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Review of the Western Wind and Solar Integration Study (WWSIS) by NREL and GE Energy
Posted by Stephen Balogh on December 6, 2010 - 10:21am
(The post below is from Steve Balogh, a contributor on TOD since 2006 writing on sustainability issues under the name Baloghblog. He is a graduate student at SUNY-Syracuse and is a research associate working on energy systems for the Institute for Integrated Economic Research)
This post presents a critical review of the Western Wind and Solar Integration Study (WWSIS) published by NREL and GE Energy earlier this year. The goal of this multiyear study was to determine the feasibility of incorporating large amounts of wind and solar energy into the Western U.S. and determine the effects of doing so.[i] An earlier Department of Energy study, 20% Wind Energy by 2030, found that in order for the continental U.S. to achieve 20% as a whole for wind energy consumption, 25% would have to be produced in the Western Interconnection. The authors of the WWSIS study conclude that it is possible (with a few caveats) to absorb and manage highly variable production from high penetrations of wind and solar energy, up to 30% wind and 5% solar. This post provides an overview of the assumptions and models used in the study, reports major findings, and considers what may be flaws inherent in the NREL/GE Energy efforts. (An executive summary of their project, models, and findings can be found here, and the full study here.)
Background
The WWSIS study area consists of land in 5 states in the U.S., the “West Connect” group of utilities, Wyoming, Colorado, New Mexico, Arizona and Nevada (WY, CO, NM, AZ, NV) which are in the Western Interconnection in the United States. The Western Interconnection includes nearly the western 1/3 of the U.S. from Washington down to California, and its eastern border includes the states from Montana to New Mexico (see figure below).
Modeling Assumptions
Our analysis of the study begins in the modeling assumptions. The authors conclude that 30% wind, and 5% solar integration in the West Connect region is possible – even at high (20%) penetrations of renewable energy in the greater Western Interconnection – if the following conditions are met (p. ES-3):
1. Substantially increase balancing area cooperation or consolidation, real or virtual;
2. Increase the use of sub-hourly scheduling for generation and interchanges;
3. Increase utilization of transmission;
4. Enable coordinated commitment and economic dispatch of generation over wider regions;
5. Incorporate state-of-the-art wind and solar forecasts in unit commitment and grid operations;
6. Increase the flexibility of dispatchable generation where appropriate (e.g., reduce minimum generation levels, increase ramp rates, reduce start/stop costs or minimum down time)
7. Commit additional operating reserves as appropriate;
8. Build transmission as appropriate to accommodate renewable energy expansion;
9. Target new or existing demand response programs (load participation) to accommodate increased variability and uncertainty;
10. Require wind plants to provide down reserves.
Another important assumption is that the new wind and solar generating capability will be added to the existing power plants, and those scheduled to be added by 2017. The current generating capacity (renewable and non-renewable) of the western interconnect is 184 GW with a capacity margin of 22% (total unused capacity available at peak load as a percentage of capacity resources). According to the EIA, this is expected to rise to 204 GW by 2013 with a capacity margin of nearly 30% (see table below). At the proposed maximum integration of wind and solar (30%/5%), along with an additional 20% outside the study area within the Western Interconnect, 75.4 GW of nameplate wind capacity and 13.3 GW of solar will be added. Although the net capacity addition will be smaller due to the lower capacity factors of renewable electricity generation (capacity factor assumptions: 31.6% Wind, 15% Solar, 90% CSP), according to my estimates, this still represents a substantial increase in capacity margin to the system.
Table 1: Total (Thermal and Renewable) Electricity Generating Capacity
| Western Interconnect | Maximum Generating Capacity | Capacity Margin |
| Current | 184 GW | ~22% |
| EIA Projected (2013) | 204 GW | ~30% |
|
EIA Projected+WWSIS Proposed: 30% Wind / 5% Solar |
293 GW | ~39% |
Challenges to the study’s assumptions:
According to my analysis, the assumptions highlighted in bold text above are the ones that present the greatest challenge to the feasibility of the project. The NREL authors readily admit in most cases that these issues will be difficult politically and technically (but maintain that they are not impossible) to overcome. Let's look more closely at these assumptions, and examine how the system as it currently operates differs from this proposed.[ii]
1. Renewable energy capacity added on top of proposed and existing capacity
The authors are able to disregard the periods of extreme underproduction, even if these periods are infrequent, by assuming that we will continue to add traditional thermal (fossil fuel) generation equal to the amount needed to meet demand without renewable energy. This is consistent with one of the key findings of my dissertation research to date: that in order to increase generation capacity of renewable energy from stochastic sources, traditional, controllable sources of electricity generation must be maintained sufficient enough to provide 100% of the demand, if the renewable energy sources are producing 0%.
2. Grid Network Integration
The scenarios assume that the patchwork of over 100 independently managed grid sections can be neatly combined into 5 large grid regions. This goes hand in hand with the assumption that the current delivery system that includes dedicated or reserved transmission lines would be eliminated and replaced with a barrier-free transmission grid open to any suppliers. All generation would need to be economically dispatched, and managed across several states, e.g. if there is overproduction from higher than forecast wind in WY, flexible generation in combined cycle plants could be turned down in NM if that were the nearest and most economical option (p. ES-17). During extreme variations in wind production, grid stability would be dependent on absorption of excess wind, or ramping up of power plants in the greater Western Interconnection. At several times in the report, the importance of the greater interconnection to the feasibility of the West Connect projects is stressed. During at least one week in April, the authors admit (p. 310):
the high, variable, wind output dominates the net load … leading to several hours of negative net load[iii] during the week. Combined-cycle generation is almost completely displaced, and significant levels of coal generation are displaced by wind and solar generation. Nonetheless, the system can operate through this challenging week with balancing area cooperation. Without balancing area cooperation, operations during the week would be extremely difficult, if not impossible, for individual balancing areas.
Because of the assumed balance area cooperation (and other assumptions), the authors highlight that at 30% penetration, only 0.5% of wind energy production would need to be curtailed.
3. Coal plants are able to be operated as load-following plants, substituting for higher cost natural gas plants
The study also assumes that coal powered power plants can be, and will need to be operated in a very flexible manner, at times operating at only 40% of nameplate capacity. While this may be consistent with emergency operating levels, the rapid and frequent increase and turn down of coal power plants over a long period of time is an untested use of their capabilities and is expected to increase operating expenses and maintenance time (p. 104, 141). This repeated cycling of coal power plants would increase the cost of electricity from coal, while at the same time, revenues earned by coal plants are expected to decline due to decreased operating times.
4. Maintaining spinning reserves to deal with infrequent extreme changes is cost-prohibitive. Load management will be used because it is more economically feasible to do so.
The authors conclude that maintaining enough spinning reserves[iv] to deal with infrequent extreme changes in wind and solar output relative to demand is not cost effective, and that demand response programs (load management) should instead be incorporated. However, the authors do not delve more deeply into this issue, nor propose which businesses or loads would be available to be curtailed at a moment’s notice, only stating that even high economic incentives for demand control would be cheaper than maintaining high percentages of spinning reserves. Unlike the current system of peak load shedding or load-shifting (which mostly takes place during peak loads in the summer, or during periods with the highest energy prices), the episodes where there are rapid decreases in wind and solar production are often not coincident with large increases in demand, meaning that those participating in the demand-side management would need to be much more flexible, and available to cut back loads at all hours of the day at any time of year. Equally, wind and solar do not result in short or periodic disruptions, but rather in extended over- and undersupply situations. This relative unpredictability creates negative economic implications (equipment utilization and workforce flexibility).
5. Expansion and development of renewable energy capacity will be a coordinated process
Also inherent in the study is that the expansion of renewable energy, especially wind, will be a coordinated effort whereby each state progresses to a similar penetration level. The authors admit in the study that individual states with large increases in wind penetration face multiple hours per year of overproduction (p. 55, for example). If the other states were not progressing as quickly as others, or if individual states where wind power capabilities are higher decide to seek a higher penetration level of wind, it may result in a disruption of the balance of electricity production and result in the curtailment of wind energy during periods of high wind production. If a state outside the study area, take California for example, decided to raise their R.E. capacity higher than the 20% modeled in the WWSIS, the challenges to integrate high levels of R.E. in the study area may become too great to overcome.[v] The authors do run an alternative scenario where new wind capacity is built in the best available wind resource areas, and interconnections between states are constructed – this scenario also assumes a even higher level coordination of development.
6. Other modeling issues
Models by definition are simplifications of a system (Hall et al. 2000). In the WWSIS the authors examine interstate transmission costs, but chose not to include and examine the cost of building intrastate transmission lines to handle the increased remote generation by wind or solar farms (p. ES-7). The sunk costs, economic or energetic, were also ignored for the purposes of this study but should be examined with more scrutiny in future studies, as proposed.
7. Electricity Storage
In the “give credit where credit is due” category, I'll point out the study’s examination of high capacity storage’s role in an electrical grid with high levels of renewable energy. The authors reach the same conclusion as I have - that large scale storage as a means of capturing excess wind and solar power and releasing it during times of need is not economically feasible, nor is it as helpful as initially suspected in filling production gaps. The authors use pumped hydro storage as their example storage system – pumped hydro being the most inexpensive form of storage, and having high turn-around efficiencies over long periods. According to the authors, even with perfect forecasting, the units were still much more expensive than just adding additional flexible generation from natural gas. Pumped hydro storage was not able to take advantage of price arbitrage during the day. Quoting (p. 281):
At the 30% penetration level, the [annual operating] value [of pumped storage] jumps up significantly, but is still only $3.8 million/year of operating value. This translates to roughly $380/KW which, even with a generous capacity value, is still more than $1000/kW below the cost of a new [pumped storage] facility. Even perfect foreknowledge of when the prices will spike and drop does not seem to provide sufficient value to justify adding any new storage facilities.
Short term storage in concentrated solar thermal plants does show some promise. PV solar production begins to decline just as the afternoon demand peak begins; however, CSP with storage allows these plants to produce power through periods with the highest demand. CSP storage benefits saturate at approximately 6 hours, and add 10% to operating revenues (p. 285). This, however, only partially mitigates the high cost per MWh from these plants in comparison to traditional thermal generation and even wind.
8. Plug-in Hybrid Electric Vehicles
The authors also examined the load effects and storage capabilities of Plug-in Hybrid Electric Vehicles (PHEV). Starting from a dubious assumption, that PHEV would only be charged at night, and then only during the hours of 11 p.m. to 6 a.m. the authors conclude that PHEV do increase the value of renewable energy by 50 cents per MWh, but also find that (p. 289):
Adding the PHEV demand did not significantly change either the unserved or the spilled energy.
9. Other interesting findings:
- Large solar and wind drops tend to be more coincident across wide areas than large rises (p. 86)
- Distributing the wind generation capacity as a percent of state demand, rather than based on the best suited sites within the multistate area, compounds issues of over and underproduction. For example to meet 30% of Arizona’s annual demand from wind power would require a much larger installed capacity than if the wind were installed in Wyoming where wind resources are greater. In Arizona this would mean that wind production would push the minimum net load (demand minus wind minus solar) below current observed minimum levels for 45% of hours in the year. And the highest minimum net load is 5 GW (wind and solar output is 5 GW higher than demand). (p. 55)
- For the entire study area at a 30% level of annual wind production, the minimum net load (load minus wind minus solar) would be below the current minimum load of 22,169 MW for 57% of the year (p. 53). The authors report “there is nothing inherently critical about this minimum load threshold. The system may be able to operate well below this load level, but it simply serves as a reference point for illustration.” How much “well below” the observed minimum load level that can be tolerated remains to be seen. Our contention is that coal plants are much less flexible than assumed in this study. What is not debatable is the fact that the minimum net load hour for the year (modeled after 2006 wind conditions) reaches -2,914 MW. This means that wind and solar production, alone, in this hour, produced an excess 2,914 MW – this without considering any other base load plant that might be operating (nuclear, base load coal, etc.). This is nearly 3 GW of electricity that must be exported and absorbed outside of the system (see figure below).
10. Accuracy vs. Precision
One final issue that must be raised is the issue of accuracy versus precision. Very precise values are given for the amount of wind consumed/curtailed/exported, as well as precise dollar amounts for costs and savings (although they have been rounded, only a single value is given). It is understood that decision makers like to have solid numbers to judge whether a project should move forward or not. However, it seems reasonable, given the highly variable nature of wind and solar production, as well as the inherent variation in electricity generation and consumption itself, that the predicted values should be presented as a range, or confidence interval, rather than a specific estimated number.
Conclusions
The NREL/GE Energy WWSIS study appears to be built on several questionable assumptions, each allowing the modeled system (of up to 30% wind/5% solar in the West Connect within the great Western Interconnect) to withstand the inherent difficulties of large scale renewable integration. The primary issue, consistent with my dissertation research[vi], is that the authors assume that we can afford to massively overbuild the capacity of the system, adding the large percentages of renewable generation on top of newly built and existing plants. This allows one to be able to ignore the hourly or sub-hourly periods with extremely low output from renewables, as well as the days or weeks at a time during the summer when wind production is well below yearly average output levels. An ample reserve is at the ready to step in when renewables perform poorly. Secondly and equally important, the authors assume that coal plants, which have traditionally run in a base load capacity, will be able to be operated very flexibly – on par with combined cycle gas plants. This allows the authors, on one hand, to state that electricity prices will be kept low, because we will still be able to burn less expensive coal as our primary non-renewable source of electricity (instead of having to switch to more expensive natural gas), but also to claim increased upside flexibility in the system to deal with periods where wind and solar output decrease rapidly and reserves need to be brought on line. Next, like previous studies, the authors assume that there is an “away” to export excess generation to during times of overproduction. By assuming that the greater Western Interconnect is available to absorb excess production (by economic dispatch and regional grid management), the authors assume minimal to no curtailment in wind production needed in periods of overproduction. If on the other hand balancing is limited to smaller areas, the authors admit that the system might not be stable.
It is my opinion that this study is far from conclusive in its assertion that very high penetrations of wind and solar electricity generation are feasible in the Western Interconnect. Although the authors of the study performed a very detailed analysis, it is one that I feel is based on technological, bureaucratic, and political optimism.
Endnotes:
[i] The WWSIS is the sister product of a study that began in 2008 and was completed in January 2010, on the feasibility of adding 20-30% wind energy to the Eastern U.S. electrical grid (EWITS).
[ii] I do not assume in general that technological or political progress is not possible or feasible. My objection lies chiefly with the methodology used in this study. I feel that the results would be more telling if the authors had first examined the issue from the current state of technology and cooperation, and then modeled the required changes needed to attempt to operate an electrical grid with over 1/3 of generation from wind and solar power.
[iii] Net load is defined as demand minus wind minus solar
[iv] Spinning reserve: Spinning Reserve is the on-line reserve capacity that is synchronized to the grid system and ready to meet electric demand within 10 minutes of a dispatch instruction. Spinning Reserve is needed to maintain system frequency stability during emergency operating conditions and unforeseen load swings.
[v] California has just adopted a 33% renewable energy standard for electricity production by 2020 (see here and here for details). This standard does not allow renewable electricity production by utilities in other states to count towards the 33% level – all production must be from California utilities.
[vi] My prior research at IIER found that in large scale integration of wind energy, to maintain grid stability, capacity in traditional controllable sources of electricity generation – equal to the maximum demand level – must be maintained in order to avoid supply/demand mismatches. This principle applies to both small scales (state or country level) to large scale multi-nation grid systems.
Review of the Western Wind and Solar Integration Study (WWSIS) by NREL and GE Energy
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Review of the Western Wind and Solar Integration Study (WWSIS) by NREL and GE Energy
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204 comments
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It sounds like whoever works out a low cost storage technology will make a fortune!
Thank you Steve. Your article seems to indicate that BAU with renewable sources is unlikely. There will be supply interruptions. Local storage of energy (lifted water, batteries, stored heat) will be essential. And rolling blackouts and service interrupt contracts will be the rule. Some of the generally high levels of renewable EROeI will need to be expended in balancing. A 25% loss for round trip pumped hydro drops EROeI to 4:1 from any value. Doubtful an industrial society could exist if all energy had to run through that loss rate.
Our current industry locations are determined mostly by transport cost (near ports/rivers) or proximity to resources. Perhaps in the future, industries will rearrange so those that must not be interrupted will move to locations with hydro or geothermal. Those more tolerant of intermittent power will move to the wind / sun belt, etc. Perhaps Iceland will become one of the world's great manufacturing centers due to its reliable geothermal.
Your article seems to indicate that BAU with renewable sources is unlikely.
BAU, with or without renewables is dead, when can we start the mourning period and end all this denial and just move on?
This may be known on these pages, but is not widely known, and if it is suspected, the details and reasons why are not really understood.
"Moving on" will require an almost across the board belt-tightening. Also, our systems are built for 100% on demand electricity (related to this post) - more research needs to be done looking at the implications of 'something less than 100% reliability' -won't be good for GDP throughput, but might be 'good' overall. The problem of course is that even if BAU is recognized as doomed, if its still viable for 5-10 more years there won't be strong incentive to change until the day it becomes non-viable in fact - until then all sorts of other front burner issues will occupy decisionmakers in all likelihood.
