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In Part 1, we looked at supply management as a mechanism for coping with the variability of wind resources. In this part, we look at the other side of the equation, load management. What are the prospects for being able to use power “as available”, and how will that capability affect the economics of renewable energy?
Some loads, by their nature, have a degree of latitude as to when they run. A good example is pumping water from a well to a storage tank. It doesn’t particularly matter when the pump is on, so long as it’s on for a sufficient period of time each week to keep the storage tank supplied. Discretionary loads enable power to be used—within limits—when it is available. A discretionary load that is equipped with a communication interface allowing it to respond to real time information on power availability becomes a responsive load.
Some loads that are not currently discretionary (or responsive) could be made so, given incentive. It would not be difficult to design refrigerators, for example, to use “as available” power to make ice. The ice would then be used to supply refrigeration at other times of the day.
That approach also works for air conditioning. Large commercial and industrial projects have occasionally employed built-to-order HVAC systems based on ice tanks or reservoirs of chilled water for thermal storage. Recently, off-the-shelf systems for smaller commercial buildings have been introduced. To date, however, the market penetration for all such systems has been low. They offer no big reduction in total kilowatt-hours consumed for cooling, and in most cases have higher initial cost. Their value lies overwhelmingly in their ability to provide cooling capacity that is decoupled from their power draw. Under rates that vary according to demand, they make good economic sense. But under a flat-rate scenario, they are hard to justify.
Turbine Inlet Cooling
There is one little-known but surprisingly large-scale application of thermal energy storage that does not depend on the politics of power pricing and deregulation. That’s because it is internal to the operations of power suppliers themselves. The application is “turbine inlet cooling” (TIC).
The efficiency and power output of combustion turbines depend on the inlet air temperature. When the inlet air temperature rises, both the efficiency and power capacity fall. The drop off in efficiency is fairly small, particularly if the unit is a high efficiency combined-cycle unit used for baseload capacity. But the drop off in capacity is large enough to be a problem. On the hottest summer days, when electrical demand is at its highest, the capacity from combustion turbine units is at its lowest.
In hot weather, it turns out to be worthwhile to use off-peak electricity on the night before to make ice, and then use the ice to pre-cool the inlet air for the turbine the next day. The direct efficiency gain offsets, but does not fully make up for the fuel consumed in making the ice. However, that's not the purpose. The purpose is to boost the capacity of the combustion turbine for meeting the next day’s peak demand. That reduces the need to draw on dirtier and less efficient peaking units.
This system has been used in Southern California and elsewhere for a number of years. In the seasons when it is used, it does have potential utility for accommodation of variable wind and solar power. The cooling equipment is a large responsive load. In principle, at least, it can be varied rapidly to offset changes in available solar and wind power. If power from a wind farm begins to fall unexpectedly while the cooling equipment is operating, power to the coolers can be cut back. This maintains a steady load for the remaining generators until dispatchable resources to replace the wind farm output can be brought online.
The same principle of thermal storage used in ice-based cooling systems can be adapted to provide hot water, industrial process heat, or general space heating in winter. When cheap power is available, it drives a heat pump. Pumped heat is stored in a hot water tank or in a tank of eutectic salts with an appropriate melting temperature, for use when needed.
For industrial installations supporting distributed generation, thermal storage can enable the generators to operate at periods of peak demand, when their electrical output commands a premium. Storage allows their co-produced heat can be used around the clock.
Heating and cooling represent a significant fraction of our overall energy use—45% of utility bills in the U.S., according to EERE. Over the long term, responsive heat pumps with ice or chilled water storage for cooling and hot water or eutectic salt storage for heating have the major potential. They should be able to accommodate almost any degree of variability that renewable energy sources might throw onto the grid. However, it will be a long time before there are enough installed units of the appropriate type to really be helpful. In the meantime, are there other responsive load applications that could be ramped up quickly?
Electrolysis as Responsive Load
Electrolysis of water to produce hydrogen and oxygen is an obvious candidate. Since the product gases can be stored, electrolysis has at least the theoretical potential to become a very large responsive load.
