( 200GWh) to be stored or used at any one time(24 h at 8GW) and still be able to transfer water to Eucumbene year round.
2) the amount of power that is being stored and released in one year with 5 h power generation/day at 8GW= 40GWh/day or approx 14,000 GWh/year. This would require a daily transfer of 18,000ML.
If wind power provided 75% of the total electricity we would need installed capacity of about 230% av consumption.(CF0.33) so surplus wind would have to be stored or load shed when output exceeds 45% of capacity(this is assuming the remaining 25% is either gas fired or CSP with thermal storage). The present 1800MW of wind connected to the NEM grid exceeds 45% capacity about 10 times a month for about 24h each time or about 2900h/year. If pumped storage could pump at 6GW this would allow 17,000GWh/year to be stored rather than load shed. Whatever the average price(last year Infigen reported an average sale price of wind power of $80/MWh including sales of REC, but claims they need about $100/MWh), surplus wind power will have to be curtailed or sold for very low prices($200/MWh.
Wind will always operate so when wind output is less than demand (60% of the time) the price will be set by the marginal cost of OCGT generation or hydro generation. When wind is in surplus (about 30% of the time) the price will be very low unless there is competition between flexible power users( pumped hydro, off-peak customers, charging EV’s). If pumped hydro buys at $200/MWh) ie achieving >$200/MWh income or $3.4 Billion./year.
3) The cost of Tantangara/Blowering $15Billion or $2,000/KW pumped hydro capacity. So if only 40GWh could be stored in a short period, build 2GW capacity. If 200GWh can be stored at once, build 8GW capacity. Both would give a return of >10% pa on capital investment assuming $120.MWh marginal cost of OCGT.
This does not address the issue you raised, can the output of wind farms be used by pumped hydro? Aggregate output of NEM connected wind has ramp and slew rates of 1-5%/h similar to demand changes. I think variable pumping turbines can handle those rates of change, but if not it may be necessary to have conventional hydro generators operating exceeding the smallest pumping turbine, allowing pumping turbines to run up or run down as wind output and demand change.
I’ve tried to explain pumped hydro in general and Tantangara-Blowering in particular, around a dozen times for you. For some reason you are not understanding. The only way you will understand is to actually do a financial analysis. I suggest you write a paper and lay out your assumptions and the analyses so we can all follow it, Then we can discuss it.
It should be clear it is not viable for what you want because no one is seriously considering building it. What you are proposing is not even close to being economically viable.
@ John Morgan, on 16 August 2011 at 12:18 PM:
This reference is the best of its kind that I have seen in the public domain. Everything in it matches well with my own experience and the conclusions re costs are in the same ball park as my own guesstimates. Excellent!
I highly recommend that article to any reader who understands the layout and basic operations of steam driven power generation.
By way of contrast, it covers a complex topic succinctly and with clarity.
This is the converse of the style of contribution which I wade through from time to time from wind proponents, some of whom seem to delight in hiding from public view any commercial conflict of interest while demonstrating endless capacity to throw meaningless and irrelevant numbers around while drawing conclusions out of thin air. All this is done while denying responsibility for the damage and cost that they are causing to other participants in the power game, its customers… and, notably recently, a proposal to extent the mayhem to the aluminium smelter industry.
I’m not surprised to note that even a sturdy campaigner, Peter Lang, has requested a paper from BNC’s resident principal wind choirmaster, asking him to “lay out your assumptions and the analyses so we can all follow it. Then we can discuss it.”
Sad to say, but faulty analysis of the effects of wind on grids is not limited to Australia – it appears to be universal. I’m convinced that for as long as the wind industry stays on the public teat, it will continue to be justified to politicians the world over by analysis which is, at its roots, unfathomable pseudoscientific mumbo-jumbo by salespeople who are more interested in the money than in results which are objectively measurable and verifyible.
John Bennetts, on 17 August 2011 at 11:05 AM — Less easily quntified problems with wind power include
(1) NIMBY — Some of these concerns are fully justified;
(2) Raptors and other birds — killed or leave the area, including far downwind;
(3) Bat kills — This is quite a serious matter in bat flyways and hunting grounds.
Who will count the deaths of birds over the oceans due to contact with 200+kph wind turbine blade tips? Their carcasses will simply be lost in the ocean and the evidence lost.
John Bennetts, on 17 August 2011 at 12:13 PM — Given the hideosous evidence of the form of many bat deaths, I doubt contact is necessary to cause the death of birds as well.
John Bennetts, on 16 August 2011 at 8:19 AM said:
Second, the assumption that water can be pumped both up and down the same conduit at the same time… impossible as well as being pointless. It is still pointless when it morphs into water being pumped uphill in one part of the system and being drawn down for generation in another, to balance wind power. What?