First, I have something of an issue with your (not you specifically Nate, but with everyone who uses the term "BAU" "BAU supporter" as a perjorative) argument techniques. The wording is designed to align anyone who argues for less than a total collapse in the near future to be unconsiously connected with "big business", "large industry", "fossil fuel utilities" etc., whereas I contend that it is rational to postulate that peaking of LIQUID PETROLEUM production worldwide does not necessarily REQUIRE complete economic collapse back to the days of whale-oil lighting, as most here would appear to prefer.
Second, I can make a very strong case that the author's base assumptions are factually flawed. Solar thermal technology is a) readily amenable to generating at peak demand hours using only slight time-shifting with cheap thermal storage. b) 3x ratio of collector power to turbine power provides for 83% reliability of generation from solar thermal, as good as coal. c) Solar thermal costs can readily be made cost competitive with simply the efficiencies of scale from constructing 8 GW over the next 10 years. Read this engineering study. Assessment of Parabolic Trough and Power Tower Solar Technology Cost and Performance Forecasts - Sargent & Lundy LLC Consulting Group, Chicago, Illinois The author's arbitrary assigning of a maximum of 5% grid capacity to solar clearly needs independent technical backup documentation or must be declared simply a prejudice.
Third, establishing a proper open market for electricity using a VERY smart grid, IMEUC - Independent Market for Every Utility Customer - Preliminary Business Case and the other two articles on the topic at that site, can clearly allow a much greater penetration of predictably intermittent generating resources into a stable grid at very little added cost.
Fourth, the author incorrectly discounts the effects of rechargeable electric vehicles. These vehicles, if aggressively promoted to replace gasoline and diesel vehicles, can both contribute to mitigating peak petroleum AND to stabilizing a substituting renewable-powered grid.
Yes.
BAU is oil and fossil fuels. An economy that runs on wind, EVs, etc, even if's it's prosperous, is not BAU.
3x ratio of collector power to turbine power provides for 83% reliability of generation from solar thermal, as good as coal.
Len, do you happen to have a link for that?
The author's arbitrary assigning of a maximum of 5% grid capacity to solar
To be fair, that the NREL assumption, and I have assumed that until CSP demonstrates cost reductions is a reasonable, conservative one. I hope the Sargent & Lundy is rigorous - I'll have to take a look. They're a respected company. Have you looked through it carefully for reasonableness?
This from NREL - Parabolic Trough Thermal Energy Storage Technology. Several techniques and storage media evaluated, most effective is simply casting a large insulated block of high-temperature concrete with thermal transfer medium pipes through it.
The specific document I was quoting was the Desertec design proposal documents, which quote 83% reliability with 3x collector kw vs. turbine-generator kw. However, not able to come up with the link immediately. Will follow.
Regardless of whether the number is 70%+ or 83%, it is very simple to then propose bringing the plant up to approx. 100% reliability simply by providing a rarrely-used fossil or bio-fueled auxiliary burner for the thermal circuit. That issue is not a blocker anymore.
it is very simple to then propose bringing the plant up to approx. 100% reliability simply by providing a rarrely-used fossil or bio-fueled auxiliary burner for the thermal circuit.
True, but I would argue that it's much cheaper and more efficient to let the grid do the balancing. People who insist that renewable sources must handle their intermittency at the local site are just trying to create cost barriers for renewables1.
1Although, to be fair, some people who repeat this are unaware that it doesn't really make sense - in effect, they've been captured unawarely by someone else's talking point. Embarrassing, to be captured by a talking point. Actually, it sounds a bit like a plot from Dr Who...
I think thats almost always the case. In a case like solar thermal, there might be an economic case -we already have heat to electricity conversion infrastructure on site. So it should be evaluated cost benefitwise against an offsite alternative.
Another note about CSP with significant heat storage: The time that it runs out of heat can be predicted several hours ahead of time, so the grid operators can plan for it. But, also I don't think it covers the seasonal differences, you'd have to overbuild the collectors pretty significantly to get high winter capacity utilization.
I have no problem with the renewable plants not providing on site storage - as long as they are willing to accept the discounted market rate for non dispatchable electricity.
There may be other factors, like a carbon tax or something in favour of renewables, but from the grid operator point of view, they see capacity and controllability - sources with both get paid more.
So, for a wind or solar plant, the owner can decide if the expense of storage is justified by the extra return created.
I like the idea of the evening storage for CSP - this is still not creating dispatchable power, but it is creating the ability to sell power when it is most valued, so it is a step forward.
For a wind turbine, it is hard to see what feasible on site options are available.
As a side note, leaving aside the CSP, it is better to have the storage at the customer sites, rather than the generator sites (EV's doing vehicle to grid are an example, even though they don;t yet exist). That way, the storage is charged during off peak times, when transmission loads are lowest, and released during peak, when transmission loads are highest, without adding to them. So it fattens the transmission load curve - storage at the generation site makes the peak and valleys greater.
I have no problem with the renewable plants not providing on site storage - as long as they are willing to accept the discounted market rate for non dispatchable electricity.
Is there such a thing as a discounted market rate for non dispatchable electricity?
In the US this problem is solved by separating kWhs from peak power capability: generators are paid for kWhs as they generate them, and they're paid separately for providing firm capacity for peak periods.
Sure there is - when you remove the mandate for wind and solar to be first in the loading order.
In a "free" electricity market, the utilities buy the power from the generators. Let's assume there is some kind of carbon tax or equivalent in place, that gives a price advantage to renewables and nukes. After that, then what? If there is no wind, some other generators are running higher. The wind starts up, but why should the utilities switch their spot market buying from X to wind? Well, they would if there was enough of a price difference to make it worthwhile.
It is the equivalent of airlines offering deals on last minute seats - to get someone to switch from whatever else they were doing and buy the seat to fly somewhere, they need to offer a really good deal.
Right now wind/solar are mandated, that they must be used first if they are there. It is equivalent to the ethanol mandate. To then have carbon tax/credit is redundant, as you are making the utilities pay more for something they already have to do.
Instead, have the carbon tax, and beyond that, a kW is a kW, and a dispatchable kW is inherently more valued than a non dispatchable one.
the mandate for wind and solar to be first in the loading order.
Is there a mandate in N. America? I know that in Germany, at least, there was a problem fairly recently with a requirement to take all wind/solar. But I'm not familiar with anything that affects the bidding order.
The wind starts up, but why should the utilities switch their spot market buying from X to wind?
because wind can always underbid them, with no marginal costs.
to get someone to switch from whatever else they were doing and buy the seat to fly somewhere, they need to offer a really good deal.
I have the impression that the price difference can be small.
a dispatchable kW is inherently more valued than a non dispatchable one.
I think that in a spot market, simple price rules. Of course, the question of how to deal with failure to deliver is another question - I'm not sure what the latest resolution of that is.
because wind can always underbid them, with no marginal costs.
Exactly, so without a mandate that the utilities must buy, there is your different price.
There is an effective mandate, because of the RFS that most states now have. Some places have capped allowable wind power %, to avoid the problem of having too much wind creating problems for others to deal with (the Alberta system operator has taken this approach).
Where you are paying wind a feed in tariff, then it gets worse, as you are paying them regardless of the selling price (-demand) for the product.
I have the impression that the price difference can be small.
Yes, but only because you get a negative bidding war between the sources, so you end up with a price some way below where you started when the wind wasn't blowing. This makes the power cheaper, of course, but only if the wind operator is not being subsidised to produce it.
think that in a spot market, simple price rules
Quite so - and for wind, the spot market is really all the can participate in, unless they can secure balancing load to back up commitments in the forward market.
Of course, the question of how to deal with failure to deliver is another question - I'm not sure what the latest resolution of that is.
That is why some grid operators are limiting wind % - so that they always have something else to call on when wind does fail to deliver. If there is nothing to fill the gap, thee are consequences for the grid operator, and the customers.
In Alberta, all the wind is in the south, the demand (Calgary) in the middle, the hydro (about equal to wind) in the west, and the coal generation (majority of generation) in the north. The load balancing problems with wind have led to a cap on wind capacity. There is no more hydro to be built, and so the utility has had to build new GT capacity in Calgary to balance the wind. Wind can increase when they build new transmission from the south, which the wind folks don't want to pay for, of course...
Some places have capped allowable wind power %, to avoid the problem of having too much wind creating problems for others to deal with (the Alberta system operator has taken this approach).
Who are the others? Isn't the Alberta Sysop the one who has to deal with it?
for wind, the spot market is really all the can participate in, unless they can secure balancing load to back up commitments in the forward market.
What % of power goes through spot markets? I had the impression that it was well below 50%. I would think that much wind power would simply be used by an integrated utility/generator, like the TVA or BPA.
The load balancing problems with wind have led to a cap on wind capacity.
I'd be curious to read an analysis. I suspect the sysop didn't try anything very creative, like expanding DSM.
only if the wind operator is not being subsidised to produce it.
Which brings us back to the basic policy question of AGW. Wind and solar are really only needed in N. America to deal with AGW. OTOH, if we think CO2, as well as mercury, fly ash, nitric oxides, etc, etc, are real problems which need to be monetized and internalized, then we need to tax FF or subsidize low-pollution power sources. Given the political difficulty of taxing FF, it's seems pretty clear that subsidies are necessary.
Who are the others? Isn't the Alberta Sysop the one who has to deal with it?
I think Bonneville has had to put a slowdown on wind. The Sysop is the referee that has to ensure grid reliability - it cannot command stuff to be built (e.g transmission, GT etc) it can only work with what exists. In the case of Alberta, they had to say no more wind until someone builds more transmission, and there is more balancing generation available.
What % of power goes through spot markets? I had the impression that it was well below 50%. I would think that much wind power would simply be used by an integrated utility/generator, like the TVA or BPA.
Depends on the market! In BC, there is no spot market, only the export market. In the east, more is done through medium term contracts, but Ca is mostly spot (I think). BPA is saying they don;t have any more balancing generation, and they are normally exporting to Ca. Keep in mind, when they have excess wind, so does everyone else except Ca.
Also, getting excess wind from Alberta to BPA is a long way, with limited interconnections.
I suspect the sysop didn't try anything very creative, like expanding DSM.
In Alberta, that is not the sysop's mandate - that is up to the retail utilities. So what did Enmax, the Calgary utility do? They built a bunch of SCGT at their Calgary hub. Easier and faster than DSM (though not necessarily better) .
Basically, the view in Alberta is that wind has used up the available transmission capacity, and if they want more, they can build it. I see no problem with that approach - certainly don;t see why anyone else should pay for it (there are no other significant energy sources in the south)
Update - the cap was actually lifted a few years ago, but there is still a transmission constraint, so there is an effective cap.
Study on wind integration here;
http://www.aeso.ca/downloads/Wind_Integration_Recommendation_Paper.pdf
They are looking at options including HVDC to service the wind area - big $$!
Which brings us back to the basic policy question of AGW. Wind and solar are really only needed in N. America to deal with AGW. OTOH, if we think CO2, as well as mercury, fly ash, nitric oxides, etc, etc, are real problems which need to be monetized and internalized, then we need to tax FF or subsidize low-pollution power sources. Given the political difficulty of taxing FF, it's seems pretty clear that subsidies are necessary.
Well, our views differ on this point, but, if we are going to subsidise it, what then is the best way to do so? A high FIT is the worst way, as you pay lots for power even in the middle of the night when it is not needed. I would only pay a subsidy for peak hour power, though implementing even that would have its challenges.
In the states, development of wind and solar are almost entirely driven by mandates and incentives, even where wind and solar resources are excellent, like California.
Which makes sense, as the external costs of pollution, occupational health, mountain top removal etc, etc are not figured in.
The US has plenty of cheap, dirty coal. If it doesn't care about external costs, heck, it doesn't need wind and solar (or anything else, like NG) for quite a while. If no external costs
are included, nothing can compete with dirty coal. And, not much can compete with coal and NG: not wind, solar or nuclear.
OTOH, if we start figuring in those costs, wind in particular gets cost-effective mighty fast, and solar is following wind's cost-reduction path, though it's several years behind. Nuclear will work as well.
In my case when I use the word 'BAU' I mean it as a reference to the current globally accepted economic paradigm that ignores resource limits and insists that there needs to be a continuation of growth despite this reality. I don't argue for collapse of any sort though given the unustainability of the current system I would not be surprised if it occurred.
As for suggesting that anyone who uses the end of BAU as a necessary return back to the days of 'Whale-Oil Lighting' is at best a strawman argument and at worst an insult.
What I think is about to happen in the next decade or so is a profound paradigm shift away from the way we have organized our economies in the western world over the last 100 or so years simply because that system has obviously failed. I think that change was coming regardless of Peak Oil though it certainly is an agent that has already brought the system past a tipping point.
Granted any transition of the magnitude that we are about to experience is certainly fraught with danger and uncertainty.
I think he makes a good point, however, just in saying that the term 'BAU' has become such a constant refrain in various discussions, that it has become extremely vague and could be embodying any number of assumptions.
As with the arguments that seek to rebuff 'renewables' without clarifying the significant differences between biofuels, geothermal, big or little hydro, solar heat, for example.. using such terms as collectively as they have been forces many of these discussions to become overly broad and unhelpful.
"Second, I can make a very strong case that the author's base assumptions are factually flawed. Solar thermal technology is a) readily amenable to generating at peak demand hours using only slight time-shifting with cheap thermal storage."
Only if you leave out replacing heating with fossil fuels with electricity or some kind of solar thermal district storage/heating, and a future involving charging EVs while we sleep. Obviously the demand for heat, which uses even more energy than refrigerated A/C, is highest in the early morning.
As far as solar troughs, there's plenty of data to be had there, as I commented earlier. SEGS doesn't put out a lot of energy relative to its footprint.
As far as a smart grid and storage solving the problems of the intermittency of wind and solar, a smart grid could easier help efficiently use the consistent and predictable output of nuclear power. Thermal storage also applies to refrigeration. My son's new high school in Ca uses ice made at night for cooling during the day.
Only if you leave out replacing heating with fossil fuels with electricity ...Obviously the demand for heat, which uses even more energy than refrigerated A/C, is highest in the early morning.
IIRC, surprisingly enough, in countries which use resistance heat for residential space heating, we find that the peak load is in the evening, somewhat later than the solar-driven A/C late afternoon peak. Apparently people come home from work and raise the thermostat setting.
This is an interesting example of price-driven behavior: consumers turn down the thermostat during the work day and during sleep to save money. It strongly suggests that if we incentivize heating behavior with time-of-day price signals, that we can move demand wherever we need to in the day.
a future involving charging EVs while we sleep.
The nice thing about EVs is they, in the longterm, can be charged whenever we as a society need them to be. Personal vehicles are only in motion 1 hour per day: the rest of the time, they can be connected to the grid.
Also, keep in mind that currently there's substantial industrial/commercial demand that has been shifted to the night to take advantage of cheap rates. Your son's new high school in Ca is a great example. All of that demand could be moved back to the daytime, if solar started to dominate electrical generation. That would be bit more efficient for those consumers: it would save the expense of the thermal storage for your son's high school, for instance.
Ultimately, I agree: whether we use wind, solar or nuclear, we'll make it work.
Apparently people come home from work and raise the thermostat setting.
Some do, and others (and more all the time) have the heat on programmable thermostats with night setbacks. You do not need to heat the lounge room and kitchen while you are sleeping. Even in the morning for a typical family, everyone is out of the house within an hour or two of getting up, so you don;t need to heat it that much during the day, when you get some sunshine too. The 7 day thermostats are great for that sort of thing.
Evening is different, everyone is coming and going, doors opening more, plus the lighting and cooking load peaks in early evening, and you are likely heating most of the rooms in the house at the same time - the lounge and kitchen where you are, and the bedrooms so they are comfortable when you go to bed. I used to be able to observe all this from the hotel/condo load management software we had at my old ski resort - family patterns were utterly predictable, but "independents" without kids were quite variable.
IT does point to the viability of short term (12hr) thermal storage for houses - that is why electric heat countries like New Zealand have used sand filled night store heaters for decades. A modern air source heat pump is more efficient for energy use, but is not so good for energy storage (needs lots of mass as temperature differential is not as great).
It all depends whether you need to move kW or use less kWh.
"IIRC, surprisingly enough, in countries which use resistance heat for residential space heating, we find that the peak load is in the evening,"
In the TVA region in the US, where some of the lowest electricity prices are, resistance heating is relatively popular. I haven't done a lot of research on peak load time throughout the US and the world, but I did notice an Alabama utility reporting that their record demand occurred on an early winter morning. They attributed it to the fact that heat pumps are popular in Alabama. Had it been resistance heating, the effect would have been the same, only more so.
