However as gas depletes towards mid century that could seem like a bargain. A follow up exercise might be how much of already installed wind capacity can be used as gas depletes. For example South Australia has 1100 MW of wind capacity but perhaps 10 years of reliable gas supply left.

Re China coal peaking note Clive Palmer’s new mines in the Galilee Basin Qld will be called ‘China First’, totally immune to carbon tax. I see new coal loaders approved for the US Pacific northwest coast. Maybe China is running out. Quoted in TOD the BP Energy Outlook 2030 says China will burn 3 Gtpa of coal until 2030 at least. Thanks for cooking the planet.

A miss-titled article really says that the AP1000 is behind schedule – http://af.reuters.com/article/energyOilNews/idAFL3E8CF0BF20120115?pageNumber=1&virtualBrandChannel=0

China AP1000 nuclear plant on track after delay-Xinhua

“Construction slowed following the tsunami, to allow for design adjustments and “stricter construction requirement for endurance concerns”, the Xinhua news agency said, citing remarks by Wang Binghua, board chairman of the State Nuclear Power Technology Corporation (SNPTC) on Saturday.

The tsunami badly damaged reactors in Japan and led to questions over the safety of China’s ambitious nuclear plans. China plans to start building new capacity almost equal to Japan’s entire nuclear power sector by 2015, to reduce its dependence on coal.

“Both the SNPTC and Westinghouse have agreed that the new reactors are able to survive the same shock experienced by the Japanese plant,” Wang said.

The two companies are still mulling over further efforts to ensure nuclear safety, he added.

Wang said an optimized construction schedule would allow the No.1 unit of the Sanmen nuclear power plant, in east China’s Zhejiang province to begin operation in 2013.”

The first four pumps were originally scheduled to ship to eastern China in November. Making the change and retesting will delay that until the second quarter of 2012, Benante said. I’m not sure whether the pump delay cause the build delay or just added to a bunch of other problems. Here is what the pump maker says, ”

Read more: Nuclear plant equipment to get revamp – Pittsburgh Tribune-Review http://www.pittsburghlive.com/x/pittsburghtrib/business/s_749669.html#ixzz1m0UaDRep
”

http://www.pittsburghlive.com/x/pittsburghtrib/business/s_749669.html

The most visible mile stone is the dome of the containment vessel scheduled for Dec 2011. It is not there yet. If it is placed in June 2012, the project will be 6 months behind the original schedule.

It is irritating that the Chinese press and Westinghouse say, “Sanmen #1 is on schedule”. What they mean is that Sanmen #1 is on a new schedule.

u-235 is peaking

Extraordinary claims require extraordinary evidence.

Peter Lang wrote:

EDM-2011 cited this comment on OzEA as the basis of their pumped hydro energy storage capacity, but they did not realise there is a constraint on the rate at which energy can be stored.

Sure enough, charge rate does appear to have a bottleneck at existing pumped hydro facilities (and other hydro plants) in Australia. If they intend to continue to use existing facilities in their calculations, they will have to update their figures in their model, and adjust for any efficiency losses for shorter term charging cycles. Perhaps this is what they meant when ruling out “water availability” in their calculations … excluding both environmental resource constraints and charge rates on existing facilities (up to full available capacity). It should be helpful to have these numbers published and documented here and elsewhere.

As concerns feasibility and costs of PHES in their paper, I’m not sure why they limit their analysis to “existing hydro” when looking at energy storage options for NEM? They are clearly proposing a broad buildout of generating technologies (CST and more), why not do the same for energy storage and run their model to more fully cover the winter period, maximize capture of spilled energy, and use less biogas on an annual basis? In Australia, energy storage from pumped sea water should be an option (anybody else know about specific proposals). Japan has an operating plant (31 MW with about 6 hours of storage), and Ireland is looking to do the same (980 MW with some 6 hours of storage). A Diurnal Storage Presentation (p. 14) at a recent DOE energy storage workshop suggests ocean pumped and variable speed PHES is less than five years from commercialization (with stainless steel components and fiber-reinforced plastic tubes in penstock and tailrace to minimize corrosion and barnacle concerns). A peer reviewed study from 2010 suggests CAES as a more affordable option than PHES for Australia, with an estimated 15.4% rate of return on capital investment (as compared to 9.6% for a sea water pumped hydro plant). Natural caverns, old mines, depleted gas, and aquifer reservoirs may be available for larger CAES facilities. Obviously, with lower cost fossil fuels available for capacity reserves there’s not much economic incentive to currently pursue these more expensive storage options (unless rising fuel prices, high marginal costs, supply interruptions, policy mandates, carbon costs, technology breakthroughs, or other externalized costs of fossil fuel generation are added to the picture).