Contrary to what many suppose, the market for hydrogen is already quite large; it will grow considerably larger over the next few years, regardless of whether we all start driving around in hydrogen-fueled vehicles. The existing markets are, in descending order of size: fertilizer production; oil refining; and other industrial. (“Other industrial” being a catch-all that includes the plastics and food processing industries, which are both hydrogen consumers.) The biggest growth will be in the area of oil refining and its offspring, synthetic fuel production. The heavy and sour crude oils that make up an increasing share of world supply require large amounts of hydrogen for reforming and “sweetening”. Production of synthetic fuels from coal and biomass requires even more.
The size of the hydrogen market goes unrecognized, in so many cases, because it is mostly not a merchant market. The big hydrogen consumers don’t buy hydrogen on the merchant market; they typically buy natural gas, and use captive steam reforming plants to produce hydrogen. Until recently, steam reforming of natural gas was by far the cheapest way to produce hydrogen. With the steep rise in natural gas prices over the last few years and diminishing North American production, the situation is now less clear. Gasified coal and petroleum coke have become competitive as sources. Could electrolysis of water by electricity from non-carbon sources also become competitive? If so, the available market is easily large enough to absorb the variability of wind and solar energy units as fast as they can be built.
The short answer as to whether electrolysis can be competitive is that it depends entirely on how serious we are about reducing CO2 emissions. When coal or petroleum coke are used to produce hydrogen, the net reaction is:
At least 1.45 moles of CO2 are produced for every two moles of H2. (The additional 0.45 moles of C and O2 are needed to balance the reaction thermally. The basic reaction,
is strongly endothermic, and requires heat input of at least 178.1 kJ to drive it. That heat input is provided by the combustion of the additional .45 moles of carbon.) When hydrogen is produced by this method, more than 16 kg. of CO2 are produced for every kg. of H2.
If we’re serious about reducing CO2 emissions, then all we need do is enact a CO2 tax that is large enough to make electrolysis competitive. Otherwise, it will be very difficult to produce carbon-free electricity cheap enough for electrolysis to compete with carbothermic reduction of steam.
You get a hint of the problem when you consider that in generating electricity from coal, only a third of the energy content of the coal ends up as electricity. The rest is waste heat. As a result, the carbothermic process starts out with a 3:1 advantage over electrolysis. I.e., using coal-fired electricity, it takes about three times as much coal to produce a unit of hydrogen by electrolysis as it does to produce it by carbothermic reduction. Of course, the cost of hydrogen depends on much more than just the cost of electricity (for electrolysis) or the cost of coal (for carbothermic reduction). Nonetheless, it’s clear that absent any credit for avoided CO2, the cost of non-carbon electricity must be substantially less than the cost of coal-fired electricity for electrolysis to compete. Since coal-fired plants currently deliver the cheapest baseload capacity available at the margins (i.e., for new capacity), that's a tall order.
The conclusion for electrolysis as a responsive load is rather problematic. It will either be insignificant or it will be huge, depending on the political fortunes of a CO2 tax.
The other big application that could potentially provide responsive loads for absorbing variability is battery charging for electric and plug-in hybrid vehicles.
There has been a recent surge in battery technologies, fueled in part by the success of hybrid vehicles and the promise of a dramatically larger market for high-performance batteries. Several new lithium-ion battery technologies are capable of supporting very high charge and discharge rates, with prospects for extended service lives well in excess of 2000 cycles. Production battery systems now achieve up to 200 watt-hours per kilogram, enabling EVs to achieve a 300-mile range on a single charge. The main issue now is cost, and the trend line there is sharply downward.
If the market for plug-in hybrids develops as rapidly as many anticipate, it will create a huge opportunity for responsive load management. The expectation is that most of these vehicles will be plugged in overnight, when they can be recharged with off-peak power. Rather than having to add new generating capacity to meet the load, the leveling effect of off-peak battery charging will enable existing generating assets to be operated at better capacity factors. This should actually reduce the average cost of electricity, on the basis of cost per kilowatt-hour.