Anti nuclear power activists often cite the writings of a popular French anti nuclear power activist. I've read his work, and it's more a criticism of France's waste of that energy, than a direct criticism of nuclear power. I'm pro nuclear power, but I do recognize that an advantage of small scale renewables, is they make people acutely aware of their own energy consumption. I see simple and inexpensive tech as a solution.
My son's new high school in Ca is equipped with motion sensors throughout, and if you leave a room, the lights go out. It's not new or expensive tech, and it's just one example of a solution to wasting of energy. I like my freedom, but I don't have a problem with energy saving features being mandated into building codes, appliances, and commercial & industrial equipment.
"The nice thing about EVs is they, in the longterm, can be charged whenever we as a society need them to be."
That remains to be seen. The new EVs have normal charge modes of about 8 hours at 240 (US) and 16 at 120. They can be fast charged, but that reduces the life expectancy of the batteries. At the real world ranges of EVs (Leaf/RAV4), for a 300 mile round trip, best case scenario would be it needing to be charged 3 times. Yes I know most folks trips aren't that far, I fall into that category, however most people do have frequent needs or desires to make longer trips.
BTW, the thermal storage equipment that is used at my son's school, although using cheaper rates, therefore being cheaper overall to run, is less efficient than more commonly used A/C equipment.
I haven't done a lot of research on peak load time throughout the US and the world, but I did notice an Alabama utility reporting that their record demand occurred on an early winter morning.
That's unusual. In places like Florida and the UK, where electric heat are common, the peak is in early evening.
I see simple and inexpensive tech as a solution....I don't have a problem with energy saving features being mandated
I agree. It's puzzling that these things aren't used more.
EVs is they, in the longterm, can be charged whenever we as a society need them to be." That remains to be seen. The new EVs have normal charge modes of about 8 hours at 240 (US) and 16 at 120.
I simply meant that price signals can move most charging to whatever time is needed. 80% of travel is in short segments during the day, and the average daily travel is only about 35 miles, which will only require about 8 hours of charging at 120V and 4 hours at 240.
Again, I suspect that pure EVs will be a relatively small niche in N. America for quite some time. Those who love the idea of an EV will buy one, and people like that will be willing to subscribe to things like DSM and V2G for the same reason. Everyone else will get an EREV or PHEV.
the thermal storage equipment...is less efficient
That's what I would expect - creating ice and storing it will have a an energy cost. That's what I meant when I said that moving that A/C load back to the daytime would be more efficient.
DSM is very powerful, and will provide quite a bit of flexibility: industrial/commercial "demand charges" are a very, very primitive form of DSM, and yet they have quite an impact on I/C energy consumption patterns.
That's unusual. In places like Florida and the UK, where electric heat are common, the peak is in early evening.
What you are seeing is the variable effect of temperature (i.e. a cold snap) being greater than the stable consumption patters of people (stuff in the evening). When it gets really cold, the heat will indeed be on in the early morning. Heat pumps are less efficient (but still better than resistance) in the cold weather, so their is a small multiplier effect.
For "normal" winter weather, which is actually quite mild, an early morning peak suggests that the heat is being used inefficiently or the buildings are poorly insulated./managed.
That's what I would expect - creating ice and storing it will have a an energy cost. That's what I meant when I said that moving that A/C load back to the daytime would be more efficient.
Not always. In areas with hot days and cool nights (dry air areas) the the temp differential from room to ambient in day can be greater than from ice to ambient at night. You have shifted a significant load from the peak period, which relives transmission constraints etc. Most of the benefits got to the utility, not the end suer. The peak pricing is meant to be just enough to make customers do these projects.
Industrial/commercial "demand charges" are a very, very primitive form of DSM, and yet they have quite an impact on I/C energy consumption patterns.
I don;t think they are primitive at all - the peak power determines the size of the equipment needed so this is an appropriate pricing mechanism. Even if all your load is off peak, but is huge, the utility needs huge equipment to service you - demand charging captures that. Demand charges are less when the customer supplies their own transformation and other equipment.
Not always. In areas with hot days and cool nights (dry air areas) the the temp differential from room to ambient in day can be greater than from ice to ambient at night.
True, but it would be less efficient most of the time. Not to mention the capital and maintenance costs of the equipment - I was involved with one large commercial building that had such an ice storage system - the operating engineers dumped it the first chance they got.
You have shifted a significant load from the peak period, which relives transmission constraints etc.
True. But, falling peak generation costs would be likely to reduce the night/day differential sufficiently to make major I/C demand shifting no longer economic (steel mills that operate at night, etc); solar that displaced NG peak production wouldn't increase peak transmission needs; and a big decline in costs for local PV systems would actually reduce transmission and distribution costs.
This conversation started with a question about the reasonableness of an assumption that solar would only provide 5% of total kWhs. While I thought that assumption was reasonable in the original context, I don't think it should be considered a ceiling.
I don;t think they are primitive at all - the peak power determines the size of the equipment needed so this is an appropriate pricing mechanism.
Sure, part of the purpose of a demand charge is to address the equipment to service the company load, but most transmission and distribution costs are related to the overall load, not the individual company load.
Demand charges represent a single point of demand, which many times is unrelated to the system peak. I've worked with a mass transit agency that has a peak during the morning rush hour for their electric trains (the system peak was in the afternoon) - they collaborated with other local governments to combine their load, and reduce their overall demand charges. Did that collaboration reduce costs for the utility? Not a bit - the demand charge was a bad price signal/incentive.
True, but it would be less efficient most of the time. Not to mention the capital and maintenance costs of the equipment - I was involved with one large commercial building that had such an ice storage system - the operating engineers dumped it the first chance they got.
Sounds like a system was used where it shouldn't have been. If it is using conventional ice equipment, it likely wont be effective. The newer ones are using an "ice brine" and appear to be much better. Still, there is a line below where they are not worth the trouble, now matter how sexy the idea is.
falling peak generation costs would be likely to reduce the night/day differential sufficiently to make major I/C demand shifting no longer economic (steel mills that operate at night, etc); solar that displaced NG peak production wouldn't increase peak transmission needs; and a big decline in costs for local PV systems would actually reduce transmission and distribution costs.
I'm not sure that there is much evidence that peak generation costs are falling - I'd say they are getting more expensive. Also, falling generation costs do nothing where the transmission is the constraint. Don;t hold your breath for a "big decline" in local PV costs.
I agree about solar, I don;t see what technical basis there is for 5% as a ceiling. Economics may limit it but that is a different issue.
they collaborated with other local governments to combine their load, and reduce their overall demand charges. Did that collaboration reduce costs for the utility? Not a bit - the demand charge was a bad price signal/incentive.
Sounds like an interesting project. But did they do any actual load shifting/reduction or was it just consolidating of "customers"?
Also, reducing demand once the equipment is already there does not reduce costs much - the demand charge is meant to avoid having to buy bigger equipment - your project probably achieved that.
Keep in mind if the "utility" is just a reseller, their main capital cost is their grid - commodity costs just flow through to the customers. So for the utility managing demand is managing the primary source of potential capital costs.
I'm not saying the demand charge is a perfect mechanism by any means, and should not be employed alone, but it does have its place and purpose.
On site solar may be a very good way to reduce that demand charge, and will almost certainly be more than 5% of the customers total - that is what matters more.
Sounds like a system was used where it shouldn't have been.
Actually, it was probably ok - the engineers weren't looking at the whole picture. I just meant that from their point of view, the system took more work - it just says that the maintenance cost/work is significant, and needs to be taken into account.
I'm not sure that there is much evidence that peak generation costs are falling - I'd say they are getting more expensive....Don;t hold your breath for a "big decline" in local PV costs.
This was in the context of a theoretical 35%+ renewable grid, which won't happen for decades. By that point, we can expect large drops in CSP & PV costs.
vBut did they do any actual load shifting/reduction or was it just consolidating of "customers"?
They only consolidated metering/reporting.
Keep in mind if the "utility" is just a reseller
Yes, that's part of the problem. The price model should relate to the whole system, not just the front-end.
I'm not saying the demand charge is a perfect mechanism by any means, and should not be employed alone, but it does have its place and purpose.
I think we're agreed - demand charges are better than nothing, but they're a very primitive and clumsy form of daytime pricing - time of day pricing would be much better, and that's rolling out (slowly) to I/C customers as well as residential.
I just meant that from their point of view, the system took more work - it just says that the maintenance cost/work is significant, and needs to be taken into account.
This is a common problem - the main guys have more work to do and don;t get paid more - so sometimes they try to defeat the system, just to get it removed.
They only consolidated metering/reporting.
So the only cost benefit to the utility is a reduction in customer service costs, which is something, but is mot saving energy (directly)
The price model should relate to the whole system, not just the front-end.
Quite so, the utility needs is revenues to be "de-coupled" from the amount of energy used, since it is really a service provider. I think the NG utilities have done a better job of this.
I think we're agreed - demand charges are better than nothing, but they're a very primitive and clumsy form of daytime pricing - time of day pricing would be much better, and that's rolling out (slowly) to I/C customers as well as residential.
Well, almost. I don't think it is primitive and clumsy, but I do think it is not enough. Time of day kWh charging is great, but a customer that creates huge demand spikes, and doesn't use a lot of kWh, is then getting subsidised by everyone else. This suggests time of day energy and demand charging is appropriate, and would be easy to implement.
Hi Nick,
It can vary. In Québec and New Brunswick where electric heat predominates, the peak is typically early morning. Outdoor temperatures are generally coldest at this time of day and setback thermostats are coming out of their night time slumber. In addition, some 80 to 90 per cent of all homes in these two provinces are fitted with electric water heaters and most are energized during those critical morning hours as folks enjoy their hot showers.
A Hydro-Québec press release dated January 16, 2009 tells us that their highest peak recorded to date occurred between the hours of 07h00 and 08h00 (see: www.hydroquebec.com/4d_includes/la_une/PcFR2009-008.htm), and NB Power's historical peak occurred on January 16th, 2004 between 08h00 and 09h00 (see: www.nbpower.com/html/en/about/media/media_release/pdfs/peakdemandjan1604...).
For Nova Scotia Power, our winter peaks generally fall between 19h00 and 20h00, more in keeping with the other jurisdictions you mention (see: http://oasis.nspower.ca/system_report/hourly_total_net_Nova_Scotia/Hourl...)
BTW, in these parts, utilities are winter peaking and winter is when our wind resources are at their greatest, so that meshes rather nicely. Unfortunately, a large portion of this energy is generated overnight when electricity demand is relatively low. The City of Summerside, PEI thinks it has the answer:
http://www.cbc.ca/canada/prince-edward-island/story/2010/12/09/pei-summe...
Cheers,
Paul
Paul,
That PEI link is interesting, but at $2k per nightstore heater, someone is profiteering.
I New Zealand, where everyone uses them, they are $500-800 (then us about 80% as the exchange rate).
http://www.lvmartin.co.nz/public/products/Level3Drilldown.aspx?level2cod...
(scroll 3/4 down the page to get to nightstore heaters)
Sounds like a business opportunity for someone....
They would possibly be the cheapest way to store wind energy.
Hi Paul,
I believe there's only one supplier of ETS equipment in the North American marketplace, Steffes, and although their products are considerably more expensive than those sold elsewhere, they're larger capacity models with more advanced controls.
See: http://www.steffes.com/off-peak-heating/room-units.html
BTW, Larry Hughes of Dalhousie University has written extensively on this topic, and the last link also references plug-in electric vehicles:
http://dclh.electricalandcomputerengineering.dal.ca/enen/2006/ERG200605.pdf
http://dclh.electricalandcomputerengineering.dal.ca/enen/2009/ERG200909.pdf
http://dclh.electricalandcomputerengineering.dal.ca/enen/2009/ERG200910.pdf
http://dclh.electricalandcomputerengineering.dal.ca/enen/2010/ERG201004.pdf
Cheers,
Paul
The first step will be identifying the current industrial processes that require 100% availability. My neighbor supervises the line producing glass bottles at the nearby large brewery -- 24/7 except for the week between Christmas and New Year's for maintenance because of the time required to heat things up or cool them off. At times they run only one or two shifts instead of three, but the raw glass is still kept molten continuously. I suspect that there are many "industrial" processes with the same problem because they are designed to be continuous -- I wonder about, for instance, water and sewage treatment. Even if converted to a batch mode, there are probably a lot of processes which require 48- or 72-hour guarantees.
The second, and potentially more difficult problem, is that of converting. At what point does a firm dare to replace their cheap continuous process with a more expensive batch process? Or to skip the 72-hour batch process and go to the even more expensive 24-hour batch? Convert too soon and you're broke because your competitors can offer lower prices. Convert too late and you're broke because intermittent power made your continuous process unworkable.
It's easy to find examples, from Pakistan to Kenya to Venezuela where randomly intermittent power availability has had fairly extreme consequences for the economy.
You raise a very good question here. I can speak to the water/sewage part of it. These systems are, of course, designed for continuous operation, though they have fairly consistent daily fluctuations. It is possible to time shift these cycles - with enough surge storage. However, the processes themselves may have to be modified. The main energy component is sewage treatment is aeration. Hold the raw sewage in your surge tank too long and it starts to turn septic(anaerobic) and then you have a treatment problem.
In effect, we are storing the "load", not the energy here, but just like energy storage, it has a cost. Many city plants do not have the land area to build half a day of storage. But, if there is space, and if the difference in peak/of peak power costs is great enough, the storage will be justified.
All water and sewage facilities are required to have backup generators, and to be able to function at least at 50% capacity under backup. (For sewage treatment this means 100% of the flow, just 50% of aeration and thus lower quality treatment, in a long outage).
So they all have these diesel backups that can be run, if they are set up for grid tie (most are set up for stand alone, of course, so control equipment changes are needed).
Diesel fired electricity costs about 30c/kWh, so that gives you an idea of the peak/off peak differential required, if you are going to be doing much of this.
Part of a change from BAU (as "we" now know it) to a new BAU - the habit of taking potable water and making it non-potable via adding a high grade compost material.
Suggestions have been made (even by me till I thought about it a bit more) to use solar powered biological systems (instead of using external energy like "normal" wastewater treatment) like algae to make bio-oil. The "rub" becomes thus: Cities are the source of wasteflow for an algae system, yet to use solar power you need land and a cover to limit cross contamination/keep it warm during the fall/winter/spring in FrostBite Falls.
A system like what Magic Soil or Jerry's Jetcomposters (produce airflow in a compost system - used to pre-breakdown for vermipost) or scale up a naturemill (this provides airation, mixing and heat to kill off the human pathogens) are changes to BAU. And each of these systems (on paper) can withstand changes in the energy used to process.
It shouldn't have to be an all or nothing thing. If they have a MOL (Minimum Operating Level) substantially lower than their normal demand, the difference should be available for flexing.
these are all great questions that would benefit from guest posts/expertise, if there is any. In the very long run (or intermediate, or possibly short) we are going towards 100% renewables - what the intermittency (ignoring cost for moment) implies for our current industrial situation is a pressing area in need of analysis.
A friend told me that if 'clean rooms' for semiconductor wafer manufacture have power outage for ~a day or so, basically the entire building is contaminated and needs to be rebuilt not just cleaned. So intermittence is a problem for that industry - at least.
Wow! I knew any product in process would be toast, and maybe the machines would need costly and timeconsuming retuning, but I hadn't heard that. Of course any facility with a high degree of sensitivity has built its own uninterruptable power supply. The outfit I work at (software development) has its own UPS equipment, I expect it is an expensive luxury, but the horrors of the California Energy crisis (was it 2000, or 2001), made it seem necessary.
A think any industrial/commercial facility has its own MOL, beyond which unreasonable damage is incurred. It is that gap between MOL, and typical operating power levels that we can legitimately play with.
No business that depends on continuous electrical power relies upon an electrical utility to supply it. Fuel tanks, generators, batteries, and switchgear to carry the critical loads are always used, even when you also go to the expense of installing separated feeds from different substations.
This article provides a high level description of the 12,500 kVA UPS supply that STMicro has at their Phoenix fab. Capable of responding to an interruption in the commercial power in 1-4 milliseconds. It would be interesting to know how big their backup generators are, and how much diesel or natural gas they keep on hand. My state has a secured facility where state agencies operate their mission-critical backup systems. When I toured it (part of preparing to explain to one of the legislature's committees why the state spent that much money), they had two independent 1.0 MW generators, two 10,000 gallon diesel tanks, and enough UPS capacity to keep things going while the generators got started. I'm sure the fab has much larger equipment.
The ability to maintain (or not) today's integrated circuit technology will be critical in determining how much must be "undone" in scaling back. I did technology analysis for 25 years, and am still amazed by how ubiquitous large-scale integrated circuits have become. One of the examples I use now is the new transmission in GMC's Sierra hybrid. 70% of all the staff hours that went into the design of the transmission were used to write and debug the software that runs on the embedded processors. Almost no one designs control "circuitry" any more; it's all software, processors and sensors.
How many staff hours does it take to design the manual gearbox for the Sierra - I'll bet it is a lot less.
Sounds like a hell of a lot of work, to design an artificial brain to do what the drivers brain can do!