One other issue concerning cost. Traditionally, PHES has been a strategic tool for baseload developers, especially in helping with thermal power efficiency and flattening out load variations. So while expensive, it often has operational and power utilization benefits that far outweigh it’s per kWh levelized investment cost. Increasingly, markets are starting to reward these benefits, and so comparing this to the wholesale rate of energy may not be particularly illuminating. How to properly price the value of stored energy (for such thing as distributed generation and power quality end-use, ramp rate control and load time shifting, voltage regulation and capacity services, transmission stability, and anything else) is anybody’s guess at this point. At the same DOE conference mentioned above, the lead presentation (p.49-51, and throughout) mentions a list of proposals for market reform at national level, state, and among PUCs in the US to perhaps make better use of ancillary and energy storage services (apart from generation). Perhaps something like a rate of return on investment might be a better measure for understanding the comparative costs of storage plants (rather than levelized costs of the energy that is being produced at them)?

If we are, will geological limits enact a ‘carbon price’ of it’s own in time to stimulate new thinking about ‘unreliables’ and good reliable GenIV power?

I also subscribe to the theory we are on the cusp of ‘peak coal’.
Geologically we couldn’t burn all the coal in the ground if we tried.

Here is a 1997 report on US Coal mining productivity
http://www.rff.org/documents/RFF-DP-97-40.pdf

Key sentence -
Labor productivity in U.S. coal mining increased at an average annual rate of slightly over four percent during the past 45 years.

Here are the latest figures. Productivity is going backwards. More miners producing the same amount of coal.
http://www.nma.org/pdf/c_trends_mining.pdf

Then some interesting facts on Chinese coal
http://www.circleofblue.org/waternews/wp-content/uploads/2011/02/coal_bohai_report.pdf

The average depth of China‘s coal mines is 456 meters. Whereas northern China has the most abundant and highest quality coal, Xinjiang province (in far western China) has more than half of coal reserves located less than 1,000 meters below the surface. Only 27% of northern Chinese coal is located less than 1,000 meters below the surface, compared to 40% of total Chinese coal.8 Mines in eastern China are particularly deep, with an average depth of 600 meters.

Free capital (investor owned capital) always flows to the investments with greatest returns in the quickest amount of time. This is why the western economies are essentially speculative in nature, far profit is to be had pushing paper than milling it and producing it.

For nuclear power plants to proceed, major degrees of costs, since return on the dollar is a minimum of 48 months, have to be assumed by the tax payer. I think this is a good thing, not a bad thing.

You’re convinced we’re already passed peak coal? I didn’t even think Heinberg was at that point. Or has he shifted?

If we are, will geological limits enact a ‘carbon price’ of it’s own in time to stimulate new thinking about ‘unreliables’ and good reliable GenIV power?

I do pay attention to estimating the costs of various forms of energy generation. First of all, these are generally acceptable and offer persuasive argument. Second, such estimates seem to me to fairly well grounded in physical reality and so I find such to be rational starting points; only actual experience with one or another generation method offers reliable data.

Perhaps even before 1970, economists generally agreed that the most efficient way to control pollution is to tax it. Controlling pollution is not free; it costs money. It can be shown that if it is controlled via taxation, and people behave rationally, the money spent to control pollution will be spent more efficiently. Even if people do not behave entirely rationally, the money spent to control pollution will be spent more efficiently than if regulations require all sources of pollution to be reduced by the same amount.

The objection to a pollution tax is largely emotional; people claim that it is a license to pollute and object to it on that basis.

“I find the idea that a ‘carbon tax’ is somehow a ‘free market’ approach somewhat puzzling. If we put a ‘punitive tax’ on a product or service we are ‘regulating via taxation’. Why not just ‘regulate’ directly?”

The attraction of a carbon tax, according to economists, is that it should be more cost-effective than regulation.

Here’s Milton Friedman, writing in 1980:

“Most economists agree that a far better way to control pollution than the present method of specific regulation and supervision is to introduce market discipline by imposing effluent charges.” Free To Choose, p. 217.

Part 2 to my reply to your questions

I also don’t see where they intend to use stored energy during “most of the year” for release during a “few short periods in winter.” As they state in the paper, PHES is utilized for storing “spilled” energy and daily balancing to maximize yearly gross energy production: “In this scenario, pumped storage hydro plants are charged using spilled energy and dispatched first to maximize the energy supplied year round” (p. 3). They state the main benefit from hydro storage (at the low energy storage levels achievable in Australia) is not meeting peak demand, but offsetting biogas consumption (p. 9).

But EDM-2011 also point out the system they simulated cannot meet the demand on some days in winter. EDM’s figure 2 does not make the problem clear because the 0 to 2.2 GW on the vertical axis has been truncated. This is where the pumped hydro should be displayed. So, I refer readers to their Slide 12 here: http://www.ceem.unsw.edu.au/content/userDocs/Solar2011-slides.pdf.
The dispatch order has been changed so pumped hydro is not the first to be dispatched. The dispatch order is:
• Wind,
• PV,
• CST,
• pumped hydro,
• hydro,
• gas turbines running on biofuel.

This is a more sensible and realistic dispatch order, than the one presented in the paper, from the point of view of trying to minimise the cost of electricity (given the technologies assumed by EDM-2011, their capacities and capacity factors).

Slide 12 shows that very little pmped hydro is available during the critical days in winter. For the 8 days shown in Fighre 12, there is no pumped hydro generation on four days, and very little on the other four. In fact, the the CST plants have not even been able to recharge their storage on those days.