Most large electricity grids are stabilized by having spinning reserve. Hydro is the preferred method of providing this because of the rapid response of hydro to changes in load. This could mean that some generators of operating at full capacity some at less than full capacity and some just spinning without any water flowing over the turbines. Because of the long pipeline lengths between Tantangara and Blowering the turbines may have a slower response to changes in grid supply and demand. than most hydro. Thus if a large thermal power plant or a nuclear plant or wind power output decreases rapidly, you could have a situation where pumped storage is operating in pumping mode, but other hydro turbines in the Snowy or somewhere else are operated to balance a rapid change in supply. This would only be a short term situation( minutes) unless the Tantangara reservoir was almost depleted, and another reservoir for example in Tasmania was spilling water, then you could have a situation when one turbine was pumping and another generating lasting for hours.
I am certain this occurs frequently in the NEM grid, now, where Tumut 3 is pumping during off-peak and TAS hydro is generating to supply some of Tasmania’s off-peak demand.
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Hello Finrod, that’s a good point re the more constant demand pattern arising from electrifying industrial users.
According to Wikipedia,
37 percent of the average primary energy demand flow of 15 TW is gobbled up by industrial users. So around 5500 GW. These are mostly factories, primary metal production, and construction. These are mostly baseload, usually operating over 5000 hours a year. If we electrify all of it (quite feasible since they are large stationary sources and agriculture is only a smaller portion of this) we get 5500 GW added electric flow. Now things might get more efficient with electric motors and heat pump heating and such, but we’re looking at a bigger world population and greater standard of living so we’d be hard pressed to keep it at 5500 GW of electric flow.
That is a lot of electricity, as today’s electric flow averages, worldwide, less than half that number (about 2000 GW according to the above Wiki).
If we assume today’s electric uses that are already there, double with the original demand pattern kept constant (?) ,then we would be guestimating that the extra demand for baseload would be on the order of twice the ‘normal’ total electric consumption.
So yes baseload will heavily dominate in a globally electrified industry scenario.
What’s todays market for baseload on per kWh basis? maybe 60-70 percent? It could well be 90% in the above electrified scenario.
It could in fact be even better because with baseload plants you have extra nighttime capacity for the normal (non-industrial) loads, and electric cars can be charged off that reliable extra nighttime capacity (since most people happen to like to sleep at night with the car parked). So we’re talking even better synergy here, allowing even more baseload generators while also solving the personal transport vehicle electrification problem.
Electric space heating is also a big contributor, using heat pumps. The heat pumps cost considerable money so it is cheapest to buy a smaller heat pump and run it constantly with some water or other hot store to buffer demand fluctuations.
It seems this type of calculation is very difficult to do on a detailed level since it relies on assumptions on future markets and what we can or want to electrify.
For example with the plugin hybrids, for my country, The Netherlands there is a peak demand of around 16 GW during the day, but is several GW lower in the nighttime. If we decide on 16 GW of nuclear (eg 10 EPRs) and run them constantly we get around 50 GWh extra every night to charge plugin hybrids. That’s about 4 million plugin hybrids with our driving habits, which is 50% of the number of cars in my country. Not bad, without building a single dedicated plugin hybrid charging nuclear plant, we could get 50% of the car fleet electrified and run the nuclear plants flat out as a bonus! With another 1 and a half of those large nuclear plants we’d get 100% of the car fleet electrified (well almost since some cars do run long distance).
This scenario is a 100% baseload nuclear one with 100% car electrification. Haven’t even included more electrification of industry here!
Nd you’ll be able to sell excess to Germany & Denmark, both of which will surely need it.
I doubt that construction provides anywhere near as big or as steady a load as water and sewage pumps. I understad that in some regions, the combined water and sewer loads are bigger than whatever comes second. To a certain extent, these demands are able to be managed. Example: If a transfer between two water reservoirs takes place over night, rather than during the afternoon peak, it will still happen in time but the load has been moved away from the peak.
I have not heard that this happens systematically, or that it does not, however this load is much easier to slide to off-peak than, say, construction loads which you mentioned. I imagine that demand management is used, to the advantage of Sydney Water or Hunter Water, etc and, in your country, for the many large dewatering pumps. Does anybody know for certain?
Also missing from your list were electric rail and mining, neither of which lends itself to demand management, but each of which are very substantial loads, at least in Australia.
I say this to indicate that some loads are easier to manage than others. Time of Use metering, coupled with the actual market prices, is able to provide the necessary commercial incentive for these larger users to reap the benefits, and surely it is easier to manage (say) 10 or 20 large pumps than thousands of tiny loads in houses.
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Instead of uranium-fuel reactors we can use thorium-based reactors. Thorium is plentiful in many places of the earth, including India, Australia and the US.
I just posted an article which shows that CO2 intensity, gram CO2/kWh, is least at no wind and that it increases as CO2 intensity increases. In less than a day the article had over 350 views.
In particular read the Dr Fred Udo article which analyses the real-time, 1/4-hour operations data of the Irish grid posted by Eirgrid on its website.
By reading some of my other articles you will have more context
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