Yeah, but people prefer to hand off brain activity to a machine eliminating the need to think. Incidentally even the local Costco and Home Depot have large fuel storage tanks (20' tall and 10' diameter at a guess) that would imply backup capability, got to keep the cash registers running..
NAOM
No question that (most) people prefer to do that- we use more resources to design it, more to build, and they are typically 5% less fuel efficient than manuals - that is a *very* high price to pay for the convenience of not changing gears, and 90% of car buyers pay it!
In the case of Costco, those backups are first and foremost to keep the refrigeration units going. But, if you have to have that, might as well upsize the system to run the store...
For the Sierra hybrid. It has to connect four different things: the ICE, two electric motors, and the wheels. Some of which can drive the others, some of which can be driven by the others (eg, wheels drive one of the electric motors for regenerative braking), in different combinations and directions and speeds under various conditions. There's not really any choice except an automatic.
I did miss that little detail about hybrid! No wonder it was so complex
There's not really any choice except an automatic.
Sure there is, you can have a manual hybrid, like the Honda CRZ:
http://www.honda.ca/crz#/crz/specs
But, the cont variable transmission clearly wins the fuel economy race, especially in city driving, so I concede that computer can beat the brain.
Though the driver reviews say the manual is much more fun to drive - "fun" = "fuel consumption"!
In the very long run (or intermediate, or possibly short) we are going towards 100% renewables
Nonsense on time scales less than century+ (say 150+ years). In which case, enough time for industrial processes to change & relocate (example - old IC fab facilities had less strict clean standards and wider wires & transistors on the chips. Write more efficient code for less powerful ICs and get same functionality. Or build IC fab next to Niagara Falls).
Nuclear power plants will remain for MANY decades.
Pumped storage does an excellent job of turning intermittent power into reliable power on as weekly basis (but nor for seasonal changes). And they last multi-centuries.
We will continue to mine and burn some coal (hopefully less) for a 100+ years if we need to. And some NG as well. So no 100% renewables + nuke even.
Geothermal and biomass provide baseload and dispatchable power respectively.
100% renewables is a good aspirational goal, but necessity will not force it on us baring complete social collapse.
Enough posting, I do not wish to be drawn back in. I should not try and stop the New TOD from evolving. "Kinder & Gentler" means no meatgrinder and accepting that everyone's POV is valid. Even when I think it is nonsense.
Alan
Hey Alan.
Some general thoughts and questions.
If thermal storage for concentrated solar is viable, why not consider the same for dispatchable coal? Add some significant thermal storage to allow the coal boiler to operate on a slowly shifting power level, and a more flexible turbine to load-follow?
Why not co-locate a CSP plant and a peaking gas boiler, thereby requiring only one turbine/generator and grid-tie investment, with much higher utilization? For a generation plant, what are the cost allocations for burner, boiler, turbine, generator, and grid interconnect? Is there an opportunity for multi-fuel co-gen?
Why not move high-power loads near the generation source, versus moving power to the loads? Aluminum smelters have done this historically, I believe. Even when an RE source falters, the feed grid could reverse without a lot of new investment.
Where is the stranded wind fertilizer initiative in all this? Surely there is SOME range of industrial processes which are dispatchable and could benefit from almost free peak production power and suffer little from varying shutdowns?
Hi Alan,
re: "Nuclear power plants will remain for MANY decades."
1) I'm very curious about what a graph would like like for a list of anticipated "end" dates (lifetime/de-commission) for each nuclear reactor in the US. So far, I've just found general information.
http://en.wikipedia.org/wiki/Economics_of_new_nuclear_power_plants
"At the end of a nuclear plant's lifetime (estimated at between 40 and 60 years)," and
"Since it may cost $300 million or more to shut down and decommission a plant, the NRC requires plant owners to set aside money when the plant is still operating to pay for the future shutdown costs.[31] In June 2009, the NRC published concerns that owners were not setting aside sufficient funds.[32]"
2) I'm also very curious about the intersection of waste disposal options, as per here:
"Currently, there is no plan for disposing of the waste and plants will be required to keep the waste on the plant premises indefinitely."
with the de-commissioning options as explained here:
"This entails either Dismantling, Safe Storage or Entombment."
It seems, at first glance, that limited the waste disposal options would, in turn, limit the choice for de-commissioning. (?)
re: "Enough posting, I do not wish to be drawn back in. I should not try and stop the New TOD from evolving. "Kinder & Gentler" means no meatgrinder and accepting that everyone's POV is valid. Even when I think it is nonsense."
Alan, I value your contribution.
If one cannot question POVs, then what is the point of having a discussion? None that I see.
What is going on and what is the problem?
There's a language for disagreement (isn't there?) -
"I disagree."
"I have a different view."
"I think you may have overlooked: X, Y, Z."
Doesn't this work? Or, what are you talking about?
Look at Table 3 on http://www.eia.doe.gov/cneaf/nuclear/page/operation/statoperation.html
Also http://www.nrc.gov/reactors/operating/licensing/renewal/applications.htm...
The question of which industrial processes (and service based "industries" too) are flexible vs. those that require 24 hour access to energy is a very important one. Also important is "at what cost?" and "when?" as pointed out by McCain. This will be focused on in future research at IIER. I am hopeful that others will be studying the issue too. If anyone is working on this currently or plans to, please contact me at balogh [at] iier [dot] us.
Nate, I am sure the bio-tech industry (for better or worse) is similar to semiconductor manufacture. Though I imagine the effect would be more expensive products (as redundancy efforts increase in price) rather than a failure of this magnitude.
RE: Industries that (currently) require 24/7 power: .. a big part of that enquiry MUST be to ask 'Which end must change.. The energy supply or the design of that process?' Since most of these systems were built in a world with unquestioned 24/7 access to energy, they could allow design parameters to be developed with that assumption, and now we get told it is simply an unbending obligation to continue in the same mold. It isn't.
As with the example of the Glass Company, we have for decades now abandoned the fine art of using a glass bottle more than once, thinking somehow that we don't have the ability to wash enough of the cooties out of a used bottle to dare put our lips on it again. Washing bottles can surely be done with far less energy, and with intermittent energy as well.
There are many layers of assumptions that have to be challenged to meet such questions, a great many of them (in Bio- and Med-tech as well) coming down to the supposed requirement for GREAT volumes of disposable materials, and the energy they 'demanded' in being created and constantly re-stocked.
"24/7" .. it's great for sales! > which should indicate that the Inverse of that can then be 'Optional Power Demand is great for Savings', as you can start finding ways to buy and in some cases to store power yourself when it's cheapest.
Nonsense. Your "friend" is mis-informed, pulling your leg, ... .
A quick web search of: cleanroom power outage
turns up links suck as:
http://code210.gsfc.nasa.gov/ETIS/contamination/CROutage.pdf
which says something like:
"3.3 Once power has been restored to the facility in question, the
contamination control technician will wait 5 to 10 minutes before
entering the facility. (This will allow enough time for the room to
purge itself of particulate matter.)
"
It then goes on to describe testing, and re-certification.
Accidents happen in cleanrooms on occasion: filter changes go awry, vacuum cleaners pop open, people bring in dirty items, people spill things, clothing gets disheveled, etc. Testing, cleaning and re-certification is old hat. Every cleanroom has lost power and lived to tell about it. Some work in progress may be lost, but often critical machines have their own UPS, and as noted, in some cases much/all of a cleanroom is on a giant UPS.
The cleanroom itself is very simple:
http://en.wikipedia.org/wiki/Cleanroom
Often they'll have automatic dampers that close when the fans shut off to isolate the room.
And THINK - if being clean is so fragile, how did they build the room that clean to begin with? (hint: they didn't) They do use special modular panels and techniques to cut down on construction debris (and to make it easier to clean), but then some people go thru with special tools/vacs/... and clean everything. And re-clean on a planned and as-needed basis. Some things robots just can't do right now.
For the homeowner functions like water heating, air conditioning, refrigeration, dehumidification can be cut off for short periods of time without ill effects.
I have to wonder if businesses would benefit from an investment in large battery banks, a facility-wide UPS, if you will. Properly incentivised (TOU, FITs, etc.) it could work out for businesses who invest in large storage systems. Large, relatively inexpensive lead acid batteries are already being used for many applications and are fairly long lived if well maintained. Highly recyclable, when all of those ICE cars become obsolete there should be plenty of lead to be had.
When I picked up my PV batteries, there were several megawatts of forklift batteries awaiting shipment, this in a fairly small plant. The shift manager I spoke to said that their primary energy source at the plant is hydro-electric purchased from ALCOA's system, supplemented with NG.
GE Introduces Durathon™ Battery for Utilities
Cool link; lead (npi) to this:
"..a quantum leap forward in energy storage"
Spec sheet here:
http://www.geenergystorage.com/documents/utilities-specsheet.pdf
Interesting stuff. With a nominal voltage of say 500 volts, 32Ah and 80% doD, you have 12.8kWh, and 15kg/kWh - that is not much more than Li-ion batteries, and much better cycle life. Possible battery for an EV pickup or high floor van/wagon?
For utility battery storage, it seems to be go big or go home.
Have a look at this one, from Fairbanks, Alaska, world's largest, with a peak capacity of 40MW, and storage of 6.5MWh;
http://www05.abb.com/global/scot/scot232.nsf/veritydisplay/faf8b33a47f7ef21c1256d94002a24a7/$file/prs%20bess%20gvea_rev1.pdf
Comparing to an off gridder's house system this is a supertanker compared to a canoe!
If you divide rated power, by rated capacity, it can buffer for 9 and 3/4 minutes. This is clearly designed to cover short term power mismatches, it is not suitable for smoothing out daily variations from say solar. But, it might provide several minutes of bridge power to enable something else to be brought online.
Actually, it could easily be used for smoothing out daily solar variations - the batteries will last much longer and have higher round trip efficiency doing 2-3hr discharge than 15 minutes.
Of course, it is probably not economic to do so, but that's the whole problem that solar faces.
Solar has major variations with season and weather phenomena as well.
Paul,
Hav you seen any pricing info? A press release seems to show low costs: a labor cost of about $20 per kWh (350 jobs x $50k/job divided by 900,000 kWhs per year)!
" General Electric on Tuesday committed $100 million to open a factory in upstate New York to manufacture batteries for hybrid locomotives and other industries such as power grid storage.
CEO Jeffrey Immelt dedicated the facility at a press conference at GE's Niskayuna, New York research and development facility along with New York governor David Paterson and other politicians.
GE has been testing sodium-metal chloride batteries for heavy-duty industrial applications, such as hybrid locomotives and trucking equipment in mining. The technology can also be used for back-up power in data centers, plug-in electric vehicles, and to smooth electricity flow across the grid, GE executives said during the press conference.
GE has already invested $150 million in developing sodium battery technology, which it says can store a large amount of energy in a relatively small space. Because it uses relatively common materials--sodium and nickel--the cost is competitive with other battery technologies, said Mark Little, director of GE Global Research.
"It's very sophisticated, very high-end manufacturing technology with very simple materials, giving you low cost," Little said.
In the next month, GE expects to pick a site for the factory, which will employ about 350 manufacturing jobs in the upstate area. The plan is to break ground this year and be producing in 2011. The factory will be able to produce 10 million cells, the equivalent of 900 megawatt-hours worth of storage, Immelt said. "
http://news.cnet.com/8301-11128_3-10238485-54.html
I have no idea on pricing - I knew they were developing this, but this is the first I've read of it going into production.
GE is also working on an all electric bus, that uses both this battery and A123 Systems lithium, to optimise power and storage. Personally, I'm not convinced that a continuous duty bus is a good application for all electric - seems a better one for hybrid, unless you can incorporate charging at each end or along the route.
Most liquid storage battery systems have independent cost components for the charger/generator component(s) and the storage components. Such is the case for liquid flow cells, and I believe for GE's sodium-sulphur and sodium-halide batteries, though of course a marketed battery comes with some energy to power trade-offs designed in for the application of choice.
Using a high-power/short-duration battery for a lower-power/longer-term application is probably possible (the opposite is not necessarily true), it will not necessarily be cost-effective compared to a solution with a better-targeted trade-off point.
Note that any hot-liquid storage approach will have volume (energy) that scales by the cube but surface area (nominal heat loss) that scales by the square, so it would appear that larger storage would be a cost-effective consideration. 300C is pretty hot, but not terribly so at least.
I think, though, that if mass energy storage is desired that NH3 might be a reasonable choice -- given the phase options and energy density, could it be stored like nat gas in salt domes? It could be shipped and/or recovered for use as fertilizer or energy, as needed. An NH3 fuel cell could perhaps be 100% utilized -- either generating NH3 or generating power -- as needs dictate. Anytime local storage became saturated, load up the overage on Alan's electric trains or into a pipeline and take it to NYC for power or the breadbasket for fertilizer use.
Such is the case for liquid flow cells, and I believe for GE's sodium-sulphur and sodium-halide
Have you seen any good discussions of this? GE's specs made it sound like a conventional one-piece battery.
if mass energy storage is desired that NH3 might be a reasonable choice
Have you seen any cost analysis of this?
GE's original interest in these batteries was for its hybrid locomotives.
http://www.getransportation.com/rail/rail-products/locomotives/hybrid-lo...
However, they are now interested in uninterruptible power supply and utility applications as well, since the plant in upstate NY will have capacity beyond what is needed for locomotives.
One technology that works and doesn't get much mention is things like the Beacon Power and its vacuum packed, made with magnetic bearings flywheels.
Possible battery for an EV pickup or high floor van/wagon?
It takes 14 hours to warm up to operating temperature!!
Right, so you plug it in, every night, to keep it warm. Is there a problem with plugging in an EV at night, especially a commercial one?
Not for many/most commercial fleet EVs. A requirement for plugging in when not in use, though, is a big problem for personal vehicles. That will narrow the market considerably.
Key questions: how much power is needed to maintain temperature, and how quickly does it fall below critical operating temperature? Could a vehicle with this battery be left unplugged for 9 hours during a work day?
Key questions: how much power is needed to maintain temperature, and how quickly does it fall below critical operating temperature? Could a vehicle with this battery be left unplugged for 9 hours during a work day?
The power to maintain temp depends on the heat loss, and insulation , and that, as mentioned up thread is dependent on the size of the battery. Insulate it well enough, and the self discharge needed to maintain temperature will be acceptably low.
When I said EV battery for PU/Van, I was really thinking commercial applications - I wouldn't suggest this for a consumer application for just the reason you raise.
But, there are plenty of opportunities on commercial - train, bus, truck, boats, forklifts, farm tractors, airport vehicles, etc.
Leave the cars to the car companies!
The Wh/kg are poorer than the alternatives for automotive use. But the Wh/m^3 are good for large batteries in other applications where weight is not such a factor.
SODIUM-METAL HALIDE BATTERIES FOR STATIONARY APPLICATIONS
The Wh/kg are poorer than the alternatives for automotive use.
gravimetric energy density of 115 Wh/kg. That's pretty good.
Also 3k+ cycles, 91% efficiency. 0% self discharge. 20 year calendar life.
http://www.geenergystorage.com/documents/utilities-specsheet.pdf
Agreed. The large format and thermal nature are not good for cars, but for electric trucks and commercial vehicles of all flavours, I think this looks pretty good - it will be interesting to see how price competitive they are with Lithium.
There was a snafu in our reviewing software and this article hit the main page for a short time last week. There was one comment during that time, from AlanFromTheBigEasy, which I past below:
I gathered from some comments over the past few days that something (which I missed) must have come to a head and caused Alan to retreat from commenting on TOD, I for one hopes he reconsiders.
Best hopes for Alan's return.
http://www.theoildrum.com/node/7132
http://www.theoildrum.com/node/7132#comment-746918
So are a number of TOD's volunteers basically leaving? I have seen almost no comments from Gail recently; she seems to be devoting her energies to her blog Our Finite World:
http://ourfiniteworld.com/
Likewise from Heading Out, apparently his post on "The UK winter starts – challenges with salt, coal, and natural gas", apparently didn't make the cut here?
http://bittooth.blogspot.com/2010/12/uk-winter-starts-salt-coal-and-natu...
No -there are over 20 volunteers involved with TOD to various degrees - many have their own blogs.
Gail and Heading Out are on the 8 person Editorial Board here, though as we are having fewer articles here they won't be able to post all their material so they also have their own sites.
"The UK winter starts..." was not submitted to the editorial queue here.
Let's keep comments on Steves NREL wind post please
What's the economics of running an HVDC line from the Southwest to the eastern time zone? The solar peak at noon local time coincides with 3:00 EST (4:00 EDT) when the east coast is having their air conditioning peaking. Then when the southwest is peaking at 3:00 local time, the east coast is into the evening hours and their temperature is cooling and their business day is over. All the locally generated solar power can meet the local needs and additional electricity can then be sent the other way from east to west. Southern California needs more transmission capacity anyways.
Robert a Tucson
The study uses estimated transmission costs of $1600/MW-mile to build, and transmission losses at 1% per 100 miles during operation.