My point was that the pmped hydro is most needed on those days in winter. To be most effective, pumped hydro would need to be maitained at full storage before entering those periods in winter. That is storage throughout the year until those critical periods in winter. This is what is critical for reducing the total capacity of biofueled gas turbines that would be required to provide a reliable electricity supply. The use of pumped hydro to reduce the amount of biofuel energy generated is a seaparate issue from the peak generating capacity required.

Just to repeat the point of your comment/question:

I also don’t see where they intend to use stored energy during “most of the year” for release during a “few short periods in winter.”

The point I was attempting to make is that pumped hydro is of little value in helping to meet winter peak demand. It also plays only a small role in summer at huge cost to avoid a little generation from biofuels (from looking at Slide 11).

I hope this has addressed this comment/question satisfactorily.

Just to head off any tendency to get down into a pedantic discussion about points of figures that have no significant bearing on the costs, can I suggest that we focus discussion on issues that do have a significant bearing on costs.

Thank you for your questions and comment. I’ll answer your questions in two separate replies.

Care to tell us why this is the case. I don’t see where the authors have widely missed the mark on hydro storage capacity and requirements. 2.2 GW capacity at 20 GWh DOES reflect an upper storage limit …

I need to provide more explanation on this. I’ll give a short answer here and intend to write up a more detailed comment to post on the Pumped Hydro thread and perhaps on OzEA to add to the previous comment here http://www.oz-energy-analysis.org/feed/show_me.php?comm=OzEA_DG0002 which addressed the question:

What is the total energy storage capacity (in GWh) of Australia’s existing Pumped-Hydro facilities?

The short answer is roughly 5 GWh can be stored per day and 20 GWh total.

EDM-2011 cited this comment on OzEA as the basis of their pumped hydro energy storage capacity, but they did not realise there is a constraint on the rate at which energy can be stored.

I need to add to the OzEA comment an explanation of the rate at which energy can be stored in the three existing pumped hydro plants.

Is the short answer:

“20 GWh DOES reflect an upper storage limit”. This satatement is correct.

“2.2 GW capacity”. No. That is not correct. Wivenhoe is the only pure pumped hydro scheme in Australia. The other two PHES plants have some pumped hydro capacity within a plant that is mainly a hydro plant. EDM-2011 attributed the full generating capacity of these plants to pumped hydro.

Only 0.9 GW of generating capacity can be attibuted to pumped hydro. The remainder of the 2.2 GW EDM-2011 assumed should be attributed to hydro. Furthermore, there are energy losses in pumping and generating, so only about 75% to 80% the energy can be recovered.

Wivenhoe PHES:

All the water Wivenhoe PHES plant uses to generate power must be pumped up from Wivenhoe reservoir. It can store energy (that is energy that can be recovered, after losses) at the rate of about 328 MWh per hour. It pumps when demand is low and electricity is cheap – between about midnight and 6 am (longer on weekends). It is on standby (spinning and ready to go to full power within less than 1 minute) for about 12 h per day and generating to meet peak and intermediate demand for about 7 hours per day (at variable power output). It generates a little during standby to balance power and frequency fluctuations in the grid. It cannot pump while it is generating or on standby. Because it is needed to be generating and on standby during the day, and because power is cheap at night, the pumping is done at night when the plant is unlikely to be needed for generation.

It takes a lot of energy to start pumping the water. The weight (~23,000 tonnes) of water must be lifted up 100 m against gravity and accelerated from 0 to 3.6 m/s velocity each time pumping starts. Therefore, it is not economic to repeatedly stop and start the pumping. The pumps are not variable speed so once started they run at their constant pumping rate of 207 m3/s.

Therefore, the pumps should only be started if they can be assured they will pump for at least several hours (e.g. 5 hours, but I said let’s assume a minimum of 4 hours to be economically viable).

If we assume an average of 5 hours of pumping time per day and energy storage at the rate of 328 MWh per h, then Wivenhoe can store about 1,640 MWh per day.

Tumut 3 has 1,500 MW of generating capacity in six generating units but only three have pumps and the power of the pumps is only little more than half the power of the generators. So it is not appropriate to assign the 1,500 MW of Tumut 3 generating capacity to PHES.

Bendeela & Kangaroo Valley – similar comment to Tumut 3.

See more details here:
http://www.oz-energy-analysis.org/feed/show_me.php?comm=OzEA_DG0002

If Germany and / or other countries demonstrate, by unarguable example, that solar and wind power are not practical, then we in the U.S. may be able to avoid, at least partially, the same mistakes, provided that the mistakes receive sufficient publicity.

This does not mean that wind and solar power should be completely abandoned; there are places and situations where they are the best sources of power, but not as a primary source of power for large countries. Solar power can significantly enhance the quality of lives for people in small remote African villages and in small Pacific Island countries where connecting to the grid is not practical.

Thank you. Excellent points.

I’d add, if we want to reduce emissions from all energy consumption, electricity will have to replace gas for heating. That means the peak Melbourne cold morning peak demand would be even higher.

John Bennetts, thank you for the comment. Can you suggest any refinements for the transmission estimate (see Appendix 2 in the PDF version)?