You might want to crunch the numbers on real world solar thermal. We have our models in well established plants like SEGS. At least that data is readily available online. Rough numbers on Solar Millennium in Blythe, Ca, is; 7000 acres and $6,000,000,000 gets 1/8 the output of the nearby San Onofre nuclear power plant, and it'll be intermittent output at that.
Not just intermittent, it will roughly follow demand during most of the day, so it'll either compete with load following combined cycle NG (~10+c/kWh) or single cycle peaker NG in the summer (30+c/kWh), not nuclear, at least not until we install a lot more than 1GW.
Blythe is modeled after SEGS, but unlike SEGS, the transfer fluid throughout will be molten salt, and it will do some storage to extend it's output after sundown. Better for the plant in the amount of money it can make from utilities, but it'll reduce the efficiency of the plant.
It'll never compete with nuclear in total resources used to generate a given amount of electricity. Yea, I'm pro nuclear power.
Nuclear will never compete with it in the amount of resources used to generate a given amount of peak capacity. ;) It's goofy to compare a peaking resource to a baseload resource. Compare baseload to baseload, load following to load following, and so on.
It is hard to tell from the graphs in the summary just how well solar and wind can integrate with hydro, but the text indicates that it would be a good match. I am curious what the thresshold would be for percent of wind/solar that could be integrated with hydro alone.
Previous posts on this subject have indicated that ramping coal plants up and down is not feasible at all. This study says it can be done. That is good news I guess.
Smart meters and smart appliances that can just be automatically shut down in periods of low electrical production would be a promising approach, although it would involve too much big brother for the typical citizen to tolerate.
On the surface (pardon the pun) solar/wind and hydro seem like a good match, but hydro is not completely controllable. There are times of the year when the dams have to spill, so they are generating regardless, and other times, like a drought, when they have to reduce operations. Also, the lower the water level, they less you get out of each drop. So hydro is good, but not perfect.
They seem to come to 20% wind is Ok, challenges after that.
There are some interesting comments on this from the Bonneville Power Authority here;
http://www.bpa.gov/corporate/WindPower/docs/2010-01-19_WIND-MainzerPrese...
Smart meters and smart appliances that can just be automatically shut down in periods of low electrical production would be a promising approach, although it would involve too much big brother for the typical citizen to tolerate.
Pushback comes in the forms of:
This is part of Agenda 21
You'll lose your 24X7 convenience
The privacy of what you opt/how you consume
Others will have control over you (err didn't you agree to that anyway when you accepted their power lines?)
The %age of the population who care about Agenda 21 is small.
The authors conclude that maintaining enough spinning reserves[iv] to deal with infrequent extreme changes in wind and solar output relative to demand is not cost effective, and that demand response programs (load management) should instead be incorporated. However, the authors do not delve more deeply into this issue, nor propose which businesses or loads would be available to be curtailed at a moment’s notice
This is a key point. The fact that periods of very low production would be infrequent means that there are a number of straightforward possibilities. These include industries with internal backup, such as hospitals and refineries. These systems must be tested at least every 6 months, which means that use by the grid for backup roughly twice per year would be essentially free. Other industrial users are delighted to be paid to participate in demand response systems - the cost to the company of very infrequent interruptions is far smaller than the value to the grid.
Perhaps the single largest and most obvious source is EVs like the Leaf and EREV/PHEVs like the Volt/plugin Prius. Eventually roughly 20% of the grid's kWhs will go to powering EV/EREV/PHEVs, and their charging is extremely amenable to demand response systems. Eventually V2G will also be feasible, which provide an enormous amount of storage and backup capability.
Starting from a dubious assumption, that PHEV would only be charged at night, and then only during the hours of 11 p.m. to 6 a.m.
It's perfectly reasonable to assume that the great majority of charging would be at night. First, most travel is during the day. 2nd, prices are lower at night. All that's required to have charging at night is for all consumers to be on time-of-day pricing. That's perfectly feasible, and in fact all utilities are required to offer it currently. Now, installing smart meters for all consumers is a public policy choice which might be delayed or deferred, but that choice is available (and is eminently sensible).
Nick, I have to correct you here. Given that not one single production vehicle of the Leaf/Volt/Plug in Prius has been delivered yet, I think it is more accurate to write;
Perhaps the single largest potential source is EV's like the...
I think the charging assumption is quite reasonable. EV owners will be well aware of the off peak times and rates, and as long as there is an ability to program the charger for those hours, I am sure that 90% of the time, that is what will happen.
I agree that it would be reasonable to assume that the majority of PHEV/EV will be charged at night. However, see here for alternative charging scenarios that may take place (Figure E-4): http://escholarship.org/uc/item/4491w7kf;jsessionid=2D938F67BEAD5B883C83...
Restricting recharging to night-time only also reduces the amount of petroleum displaced by the PHEV/EV. Also, many early adopters may attempt to maximize the amount of all-electric use of these vehicles to get more "bang for their buck", this means day-time charging.
There are several anecdotal scenarios I can imagine that would dissuade people from charging only at night. Here is one: Imagine you are a EV owner. You live within a range that allows you to travel to and from work on a single charge. Do you plug the vehicle in as soon as you get home (in case you need to travel again that night?) or do you program the charger for only late night charging - leaving the vehicle unavailable until the next morning. (PHEV options do get around this issue, but again displace less petroleum consumption.) Another: one is a stay at home mother (or father), you combine your trips and errands during the day to avoid repeated trips. You get home with a partially depleted battery. Again, do you plug it in for on-demand charging? Do you wait/program it?
I guess only time (and the future price of electricity/gasoline) will tell what future PHEV/EV owners will do.
Re: V2G, Using very expensive batteries in PHEV/EV to balance short term electricity disruptions comes at the cost of deteriorating battery life. Batteries would have to come a long way from where they are now, consumers would have to be conditioned/educated to allow their potential driving capacity to be reduced, and then the stored energy would be still be very expensive on a per-kWh basis. Even with V2G the number of vehicles needed to bridge potential several day gaps in electricity production is very large, and in some cases V2G could provide only a fraction of the electricity needed.
GM is leveraging the OnStar technology to allow Volt owners to control their charging schedule. http://news.cnet.com/8301-11128_3-20019424-54.html
It also looks like you can set the internal temperature, so it is cosy when you leave for work.
I'm glad you point this out. I've often seen writing that I classify as "utility executives salivating over the possibility of getting consumers to give them free energy storage". Of course the utility agent isn't concerned about battery deterioration issues, but a knowledgeable PHEV owner should be.
I agree that it would be reasonable to assume that the majority of PHEV/EV will be charged at night.
Then we're in agreement. How EV/EREV/PHEVs will be charged will depend on public policy - we can choose how much charging happens at night. If we need most of it to be at night (as I think we all agree is desirable) then that will happen. Of course, some portion during the day would be handy, as it would provide a perfect load for DSM, and DSM will be needed throughout the day.
I think that EREVs and PHEVs will be a much larger market segment for a long time, due to the limitations you describe.
Using very expensive batteries in PHEV/EV to balance short term electricity disruptions comes at the cost of deteriorating battery life. Batteries would have to come a long way from where they are now
That's probably not true, even now. Automakers are being very conservative about their battery life projections, but A123systems batteries can sustain 5,000 cycles at very deep discharge levels without losing more than a small fraction of capacity - they would be very likely to last the life of an EV, including some reasonable amounts of V2G. The Volt LG Chem/CPI battery is, IMO, very likely to last the life of the car. The Leaf just might, but the likelihood is much lower, as Nissan isn't being nearly as conservative with battery management (depth of discharge as well as temperature management) as GM.
consumers would have to be conditioned/educated to allow their potential driving capacity to be reduced
Not for EREV/PHEVs. For those, there would only be the relatively small cost of reducing the next day's all-electric range - most drivers wouldn't even use more gas.
the stored energy would be still be very expensive on a per-kWh basis.
If a li-ion battery costs $350/kWh and lasts 5k cycles, that's only 7 cents per kWh. That's pretty cheap, in the grand scheme of things.
Even with V2G the number of vehicles needed to bridge potential several day gaps in electricity production is very large, and in some cases V2G could provide only a fraction of the electricity needed.
Well, we have to decide what timeline we're analyzing. If we're analyzing the next 10 years we don't have to deal with very high levels of wind power penetration. If we're analyzing the next 100 years (as 100% renewable would suggest), we can assume very large numbers of vehicles. 230M EVs with 50kWh of storage each could provide 50% of the current US grid for 52 hours (11.5TWhs / .44TW average / 50%).
EREVs could provide backup power almost indefinitely - then we're using liquid fuels as a backup for the grid. This would be more cost-effective than it sounds, as it would likely be used very rarely, and the ICE generators in EREVs are likely to be much more efficient than the standard ICEs used in conventional vehicles currently: at least 33% efficiency (2x-3x higher than current ICEs) could be expected.
Where did you get this 5000 cycles number?
The numbers they cite in their specs are "over 1000".
Go to http://www.a123systems.com/a123/technology/life , and click on the first chart: "Thousands of Low Rate Cycles". You'll see that their batteries reach 7,000 cycles with 80% capacity remaining, with 100% Depth Of Discharge (DOD)! Or, look at the chart labeled "Independent National Lab Validation", and you'll see 300,000 microcycles.
I think those numbers are a tad bit inflated.
That same page says
That's the more relevant number. And it backs up the orignal post, battery cycle life is a critical barrier to V2G.
10C is a moderately high discharge rate - it's higher than the majority of normal operation. More importantly, it would never be sustained to 100% DOD. 100% depth-of-discharge is far more demanding than automotive use: The Volt, for instance, doesn't go below 75% DOD.
It would take far less than 1,000 full depth-of-discharge cycles to destroy the Prius's NIHM battery, for instance, which so far is lasting the life of the car. The 300,000 microcycle statistic is more relevant to automotive operations.
10C cycle life is the relevant number. I'm not saying an EV will draw at the rate all the time and get 1000 cycles. But your 5000 number was generated at an undisclosed "low rate". It is marketing BS. An EV will get more than 1000 cycles but no where near the 5000 you claimed. This is clearly seen in Nissan's projected life span for the Leaf's battery, 5-10 years.
Also
http://www.mpoweruk.com/life.htm
In the end cycle life time is the critical factor in determining battery life span. V2G will lessen that lifespan by drawing down the battery cycle life at a rate roughly linearly proportional to DOD.
If I ever bought a $40k EV I sure as hell won't let some elec company suck the utility out of it via a V2G system. I don't think most consumers will either.
You will if you're being paid peak rates for the power.. and the idea that you'd be 'required' to allow them to extract at Hot current rates is fairly ridiculous. Frankly, I'd expect that the battery owners will be able to choose the export rate, and there will be price signals to tie in with different levels of currentflow.
In California, you have the situation where your nightime power is 5c, and your daytime is 25c (actually, on "declared" Peak Days it can be 40c). So if you are prepared to let the grid take back say 10kWh from your 24kWh car six days a week, you could sell back 3000kwh/yr. With a round trip efficiency of 80%, you would make $1.60 per day, or $480 per year.
Over ten years, that is $4800, and 3000 cycles to say 50% DoD.
Is that enough to be worth it? Are you prepared to accept the effective range reduction for your drive home each day?
I'd say the benefits for the car owner are marginal. The benefits for the utility are probably much better.
AS an alternative, if you want to be in the business of storing and re-selling electricity, you could do it with lead acids.
A 24kWh bank, charged and discharged each day for 10kW, will give the same $480/year. It will cost about $6k to set up, and does not involve any inconvenience, works every day, etc etc
If you already have a home solar system, then you already have half the equipment already, so would be even cheaper.
Keep in mind that not everywhere has 20c difference between peak and off peak - if you are at 10c, it is hardly worth the trouble.
Personally, if the car is set up for V2G, and I know I'm not going to use it today (I work from home) then I would probably do it, as it would be plugged in all the time at home. When I am somewhere other than home, probably not.
Frankly, I don't think that's the scenario that would develop with V2G. Users would not be interested in a day-long 'lean' upon their vehicle batteries, largely for the reasons you state, but would be enticed by higher rates for shorter peak periods. As with the discussion about storing surplus ocean windpower in underwater compressed air, it's not a question of running the whole grid on these sources, but of having dispatchable supply available as well as having some demand controls (web- or smartgrid- enabled DHW Heaters, for example) in order to smooth out the loading.
To make it worthwhile for these EV consumers, again to reflect on your own statements, the buy prices would have to be reaching into the levels where tapping EV's is one of the last options for the utility as well. I would actually expect that the car's grid-tie controller would have price ranges that tied into state of discharge, and if you want these KWH that bad, you're going to pay for them (like Switzerland or Denmark)..
I guess it depends on the "lien"(sp?). presumably you could have the mode where you give the utility full control, to maximise the money you make (within set charging boundaries, etc) or you could control it yourself. If we assume the car is fully charged each morning, there are plenty of days i need to drive to town and back (10mile round trip), even do 20 miles. But there are almost no days when I do more then 50 miles without knowing in the morning that I will be doing that. It all depends how predictable your routine is - if it is not, then v2G, and possibly an EV at all, are not for you.
Agreed the buy prices would have top be quite high. In California they would be because the problem is not just generation, it is also transmission - V2G may be expensive for the utilities to buy back, but it is already where it is needed and not subject to most transmission constraints - it actually helps to relieve them.
It all depends how predictable your routine is - if it is not, then v2G, and possibly an EV at all, are not for you.
But it would work just fine for an EREV or PHEV, where running out of range is not big deal. In fact, arbitrage becomes very practical: if V2G pays 40 cents, and ICE generated power costs 35 cents, then there's a large profit on days where one stays within the reduced range, and only a smaller profit on days where one exceeds it.
I suspect that pure EVs will be a relatively small niche in N. America for quite some time. Those who love the idea of an EV will buy one, and people like that will be willing to subscribe to things like DSM and V2G for the same reason. Everyone else will get an EREV or PHEV.
10C cycle life is the relevant number.
It may be a useful benchmark for comparisons between batteries, but that doesn't make it the best number for projecting useful life in an application.
More importantly, this test was to 100% DOD.
But your 5000 number was generated at an undisclosed "low rate".
If you look at the chart, it says it was done at 1C/-1C. That's pretty straightforward, and it, too, is a standard battery test benchmark.
An EV will get more than 1000 cycles but no where near the 5000 you claimed. This is clearly seen in Nissan's projected life span for the Leaf's battery, 5-10 years.
You're clear that different EV batteries use different chemistries, right? Li-ion using Cobalt, vs iron-phosphate, for instance? And that battery management is important, including temp and DOD control? And that the Leaf has almost no temp and DOD management?
one cycle of 100% DOD is roughly equivalent to 2 cycles at 50% DOD and 10 cycles at 10% DOD and 100 cycles at 1% DOD.
That's not consistent with my observations and reading. I've seen one or two cycle life vs DOD charts, and I don't remember that simple inverse relationship. How many 100% DOD cycles will a standard high-discharge LA battery tolerate?? How many 25% DOD cycles does a Prius NIMH battery undergo over it's lifetime - as many as 20k, perhaps? Would it really handle 5k cycles at 100% DOD?
You're clear that different EV batteries use different chemistries, right?
More importantly, this test was to 100% DOD.
How many 100% DOD cycles will a standard high-discharge LA battery tolerate??
This is getting silly.
That's not consistent with my observations and reading.
Try reading this.
http://www.mpoweruk.com/life.htm
And you are right. Its not a simple inverse ratio. Its roughly linear excluding other aging factors. But that holds for this example as your EV is going to be temp controlled, and current limited and charged gently etc. That is car manufacturers are going to minimized all these other aging factors.
And that brings us back to the main point. Life span of these EV batteries are going to be life cycle limited. And V2G will suck that utility out of your batteries.
Rethin,
Your source is useful - thanks for that. The information that you're quoting is kind've a simplified introductory section. It's introducing the reader to the basic concepts, including the idea that reducing DOD increases cycle life. The details discussed later in the article are more complicated.
Regarding the question of different chemistries, look at the section labelled "Cyclic Mechanical Stresses". We see that two different li-ion chemistries have very different cycle life expectations. So, are we agreed that we can't look at laptop batteries, and generalize to all EVs? That we can't look at one EV, that uses one li-ion chemistry, and generalize to all EVs?
Regarding DOD, let's look at the chart labeled "Depth of Discharge vs Cycle Life": we see that 100% DOD gives 500 cycles. 80% DOD gives 675, significantly more than the 625 we get by dividing 500 by 80%. 50% DOD gives 1,150, significantly more than the 1,000 we get by dividing 500 by 50%. 5% DOD gives 15,000 cycles, significantly more than the 10,000 we get by dividing 500 by 5%. And so on.
I think we have to say that even this chart isn't intended to be realistic. For instance, a LA that gets 500 cycles at 100% of DOD....well, that's one tough lead-acid battery! In real life, the number of cycles will start lower, and rise faster than this chart indicates.
And that brings us back to the main point. Life span of these EV batteries are going to be life cycle limited. And V2G will suck that utility out of your batteries.
There are two questions:
1) will reducing the life of the battery reduce the number of cycles below the number needed for the life of the car? If not, and there are substantial excess cycles available, or V2G will be used fairly rarely, then this strategy works well.
and
2) if it does, what is the cost of that reduction? If the cost of the reduction is in the range of 7 cents per kWh, as is likely, and the value to the utility is 25 of 50 cents per kWh (or more), then we have a sensible proposition. Keep in mind, one good way to use V2G is for relatively rare, large lulls in renewable production: if these lulls only happen 3x per year, the value to the utility is likely to be in the range of 50 cents or more. And, yet, this would still be extremely cost effective for the utility as a method of dealing with seasonal renewable intermittency.
That's why I was careful to quote the paper when it says "roughly" linearly proportional.
Sure they all have different cycle life expectations. But they are all roughly linearly proportional to DOD. And that was the only point I was trying to make with that.
Yes, this is a very good question. Most of the supporting work for V2G seems to come from older lead acid technologies where the life span of the battery was calendar life, not cycle life. In that case V2G makes sense, as you said above, you are using cycle utility that would be otherwised wasted.
This doesn't seem to be the case with more modern chemistries.
Paul Nash makes a compelling argument against this above
Sure they all have different cycle life expectations. But they are all roughly linearly proportional to DOD.
Yes, as DOD rises, cycle life falls. I can kind've go along with you, though I'm not sure it's really close enough to call it a "roughly" simple reciprocal relationship. When you can get 400,000 cycles by reducing DO to, say, 1% ("For cells used for "microcycle" applications (small current discharge and charging pulses) a cycle life of 300,000 to 500,000 cycles is common.") I'd say the simple reciprocal relationship has broken down completely.
Also, the number of cycles at 100% DOD really does fall pretty sharply: the chart shows 500 cycles at 100% DOD, but I've never heard of a LA that could do anything like that. 100% DOD even for marine batteries designed for deep discharge is battery abuse. There's an old saying in the industry: "batteries don't die, they're murdered".
Paul Nash makes a compelling argument against this above
He actually says
1) V2G seems reasonably attractive to him: "Personally, if the car is set up for V2G, and I know I'm not going to use it today (I work from home) then I would probably do it"
and,
2) relatively modest price differentials would make V2G marginal, but larger differentials would make it very, very feasible. If V2G were used only occasionally for seasonal lulls, it would be extremely cost effective for utilities to pay a substantial premium (perhaps $.50-1.00 per kWh).
"Using very expensive batteries in PHEV/EV to balance short term electricity disruptions comes at the cost of deteriorating battery life."
I don't think that conclusion is altogether clear yet. Batteries are most damaged by being charged and discharged at too-aggressive a current rate, and by being Overcharged and Over-discharged, ie, reaching high and low voltages at the ends of charge/discharge cycles that are beyond it's design range.
It seems to me that having a proper BMS Battery Management System (which a user can somehow be enough involved in to antagonize any 'Forced Obsolescence' designed into its systems) would allow for regular, but controlled grid-give/take, and would help prevent your battery's early decay. IME, batteries do need 'exercise', like muscles.. they just don't do well with Abusive Treatment. (Many present battery chargers are still very rough on batteries, as they're often designed to impress us with speed-charges, instead of protect us with long-lasting batteries..)
It also seems to me that V2G can be a way to let your EV play the markets and actually help to pay for their own eventual replacements. eg, If the grid needs more supply and the price signals can trigger the BMS/Grid-tie to respond, then you have an automated trader in the energy market. (Your 'Added Storage' Hot Water Heater and Chest Freezer might be part of the play as well, not to mention your PV/Wind and Home Battery Banks) We'll see if it comes to pass, but I think it's a compelling and probably feasible system to create.
Bob
Stephen, in Scotland our government is aiming for 80% renewables (mainly wind) by 2020. I wrote to our First Minister asking how this was to be achieved, and asking for the technical work that underpins this ambition, and received a reply with three links, only one of which could be classified as a technical report. The quote above is how it is to be done - can anyone explain it to me?
Energy Storage and Management Study, produced by AEA Technology on behalf of The Scottish Government.
http://www.scotland.gov.uk/Publications/2010/10/28091356/0
Pan european wind lulls can last several days. The way we are headed we will build tons of pumped storage - which is the only storage game in town in Scotland, but still need 100% back from nat gas. We can look forward to an approximate trebling of our energy infrastructure with all the costs that involves. The government seems to think having lots of energy related jobs is a good thing.
Euan - Just a raw guess but it sounds a little like reverse engineering: Define a locale by it's very specific energy demand profile and then build the required plant if there is an appropriate design. IOW such a system will not work everywhere and thus has to be designed as very site specific. But the plan may also include the assumption that as marginal costs are satisfied additional users can be relocated to take advantage of planned excess capacity.
Euan,
I'm starting to read the study.
First thoughts: first, it's clear that it relies heavily on exports to England, so the percentages quoted are not for a system, but for just one component of the system. 2nd, 80% renewables in Scotland is just one of several scenarios, and is the most ambitious.
Do we know what the comparable percentage is right now?
Installed capacity / approximate load factor
Torness nuclear 1250 MW / 87%
Hunterston B nuclear 840 MW / 71% / 50% depending how you count
Longannet coal 2400 MW / 58%
Cockenzie coal 1200 MW / 34%
Peterhead CCGT 1180 MW / 63%
Hydro suite 1584 MW / 35%
Wind 1600 MW / 30%
The trouble with the import / export grid connectivity notion is that for much of the time when Scotland has surplus wind so will most of western Europe. And when we need to import power during lulls, a lot of western europe will be doing same. The 80% target is for electricity consumed, not generated.
Hmmm. Wikipedia says Scotland has 2,129MW of wind as of October. http://en.wikipedia.org/wiki/Wind_power_in_Scotland
When I add that up, I get:
10,583MW /50%, with average generation of 5,328MW, % wind & nuclear &hydro is at 52%, and wind & hydro is 22.4%.
Wow. So Scotland is already at 52% low-CO2, and 22% renewable!!
for much of the time when Scotland has surplus wind so will most of western Europe.
Sure. Nevertheless, 80% renewable embedded in a larger system which is 20% renewable overall is a very, very different target from 80% alone.
The 80% target is for electricity consumed, not generated.
This is what the study says:
"Scotland is developing a leading position in the development and deployment of renewable energy technologies to address the challenge of climate change and, at the same time, to create economic opportunities. The Scottish Government has a number of important targets in relation to climate change and renewable energy. These include:
A reduction in greenhouse gas emissions of 80% by 2050.
An interim target to reduce greenhouse gas emissions by 42% in 2020.
Renewable energy production equal to 20% of final energy demand in 2020.
Is that last 20% a typo?
http://www.scotland.gov.uk/Publications/2010/10/28091356/2
(1) “Target for renewable energy now 80%”
http://www.scotland.gov.uk/News/Releases/2010/09/23134359
Nick this has wandered way off the specific topic. I'll do a post on the Scottish situation some time soon where the specifics can be discussed.
I think so yes.
And as for wind capacity, the number I quote is from DECC statistics and is for year end 2009.
http://www.decc.gov.uk/en/content/cms/statistics/source/electricity/elec...
Why only 5% for solar in the sunniest region of the country? CSP makes sense in the west which is much drier than the east or very windy Great Plains. Even the north is very sunny east of the Cascades. For that part of the country I would assume the mix by 2030 could be 20%+ solar and 5% wind. This understating of solar is the major flaw of the study.
Since the electric grid cannot be maintained under the current fossil fuel regime, then BAU cannot possibly continue.
The regions of the country that begin an aggressive installation of wind and solar will be best positioned in the peak fossil fuel years.
Supply disruptions are inevitable in either peak fossil fuels or a pure renewable build out.
which would we rather have no renewables and brownouts or a lot of renewables and fewer brownouts.
I choose the latter. Best of luck. Mitigating peak fossil fuels should not be political at all unless there is a political group that wants chaos in the future.
Hoping (naively) for a less political build out of solar and wind in the future.
The alternatives are spending the bulk of the investment on conservation or nuclear.
Could someone explain why wind and solar are better investments than these two?
Nuclear: the Solution that cannot be named...
"Its too expensive" despite plenty of evidence to the contrary around the world, where build costs and lead-times in Asia are proven to be a fraction of numbers bandied about "proving" that nuclear is too expensive.
High costs, cost-overruns come down to socio-political factors in the US of A, including the business and legal environment. Dysfunctional politics and cultural values (anti-science, pro business/financial monopoly esp. re fossil fuels industry, etc.), not technology, are the problem. Regulation and politics are the root cause of problems and if you want cheap, reliable 24x7 power without fossil fuels then that's where we need to start for solutions.
It takes too long for a major build.... have a look at this chart from the IEA: France's historical electricity production by type Now, why can't USA have the same kind of growth rate, esp. using all the knowledge new design tool available to us some 20-30 years on?
It's too dangerous is the next canard, despite the best safety-record per GW-year of generation of ANY power source over many decades.
What about the waste is the next, despite the fact waste volume per GW-year of reliable power delivered is several orders of magnitude smaller than fossil fuels, and if nuclear technology is pushed to go closed fuel cycle, the potential is two-orders of magnitude smaller AGAIN.
And on it goes.
If this site wants to take a new editorial direction, I think it should be dedicated to rational analysis of all energy options and nuclear technology is the elephant in the room.
Clearly Coal and NG swayed public opinion that nuclear is unsafe to their advantage. Although a few disasters helped that discourse along.
Of course,coal is unsafe as well (witness the slag spill in Tennessee). NG is unsafe (witness the explosion of a gas line in San Bruno, Calif, which burned 4 or 5 people in their homes alive. The NG pipeline system in California is not up to date. That line was from 1949!
http://www.youtube.com/watch?v=EZ6YbUrnxVM
Nuclear is unsafe also. People will die from all these sources of energy -- no doubt.
How many more will die because we never planned for the inevitable decline of fossil energy?
The problem rests with the leaders who are not out their saying to the people what the actual problem is that we face. Everything has a trade-off.
Too bad we humans are not able to think rationally about our lifestyle and so forth.
The thing that worries me the most is weapons proliferation. I haven't really seen a good resolution for that. Just look at Iran.
My understanding (and I hope the nuke experts chime in here) is that the Thorium reactor system cannot be used to produce weapons grade material, and that is the primary reason why it was not adopted back in the '50's.
How the tables have turned!
You could try to game weapons production, by hiding some Uranium fuel rods among the Thorium ones, but otherwise you can't get weapons grade stuff. I suspect
it is a tad more expensive to make Th reactors run -at least if you assume that Uranium is abundant and cheap, and waste disposal isn't a bug deal. The gamma rays from a Thorium reactor are supposedly harder than for a Uranium one, so some additional engineering is needed. Also the Thorium reaction cannot be bootstrapped from Thorium alone, you need some neutrons from Uranium so that you can convert Th233 to U234 (which can then be used in a reactor). I'm not sure what the breeding ration is (once you have enough U234 made to get your reactor going), but if it isn't greater than one, you'll need to use some U to maintain your supply.
"Cannot" is an overstatement, but it's significantly harder than the established methods for producing weapons-grade U-235 or Pu-239. And it would be fairly easy to tell if a thorium reactor could be used to produce weapons-grade U-233. However, I think the main reason is that they'd already developed so much expertise with uranium reactors that the people in charge didn't see the need to develop a whole new system.
Thorium-232 captures a neutron to become Th-233, which decays quickly to protactinium-233, which decays slowly to fissile U-233. Separating uranium from thorium is pretty easy, so if you wait for the protactinium to decay, processing reactor fuel is straightforward.
Minor processes convert some of the thorium to U-232, which decays to isotopes that produce significant amounts of gamma radiation. A bomb containing more than trace amounts of U-232 will cook the chemical explosive and the electronics needed to set it off — and maybe the bomb-makers if they're careless. Separating protactinium from uranium and thorium is pretty difficult, but would give you clean U-233. So it'd be worth looking very carefully at anyone proposing to use that method of fuel processing.
The other way of using a thorium reactor to produce weapons-grade material would be to briefly expose U-238 to neutron flux, converting some of it to Pu-239. But a thorium reactor doesn't have a lot of neutrons to spare beyond what it needs to produce enough new fuel to replace the old fuel it's consumed. Somebody should notice if the inventory of fissile material is falling below the designed production rate.
For much, much more on the potential of thorium reactors, see http://energyfromthorium.com/
And like Stirling Cycle engines - Thorium is not 'popular' due to 'technical challenges'.
Thorium is not a magic bullet that solves all the problems with Fission power - humans are stilled flawed creates who make machines that fail. And so long as one man is willing to attack another over real or imagined wrongs places like a reactor that can put 30+ miles of land into a no-go area for lifetimes will be tempting targets.
When a wind machine or PV fails no one has to place guards around a 30 mile exclusion zone for years.
Well, in the case of Stirling engines, "technical challenges" would indeed be the reason why they are not being made in any quantity, though they are very popular with people who promote them.
[]
And that sounds exactly like the thorium reactor pimps.
??
In the case of Thorium Reactors, "technical challenges" would indeed be the reason why they are not being made in any quantity, though they are very popular with people who promote them.
Now I get what you meant - I thougth you were implying that Stirling engines did not have technical challenges.
Nuclear: the Solution that cannot be named...
Fission has been demonstrated as a failure. Hard to name something a solution that is a demonstrated failure.
Yet another example of the failure:
http://www.independent.co.uk/news/uk/home-news/how-sellafield-mutilated-...
Yup. Replacing bones with broomsticks to cover up the failure of the operation of Fission.
nuclear technology is the elephant in the room.
Yup. Like elephants - they consume alot of resources and produce piles of waste. The piles of waste and failure modes are the issue.
Fission is just more BAU - the non BAU resilient solution is small local generation via wind, PV et la. Not gigawatt accidents waiting to happen.
Wow, that's a great setup for a Ghost-story though, isn't it?
Lotta ghosts in that machine, it seems..
It's interesting to think about the actual violation involved. Part of me is a pragmatist, and knows that the body is done with, at that point, and nothing you do to it changes who that person was, but it really comes down to our respect for our people. It's very similar for me to the Mormon process of seeking out folks in old family lines and 'Saving' them by turning them Mormon-Post-Mortem, regardless, it seems of what that person may have believed or wanted. It's harmless to that person's actual history, of course, but the audacity of the offense, the presumption that you can 'Harvest Souls' when they themselves have no opportunity to challenge it like this is still an incredibly offensive proposition to me.
It's OK, I'll have my ghosts come in and 'comment' on it. That's why they're there, after all!
.. interesting as well that there's no mention of what they FOUND in the affected tissues.
Probably nothing.
Back to my MTV,
The reported testimony is thus:
We removed the cancerous and effected material so no one could show that Fission power is unsafe.
Wind is currently very roughly 1/3 the cost of solar. If CSP meets it's promises, it will still be 2x as expensive as wind. And, of course, wind costs will continue to fall, and maintain an advantage over solar.
That comparison relies on the assumption that the price of power in independent of time. Solar tends to produce during times of peak demand, so
on average it's output should be able to command a premium. A lot of wind production will come during slack times (demand wise), and so the average value of a KWhr should be less than for solar.
Also I think that the rate of improvement in cost performance of new solar is higher than for new wind. So it is serious guess work to assume which version will be most economic a decade or more out. I would also point out that the best wind sites are built out first, so even though turbines are getting better, they will have to be put on less than ideal sites. The site
issue is important in Califonia, which only has a few places with good wind potential -and they've already been developed. By contrast, the varaition in solar potential is not so strong, so I wouldn't expect the site quality (for new build) to decline with time.
Solar tends to produce during times of peak demand, so on average it's output should be able to command a premium.
I agree. Even accounting for the peak premium, it's very hard to justify a large % of solar (more than 5-10%) with relative costs anything like their current levels.
Let's say wind is $.07, and solar is $.14 per kWh. Wind could curtail 50% of it's generation in order to shape a supply curve similar to solar, and still match the solar price. And, of course, that night time power will be indeed have some value.
Also I think that the rate of improvement in cost performance of new solar is higher than for new wind. So it is serious guess work to assume which version will be most economic a decade or more out.
Absolutely. Nevertheless, we have to do our best with projections like these, so we have to rely heavily on current costs.
. I would also point out that the best wind sites are built out first, so even though turbines are getting better, they will have to be put on less than ideal sites.
Not so much for the US, overall.
The site issue is important in Califonia
Sure. CA isn't shy about importing power.
the varaition in solar potential is not so strong
Yes, but there's pretty strong regional variation. Solar in S Cal and Nevada will beat the pants off solar in Michigan for a very, very long time.
What I meant is that California has a bigger appitite for wind than it has places to put turbines. Only a few quite small areas (passes, and widgaps) have sufficient resource to make sense. So increasing wind capacity by much
just isn't feasible.
Here the proper geographical scope is within a utilities service area. There are a lot of sites with roughly the same quality of resource. There is no danger that the good sites will be taken, and only very poor sites remain.
California has a bigger appitite for wind than it has places to put turbines....So increasing wind capacity by much just isn't feasible.
But why is installation within the State important? CA imports a lot of it's power right now - why not continue, if there's a substantial cost differential?
There are a lot of sites with roughly the same quality of resource. There is no danger that the good sites will be taken, and only very poor sites remain.
Yes, CA (along with the whole US SW) has enormous solar potential. Of course, the whole US has enormous wind potential.
Really? I would think we have lots more places to expand. And how about offshore? I don't think there is much if any offshore wind facilities off California.
Not really. See, e.g. this map:
http://www.windpoweringamerica.gov/wind_maps.asp
And the seabed off California drops pretty steeply; there's no continental shelf like there is off the east coast. So far, there's something like one (1) experimental floating wind turbine in the world.
Solar heat (hot water, building heat) is even better cost wise than taking electrons and using them to make things warm.
"Even the north is very sunny east of the Cascades."
Since I live there;
In the summer it's sunny, and the days are long, so solar would do well.
But the winters are another matter. 8 hours of alleged sun that you can't see through the heavy overcast make the panels useless. And the fogs are also windless, so no help from the windmills.
The dams work, as does the nuclear plant.
The Navy can build load-following reactors, so could the civilians. It's a cash flow issue; the plants cost so much they want to run them flat out. It also makes refueling easier to plan when you run a full nameplate for X hours. I used to have to calculate EFPH every day, which the officers somewhere would add up and estimate when the reactor would need to be refueled. Even so I heard stories about boats towed to the yards because the reactor was all done one trip early.
(EFPH is effective full power hours, and is really a way of figuring our uranium consumed today, or rather, yesterday.)
Wow - to run out of nuke fuel on warship seems like a serious error. Was this in the early days of nuke ships- I can't imagine this happening to a carrier or submarine today?
Why is it assumed that load following has to be implemented by the fossil fuel plants alone?
In particular, this has the potential to cause problems during periods when wind and solar are generating too much energy, which has to be exported.
Wind turbines have blade pitch control so that they can be prevented from overspeeding and stopped during periods of high winds. It would seem simple to have a smart grid command wind farms to adjust pitch or stop units in order to reduce generation when it is not needed, rather than reducing output from nuclear or coal generation plants.
I don't think anyone is going to shut down nuclear. If you shut down coal, you save the money you would have spent on coal; if you shut down wind there are no fuel savings.
Molten salt cooled reactors, if they existed, might store heat somewhat like concentrating solar power plants do now. The idea would be to run the nuclear part at 100% 24/7, and shift some of the power from night generation to daytime generation. From the operator's point of view, this allows the plant to shift power to the pricier part of the day. From the system's point of view, this allows a larger fraction of total system power to come from nuclear.
The cost of the storage media itself (probably the loop salt, like a MgCl2/NaCl eutectic) and the tanks to hold it are not a problem, as it takes about a year to pay that back. But several systems get scaled to 1.1x or 1.2x the average power of the plant -- in particular, the gas turbine, the generator, the switchyard, the salt/gas heat exhanger, and the final heat exchanger which rejects heat to the environment. And this gets to a calculation which makes all energy storage systems look terrible: the extra capacity has a capacity factor of something like 25%, and the money it makes when operating is the difference between daytime and nighttime power prices (and not just a straight price).
For example, assume that those systems cost $600/kW (about as much as a combustion gas turbine and generator), which is quite optimistic, and assume the portion larger than the nuclear heat source gets used for 6 hours/day. The extra capacity costs $100 per kWh shifted per day. Assume daytime electricity is worth $10/MWh more than nighttime electricity, so that the kWh shifted is worth, 0.1 cents. It takes 10,000 days to make back the original investment. That's too long.
But this calculation also applies to dams with excess generation capacity. Somehow the turbines and generators and so forth on these dams are much cheaper than gas-fired turbines. The Bureau of Reclamation claims that uprating dams has cost an average of $69/kilowatt since 1978... which is somewhat cheaper than the gas turbine costs I've assumed. So something is going on here that I don't understand.
Molten salt cooled reactors, if they existed
I believe they have existed (As experimental) but due to safety issues are not a #1 choice.
You may be thinking of reactors cooled with liquid metal, especially liquid sodium. That can get exciting if it leaks. Molten salt is used in several solar plants; it needs no special treatment, just a large insulated tank.
http://home.earthlink.net/~bhoglund/mSR_Adventure.html
What you're talking about is called "curtailment". As "pasttense" notes, we want to minimize curtailment, as wind power is free.
Of course, curtailment is a perfectly reasonable strategy, if it's not overused. Some amount of it will be included in any fully optimized system.
The NREL study tries to keep curtailment below .5%.
Given the ratio of new transmission costs vs. WT costs, I expect the minimum economic curtailment to be at least 4% of total wind MWh generated, and likely closer to 10%. 0.5% seems uneconomically low.
An alternative strategy showed up in Idaho. Rural T&D line has 18 MW capacity. Build a dozen 1.5 MW wind turbines that feed into that line. Do the same on several different lines. No transmission costs (except short hook-up).
Alan
An alternative strategy showed up in Idaho. Rural T&D line has 18 MW capacity. Build a dozen 1.5 MW wind turbines that feed into that line. Do the same on several different lines. No transmission costs (except short hook-up).
This is one example of distributed generation. You are trading off ideal wind sites for ideal (=free) transmission access. Though there will be plenty of windy sites on/close to distribution lines. This means you don't get concentrated wind farms, so they are a bit more costly to manage maintain, but so what? The coefficient of variability will also be slightly lower.
Also, curtailment reduces the overall consumption of the wind (or solar) generated electricity annually. This means that one would have to increase the overall capacity of the wind farm to meet a desired penetration rate of wind power consumption.
Yes.
Another perspective: curtailment raises the effective cost of wind power, by reducing it's effective capacity factor. If we lose 1% of wind output through curtailment, we raise the cost of wind power by 1%.
So, we definitely want to minimize it. OTOH, small amounts of curtailment may be cheaper than trying to accomodate every last kWh generated, through transmission, storage, etc.
There is another way to deal with Excess from wind.
Create environmental dump loads. An example - a current in an artificial reef structure helps coral grow and can overcome heat and acidification stress.
Thusly one can create organic (small) dome structures for human use or a far more important use - promote fish habitat which can't be exploited by trawling type operations.
How much electrical energy is lost in transmission across a) conventional grid and b) HVDC grid ?
This seems an eminently sensible question to answer before we rush off and plan energy infrastructure (on paper!) where the generation of sparks is some way from the demand. Here in the UK this is less of a problem - the furthest anywhere is from the sea is 70 miles (offshore wind, eg). But what this article is proposing is on a much, much larger geographical scale.
Perhaps while answering this question it would also be sensible to determine the STD DEV distance of current US habitation from conventional power generation. I bet most people in the US live much closer to a power station than what is proposed.
I know I haven't bothered to google these questions, my apologies for being lazy but I have to put the dinner on which means going to the shops first. Anyone have any figures? ta.
HA - I don't have numbers but I'll pass on the story again of how Texas has become one of the major generators of wind power in the US. One huge wind farm was built in west Texas where there is little demand. But Dallas, hundreds of miles away, had a surging demand. The last I heard Dallas was considering voting on a $2 billion bond to build the transmission system to capture the excess power. Not only did the windfarm owners get the public to pay for the transmission lines but they also got the right of way to lay a fresh water pipeline along the route. Supposedly the windfarm economics look pretty good. But, then again, what project wouldn't look better with a $2 billion subsidy?
I' m not completely opposed to such a scheme. The alts seem to have difficulty clearing economic hurdles today. When the day comes when the economics work well it may be too late to switch over quickly. Unfortunately such a plan has at least one major flaw: the govt needs to make very sound and logical plans for such a future. I would be concerned that the political math would override common sense.
Thanks Rockman - interesting story. What I would be fascinated to know is whether, for instance, it would be energetically feasible to transmit electrical energy from the new off-shore wind farm in Maine to Florida. That is some serious distance. Is there a Federally mandated grid in the US, or is it within States' rights to withhold their sparks? At peak times in the UK we southerners rely on excess Hydro capacity coming from the Scottish Highlands - which can come on line (and off again) within minutes. But even from the Highlands to the South Coast it is less than 500 miles, about the same as your wind farm to Dallas example.
I think we had the opposite problem. There was a proposal to generate wind in the midwest for consumption along the east coast. East coast political interests were opposed, because they wanted the money to be spent locally.
"Energetically feasible" is entirely a question of economics of the particular situaton. However, Hydro Quebec does generate about 20+ GW of hydro power in Northern Quebec and transmit it with HVDC as far as New York State, probably comparable to NY City to Florida. Everything depends on the voltage used. A line at 250,000 volts will waste 4x as much power as a line at 500,000 volts for the same conductors, the same kw, and the same distance. As distance increases, AC transmission develops problems which DC transmission avoids. It's do-able now to operate HVDC lines up to about 1,000,000 volts, whereas AC is limited to about 750,000 volts.
Some formulae.
Loss (E) = Amperage (I) x Amperage (I) x Resistance (R) (I^2R)
HA - Just a guess but I think e can be shipped state to state if the buyers/sellers cut a trade. But at one time there was a physical barrier: three grids in the US: east of the Miss. River, west of the M.R. and Texas. During the early part of the 20th century the system was designed and voluntary. Texas, being Texas, opted not to be connected. But that situation may have changed in the last 20 years or so.
http://en.wikipedia.org/wiki/Independent_system_operator
There appear to be four Regional Transmission Operators, two quasi RTOs, and eight Independent System Operators, of which Electric Reliability Council of Texas (ERCOT) is one.
With AC interconnects, the problems of system management and stability do not necessarily get simpler as the size increases, since you are talking about a giant, synchronous electromechanical machine with considerable delays between its parts. Ties between the New York Independent System Operator and the PJM Interconnection were weak enough that New Jersey was unaffected by the New York blackouts of 1965 and 1977. By the 2003 the ties had been improved to the point that the Northeast Blackout also blacked out Northern NJ, along with about 55 million other people. http://en.wikipedia.org/wiki/Northeast_Blackout_of_2003
A more stable design would be to divide the geography down into smaller units with HVDC lines for trading power between units. However, with the US business, economic and political setup, that will never happen.
Merril - Thanks for the details. I could barely remember that there were serious intergration problems with various NE grids. Something like one switching station failing led to ten's of millins blacked out. Some folks worry about terrorists upsetting the system. Might be smarter for them to just sit back and let us do the dirty work.
you are talking about a giant, synchronous electromechanical machine with considerable delays between its parts.
Which is a very strong argument for investing in a smarter grid. There are a lot of benefits to upgrading the grid beyond accomodating renewables.
I think the study is wise to rely less on gas fired backup. However the assumption that coal can do the job not only implies more load variation than is normal but ignores the possibility of severe CO2 caps. Some climate campaigners want 80% CO2 cuts by mid century. In any case the US will be one of just a few countries with cheap coal to spare in 2050.
Other possibilities are burning biomass instead of coal and coal with carbon capture and storage CCS. I doubt that either will scale up at affordable dollar or environmental cost. There is some talk of molten salt nuclear reactors that can quickly load follow but commercial versions are years away. It all points back to energy storage. I guess we will have little choice but to pay a lot more for energy or cut back.
One possibility to incorporate much more wind and solar into grid:
When a wind and solar project is planned then be bold and increase the size many times over. Then build a transmisson line to the area which does not have more capasity than 30% of installed production capasity.
This looks as a waste of resource but it is not.
The transmission line will have a much higher utilation and economy as it will run at or close to max capasity for 6000 hours a year rather than 2000 hours a year. This project becomes now 3 times as realiable for grid controllers as otherwise.
When wind or solar production exeeds transmission capasity is the exess production diverted to electrolyzis production of Hydrogen and Oxygen. Storage tanks for hydrogen at high pressure is very costly. A far cheaper storage is a multiple mile long pipeline. The same storage is to be used for the oksygen as this is produced along with the hydrogen. Hydrogen should not be used to produce electricity as this route results in 80% loss. Hydrogen and oksygen should be used as a product. The multiple mile long pipelines should lead towards industries which need hydrogen and possible oksygen. Possible industries could be: Fertilizer industry (ammonia),Heavy oil refineries, 2nd generation BTL or CTL industries (gasification. A BTL (Methanol) plant has too much CO and CO2 in syngas compared to Hydrogen. If new hydrogen and oksygen is availiable it is possible to triple the liquid (Methanol) output from the same biomass input.
The biomass resource is realy to small to scale BTL up to a significant level so tripling its reach is really a desired achivement.
A pipeline as storage is quite flexible. Multiple wind or solar producers can apply hydrogen along the route. Several industries is also located along the pipline. The hydrogen will by the preassure move along the pipeline towards the users. When there is a "lull" in wind and solar there is still hydrogen availiable although less so as the preasure decreases.
Back to the electricity case.
Electricity has a difficult storage issue. A project where only 30 % of capasity is connected to grid becomes much more reliable. When the wind slows down is the Hydrogen production reduced as electricity is given prioriy. This project could also become a electric sink (load). If to much electricity is awailiable elsewere then this project could utilice all own wind and solar electricity for Hydrogen production. The transmission line could also provide ecsess electricity produced elsewhere towards the hydrogen production.
Running the coal fired plants, which is badly suited for load following at capasity may be a possibility.
Such a plan will.
- Become more reliable making balansing easier.
- Better utilation of transmissin investment.
- Producing hydrogen which is used as a product (saving natural gas)
- Becoming an electricity sink if needed.
make hydrogen
I'd say no.
1) Hard to contain H2.
2) People who work in the fuel cell industry have pointed out that straight up H2 fuel cells are not gonna happen without a miracle
3) http://www.tinaja.com/h2gas01.asp
Best plan on local generation is try and figure out what energy capture -> montizitaion/life improvement plan will work for you based on intermittent energy flows and then do them.
(or pray that supercaps AKA eestor are true)
Eric,
The proposal here is very different from H2 fuel cells for transportation. There's no need for distribution, and the electricity is almost free.
The question is: what's the cheapest way to store electricity for periods of up to a year? Pumped storage would work, but for periods of that length would be expensive. PS works better for daily (or shorter) cycles. The same applies to chemical batteries, only more so. We need something where the storage itself is very cheap.
I suspect that creation of electrolytic H2 would work. Perhaps synthesis of some simple hydrocarbon, such as methane, ammonia or methanol would make sense. Perhaps CAES (air) would be best: http://isepa.com/ , http://www.sandia.gov/ess/About/docs/haug.pdf , http://www.generalcompression.com/gcaes.html
what's the cheapest way to store electricity for periods of up to a year?
With current levels of technology you can't. Ultracapacitors might be able to, but they lack the watts/cost.
You can convert into a 'stable' form then back - as you note Ammonia/methyl alcohol. Back in the 70's there was a process called (I believe) seafuel that used electricity to make methyl alcohol.
I suspect that creation of electrolytic H2 would work.
Not keeping it as Hydrogen gas, no.
With current levels of technology you can't.
I think what you're really saying is that the cost for chemical battery storage would be far higher than for alternatives.
Back in the 70's there was a process called (I believe) seafuel
I couldn't find it easily.
Not keeping it as Hydrogen gas, no.
Why do you say that? Stationary storage is much easier than mobile storage (for vehicles). Underground storage would seem to work well: http://en.wikipedia.org/wiki/Underground_hydrogen_storage
I couldn't find it easily.
So your search engine kung fu is better than mine and you found it?
Why do you say that?
Because its true.
your search engine kung fu is better than mine and you found it?
I meant that I did a preliminary search and didn't find it. I could spend more time, but that would might be a waste of time, especially if you have more info.
Why do you say that? Because its true.
Ahem. That's not really advancing the conversation. I was asking for specific info - do you happen to have any at hand?
Nick: Why do you say that?
Eric: Because its true.
Nick: Ahem. That's not really advancing the conversation.
Have you bothered to read the link to Don Lancaster I provided? How about my profile where I quote the Chair of a Fuel Cell group where he declares Hydrogen only cells dead?
You have to be willing to do SOME work on your own. Like look at links.
Now - having a few days to think of the SeaFuel link I re-applied my google fu.
http://peakoil.com/forums/viewtopic.php?f=6&t=1560&view=next
Seafuel Synthesis Process: MeOH from Oceans
As noted - they had the process working.
Now, go back and read Mr. Lancaster. If you can debunk his position, do come back. Otherwise the readers will have to assume you agree with him or you are too unmotivated to go read the link.
Have you bothered to read the link to Don Lancaster I provided?
I presume you're talking about the tinaja.com link. Yes, I read through it. I'm very familiar with the info - it primarily relates to personal transportation, and it assumes methane as the input. It doesn't tell us much about my question, which is about a stationary application linked to wind power as the input. That has very different conversion, distribution and storage dynamics.
I took a look at the seafuel link - it didn't give much info for this application:
"the book Methanol: Bridge to a Renewable Energy Future by John H. Perry Jr. and Christiana P. Perry....I think the authors (a father/daughter) own the Seafuel process described below....The core of the SSP process is mixing elemental hydrogen and CO2, and reacting them with a catalyst to produce MeOH & H2O. Then you distill out the MeOH. No hydrocarbon feedstock outside of construction (and perhaps electrical power)."
Amazon has the book, but it was published in 1990 - I'm not sure it's worth buying.
Nick,
Okay, underground storage of hydrogen isn't something I know much about. You do need convenient geology though, which is not available everywhere or even most places.
If we store hydrogen as a gas at ambient temperatures in aboveground tanks, the pressure vessels cost quite a lot. At a 6% interest rate, the interest on the capital on the tank for 12 days is more than the value of the hydrogen. That means that if you were planning on storing the hydrogen for longer than 12 days, you can save money by not building the tank, flaring the hydrogen off and then generating new hydrogen later when you need it, from something like natural gas. I realize this completely defeats your point, but that's how expensive it is to store hydrogen.
Numbers:
Pressure vessel made of steel.
Steel yield strength 310 MPa, safety factor of 4 (ASME)(so loaded to 77.5 MPa)
Steel is $1/kg and 7.85 g/cc
Pressure vessel is a sphere (most efficient shape)
Hydrogen is worth $0.7/kg
Hydrogen is 22.4 m^3/kg at 25 C and 100 kPa. Multiply and get 2,240,000 Pa*m^3/kg at 25 C
The steel needed to contain that hydrogen is 340 kg for each kg of hydrogen. Equation is at Wikipedia.
So, that's $340 of steel to contain $0.70 of hydrogen.
At 6% interest rate, 12.5 days of interest on $340 is $0.70.
I've neglected the cost of actually building the tank, which is going to make this look even more dismal.
-Iain
Wow. So a 340 kg tank is needed to store 1 kilo of hydrogen? Wow. Yeah, that doesn't look anywhere near competitive.
That certainly points to underground storage. I would agree that convenient geology is needed. The Wikipedia article says that there's hydrogen storage in Texas (the ConocoPhillips Clemens Terminal), and there's a similar (larger) storage tank in Kansas for propane. Those locations are pretty close to the Midwest wind corridor.
I don't think it makes sense to require that the storage be colocated with the power source - your wind farm may not happen to be on top of a salt dome. If the storage is reasonably nearby, that's good enough. Heck, with a robust grid location shouldn't matter that much.
Iain,
Where did you get $0.7/kg for H2?
Given that 1kg of it has the energy value of about one gallon of gasoline, I would expect the value, once pressurised/liquified suitable as fuel, to be around $3/kg.
That still doen't make it economical, of course, but it is not as low value as you are using.
70c/kg sounds like the cost of making it from NG, at a refinery or such, where they use it rather than compress and store it.
In any case, it is very expensive to store!
Ideally, there would be some easy, small scale way to convert it to methanol, and store that. There is such a way, but it is not easy, not small scale, nor suited to stop start operation.
I can't see hydrogen being the answer, unless there is an on site use for it.
in order to increase generation capacity of renewable energy from stochastic sources, traditional, controllable sources of electricity generation must be maintained sufficient enough to provide 100% of the demand, if the renewable energy sources are producing 0%.
This sounds more meaningful than it is. If we retain legacy coal and NG plants, and build very cheap biomass-powered peaker plants, and use all of these only 5% of the time, the costs are not large relative to the overall system costs.
And, as discussed below it's only true because we (and the NREL) want to minimize costs. For instance, we could use 50% of windfarm power output, or 25% of CSP output, to electrolyze hydrogen. Pumped storage would also work. Utility storage of power is far from the low-cost approach - it might add as much as $.07 per kWh - but it's costs would be acceptable from a "preventing TEOTWAWKI" perspective.
Utility storage makes sense to smooth out very shortlasting shortfalls, say a few seconds or a few minutes. These can allow time to bring up spinning reserves, or other sources (and deamandside actions as well). Stability covers a range of timesacles from fractions of a second, to hours (or months, if say a utility with a lot of hydro suffers from a severe drought). Obviously
storage solutions that make sense on one end of that scale, are not good candidates for the other end of it.
Yes, I was thinking of seasonal drops in production.
Utility storage will work just fine for very short variations. Utilities really should move to Demand Side Management for that, though, because it's much cheaper. DSM is really the best solution for variations within the daily cycle.
If I put on my "imaginary industrial plant managers hat", I would be
much more likely to accept a contract which means I get the occasional notice that says "You have ten minutes to transition to our mutually agreed upon MOL", then one which says, "we just just off your power to process XXX (so sorry". Given some amount of lead time should allow for orderly transition (like finishing something undergoing a power hungry process which will be ruined if it is cut off in mid process). Having various levels of gap bridging storage is likely to be crucial for grid stability, even if it has no hope of covering longer term *hours to days) power gaps.
Consumer requirements would vary greatly.
PHEV/EREV/EVs, for instance, could be cut off instantly. So could A/C (if only for a period of minutes). Industrial/commercial lighting levels could be reduced by 20% instantly.
Other consumers would require lead time.
Despite the major costs I think electrolytic hydrogen may work out better as a source of peaking power than biomass. In my observation biomass currently needs associated sunk costs, subsidies and cheap diesel, factors we can't assume will always be available. Sawdust or bagasse burning needs a saw mill or sugar mill nearby. The operators complain if they can't sell carbon credits. The biomass is harvested and delivered in diesel powered machines. Also a steam boiler based power plant should not be idled for more than a couple of hours.
OTOH hydrogen can be handled any time in reversible fuel cells. In hydrolysis mode vent the oxygen and store the hydrogen in large low pressure tanks. On a TV show on submarines I noticed they vent the hydrogen instead. In fuel cell mode make electricity. No steam boilers to fire up, no soot, no moving parts. The problem is capital cost including that of platinum electrodes. Maybe NREL should work on getting hydrogen costs down.
I'm sure that use of low-cost surplus wind power to make hydrogen and synthetic hydrocarbons will be a significant part of the mix.
The problem is low efficiency thoughput. One answer, as you note, is fuel cells, but that raises capital costs, and this is equipment that will not have high rates of utilization. OTOH, I think that fuel cells are making progress towards reasonable costs (just not for personal transportation).
Some poor analysis.
One is not understanding the economics of pumped storage.
As long as Natural Gas is dirt cheap, IF THE ONLY ROLE of pumped storage is back-up for renewables, NG wins at $4/mcf.
However, TVA found it economic to expand their pumped storage (Raccoon Mt) just to operate their FF units more efficiently. In addition, PS provides almost free spinning reserve for those utilities with PS. Switzerland is not building 12 GW of pumped storage just for renewables, but it is economic to build PS and some of the purchased power will be 3 AM wind.
And there is more.
Also, the claim of 100% FF back-up required for renewables in specious.
The vast majority of US utilities are summer peak. Usually on a very hot SUNNY day in second half of July or first 3 weeks in August between 3 & 4 PM. A day without sunshine is NOT an annual peak demand day !
Solar PV is not at maximum output then (max insolation is ~June 21 at solar noon, 1 PM DST) but there is still some decent output in mid-August at 4 PM.
Texas is very well known for summer doldrums (little wind) during heat waves. Yet ERCOT still gives wind a 5% of nameplate credit for calculating peak capacity. (Coal gets about 90% from vague memory). So ERCOT disagrees with the 100% figure quoted.
This was just so egregious an error, I felt a need to post. But there will be few others.
Alan
The main problem with the study is its overall perspective -- it is a study of how to integrate wind and solar alternative energy deployments motivated by GHG emissions reduction into a BAU electrical generation system governed by BAU economic principles.
It is not a study of how to integrate wind and solar generation needed to build out added electrical capacity in a nationalized electrical grid administered under a state of national emergency in order to compensate for lost oil production and skyrocketing costs of coal and gas in a highly inflationary economic environment.
For a 2030 time frame, the latter would be much more interesting.
But the latter wouldn't have to spend time on analysing market pricing of electricity, carbon taxes, and other fashionable subjects.
For better or worse, the US has more than enough affordable coal for the next 50 years, even if we replace oil with electricity (EVs, heat pumps, etc), and even in NG runs short (which appears unlikely).
I strongly advocate a fast transition to wind, solar, etc, but that's because I think AGW is a very big problem.
OTOH, I think what you're really saying is that the kind of analysis of small differences in cost that the NREL performed is irrelevant to the kind of "preventing TEOTWAWKI" approach on TOD. And, you're right - wind, solar, etc are entirely affordable, whatever the cost of mitigating intermittency.
"For better or worse, the US has more than enough affordable coal for the next 50 years..." Nick, you should check the cost of NEW coal power plants that have ALL the required pollution control equipment, i.e. SOx, NOX, mercury, particles, AND new solutions for ash disposal, which by all technical definitions low-level radioactive waste. It matters not one ioto in the life-cycle, full value chain analysis how cheap you can buy the coal. The capital cost and associated operating costs of new coal power plants will absolutely kill it when compared to new natural gas. And yes, there is a real probability that new coal power plants will at some time in the future be forced to retrofit for CO2 capture. New coal is dead, end of story. And please, please, please do not confuse this with the low cost of continuing to operate ancient, debt-free grandfathered coal power plants that have no obligation to clean up the godawful mess the spew out by the millions of tons yearly into to hopelessly unsafe ash ponds and directly into the air that you and I breath and into the surface waters the whole of creation depend upon.
Please forgive my rant, I am just so damned tired of all the misleading claims of cheap coal.
You've got a very good point. The Prairie State coal plant now being completed in Illinois, for instance, is costing about $2.75 per watt of capacity ($4.4B for 1.6GW), which is much more than older plants. With a capacity factor of 73%, that's a capex of about $3.75 per W, which pushes the cost of coal power up into the range of what, around $.07 cents/kWh? And, some other coal plants will be even more expensive. That makes it hard for them to compete with high efficiency NG plants.
But, keep in mind the context. This is what I was responding to:
"It is not a study of how to integrate wind and solar generation needed to build out added electrical capacity in a nationalized electrical grid administered under a state of national emergency in order to compensate for lost oil production and skyrocketing costs of coal and gas in a highly inflationary economic environment. "
My point: we have plenty of affordable coal. NG may well be cheaper, but we're in no danger of not being able to keep the lights on in an affordable way.
Similarly, we should retrofit for CO2 capture, but if there is a choice between sequestration and keeping the lights on (and consumers solvent), there's really no question what choice will be made.
I would bet dollars to donuts, that their charter didn't allow consideration of that sort of scenario.
What a strange contention, but I have seen others make the same error.
If solar and wind have the capability to produce an excess they do NOT need to 'be exported and absorbed outside of the system'.
Of course, commercially (like any utility), they prefer higher GWh, but there is no technical brick wall here.
You can relatively easily and simply, reduce power from Solar and Wind, as required.
OR, you may chose to use that excess, to bank into pumped storage, for example. - but you do not have to complete a complementary storage at the same time, if funding does not allow.
In California, some new PPAs (power purchase agreements) between utilities and renewable resource generators give the utility the right to curtail the renewable generation for a specified number of non-summer-peak hours per year (typically 50). The generators agree to this because their revenue during the rest of the year - particularly during summer peak hours with their higher time of day rates - makes up for the lost revenue during any curtailments. The buyers use the curtailment rights to avoid having to curtail coal or nuclear during low off-peak load hours with high renewable generation, or having to curtail gas-fired generation at night from slow-start plants that are expected to be needed to meet the following afternoon's peak.
For WestConnect, there is a simpler solution to the problem of up to 3 GW (in the worst hour of the year) that "must be exported and absorbed outside the system." Namely, export it to California, where it will be absorbed outside the system. California's annual minimum load is around 18,000 Mw for the CAISO-controlled grid, plus another few thousand Mw at municipal utilities.
Balogh is correct that at some point integration will create problems, and California is devoting a lot of effort now to thinking about those problems now, but they (a) can generally be solved easily with money (e.g., curtailing low marginal cost resources with high capital costs, like wind, coal , or nuclear, which is expensive but feasible), or (b) can be solved over the next decade with cleverness. The CAISO, which usually is all in favor of reinforcing the California transmission grid at any price, has concluded that the exisitng grid can handle the operational issues raised by 20 percent renewables, and will be able to integrate 33 percent renewables (the 2020 target) with a few thousand Mw of new thermal generation (less than what has already been licensed but not yet built. So without being too much of a Polyanna, it's easy to believe that the real technical heavy lifting won't arrive in California until renewables make up more than 33% of generation, in the 2020s.
So without being too much of a Polyanna, it's easy to believe that the real technical heavy lifting won't arrive in California until renewables make up more than 33% of generation, in the 2020s.
unless, of course, if NG, on which Ca now depends very much, returns to pricing levels of 2008 - that will lead to some very "heavy lifting"
To be accurate, you should probably state "renewable imports" make up x% of the grid,, since importing seems to be the basis of Ca's policy on renewables.
The authors reach the same conclusion as I have - that large scale storage as a means of capturing excess wind and solar power and releasing it during times of need is not economically feasible, nor is it as helpful as initially suspected in filling production gaps.
I think the phrase you want is "economically competitive". IOW, large scale storage likely would be feasible, but would not be the low-cost solution.
Have you looked at H2 electrolysis, or hydrocarbon synthesis (methane, methanol, ammonia, etc)? Are you aware of any studies of these for wind power balancing?
I haven't read the report and probably won't as I am not into fairy stories.The Beyond Zero Emissions report in Australia recently was in this mould.
Why bother with trying to shoehorn renewables into supplying base load power when there is already a proven,improving and non polluting technology available and working on a large scale worldwide?
That technology is NUCLEAR, boys and girls - oh,shock,gasp,horror. - get real,get over it.
Yes, nuclear is perfectly feasible as an answer to our need for electricity. Your comment would be appropriate for an Original Post that was questioning whether we will be able to maintain a cost-effective, adequate grid. But, this study isn't about that: it's about the limits to wind and solar.
There's one good reason for studies like these: wind (and solar) are much faster to build. You can go from empty field to working wind farm in 24 months. The comparable figure right now for nuclear is at least 8 years.
We need low-CO2 power ASAP - we're already perilously close to "losing Florida".
Yes, we can speed up nuclear, but getting that acceleration would take time. Plus, we can speed up wind, too - it will always be 4x faster.
Nuclear is now "nonpolluting" apparently according to fiat.
Tell these children about that:
http://t2.gstatic.com/images?q=tbn:ANd9GcTVbShbD8tWAUiBuDkf19LqohQ_p8j_D...
http://t2.gstatic.com/images?q=tbn:ANd9GcT8BNhlVTGqt9dQbxRrIDrGE5FTZFTE_...
Nuclear appears to pollute based on those images.
Please do comment on nuclear waste issues.
How is it stored? How is it transported? What happens when a facility is compromised? Who pays for the clean-up? AND SO ON.
Then do the same for solar and wind. Indeed they are not baseload sources, but they also are less polluting than nuclear and they can be insured.
Nuclear plants are not insurable unless the public does it via a government. Gee, why is that?
You arn't gonna get 'em to comment. Dig around in the archives you'll see the pro nukers make up safety ratios (1 in X). Some of 'em seem to rotate 'round the internet posting the same stuff...almost like its a paid job to pimp for Fission.
I am not into fairy stories.
Like how Nuclear is safe, clean and even too cheap to meter?
That technology is NUCLEAR, boys and girls - oh,shock,gasp,horror.
I stand corrected then. Nuclear is not a fairy story - it is a horror story.
(I note how not a single pro nuker has supported the actions of people associated with the Fission power industry removing the bones of the dead and replacing 'em with broomsticks.)
What is an estimate of the cost of electricity in this area if the solar/wind proposal were done instead of a traditional coal/natural gas expansion?
Man, it's crazy that we live in a world where The Oil Drum seems to give a better and more unbiased analysis than the academic literature does.
The points made here are all REALLY good and as somebody who's researched this exact subject, all of these things concern me. This study hinges upon probably 5 other studies that needed to be done but never were. I think many of the problems are resolvable, like the maneuverability of thermal plants. There is nothing new about the ramps that thermal plants are tasked with in this study, but the structure will be different. Thermal plants are intermediate, scheduled, resources. Renewables will demand unscheduled maneuvers. That is a very tough egg to crack, and though it will drastically influence operations, it's incredibly hard to say how-so.
A point I would make is that the negative net load hours clearly form a "long tail". It's not a major quantity of energy, but it is a very challenging control problem. "so what?" you say. The conclusion is that prices will be negative for these times. The economics point FIRMLY to this result. The problem is easy as pie to solve if you could send a message to everyone to turn their lights on, and if you already implemented a system to instantly curtail demand, it should be trivial to use said system to instantly increase power. You can't get something from nothing, but getting nothing from something is totally doable. Nevertheless, infrastructure for getting nothing from something doesn't yet exist, and a blackout is a blackout.