However, this model doesn’t do a lot for wind and solar energy, whose peak outputs are respectively uncorrelated and anti-correlated with overnight charging.
For best use of wind and solar energy, a substantial fraction of the battery pool must be available for charging throughout the day. The conventional PHEV scenario, focused on overnight home recharging, does not support that very well. Even when a PHEV remains at home and plugged in during the day, its batteries will normally have been fully recharged within the first few hours after it was plugged in, to make it ready to go whenever needed.
There are a couple of strategies to address this shortcoming. One is to equip businesses with smart outlets for vehicle charging in their parking lots. That would allow more latitude in when charging was performed, so that it could better match power availability. It the "vehicle to grid" concept, it might even be used in reverse, allowing the charged batteries of plugged-in vehicles to be used to supply peak power to the grid. Charge management software in the vehicles would allow their owners to control whether and to what extent they were willing to participate in VTG operation.
The other strategy--which I personally prefer--involves the use of swappable battery modules. I'll leave the description of how that could work to a future article. However, the bottom line for load management is that there would be a sizeable pool of battery modules plugged in to charging stations at all times. Many of those modules would be reserves that could afford to wait for recharging when power was available. They could therefore serve as ideal responsive loads.
The Variability Issue: Is It Dead Yet?
In Part I, we saw that options available for supply management are sufficient to enable a fair level of wind generation to be accommodated at low cost. Up to a penetration level estimated at 20% of total demand, wind can usually be accommodated without resort to new backing capacity.
In this part, we looked at several types of responsive loads with high potential for load shifting. Load shifting to use power “as available” not only allows higher levels of variable wind and solar power to be accommodated, it actually reduces the general level of peaking and backup capacity required for reliable operation of the power grid. It allows more of the total load to be met using high efficiency baseload units. Power pricing policies that encourage responsiveness make economic sense, independent of whether the variability that they address arises from the nature of RE sources or from the normal daily load profile.
Is that it? Are supply management and load management, between them, all we need to slay the dragon of variability for renewable energy?
Probably not. Certainly supply management, alone, is not sufficient. It enables the use of wind and solar resources to reduce fossil carbon consumption, but is still dependent on use of fossil fuels to support dispatchable generating capacity. When load management is added to the picture, the need for dispatchable fossil-fueled capacity diminishes. A sufficiently high level of responsive loads, combined with a high level of non-fossil baseload capacity (nuclear and / or hydroelectric), could entirely eliminate the need for fossil-fueled generation—in principle. But realistically, it will be necessary to invoke a third strategy for coping with variability if we ever expect to derive most of our energy from renewable sources.
That third strategy, of course, is energy storage. We'll look at that in Part III next week. But it's worth mentioning here that the kind of storage we'll be talking about is long period energy storage, capable of supplying several days worth of backup to large-scale wind and solar resources. We won't consider battery storage, for example. Battery storage has become useful for short-term energy storage up to as much as an hour. E.g., the Sorne Hill wind project in Ireland will be using a vanadium-redox flow battery will to "firm up" its output and provide a more predictable and "operator friendly" interface to the power grid. However, its 12 megawatt-hour capacity represents only about 20 minutes of full output from the wind farm. For the regulated interface that it provides, that's sufficient and cost-effective. But even flow battery storage is much too expensive to supply backup of wind and solar resources for a period of several days running. For that, some new technology is likely to be needed.
An energy analyst once told me that the market for responsive loads with respect to HVAC and to some extent refrigeration is so huge that that any variation in supply for the foreseeable future could be quickly cobbled up by them with no need for electrolysis (for example). This would require some additional metering, but the costs could be easily justified for the savings involved.
One could even see the refrigerator in our homes being possibly wired to receive extra electrical power. The net result is a bunch of freezers are a few degrees cooler and will need to draw a bit less current some hours in the future.
Again, the metering is the bugaboo, but I already have an electric water heater set by the electric co. to cut off in the case of a brown-out, for which I receive a much lower rate. I'd think the opposite could also be arranged in a similar fashion.
Roger Arnold 12.28.06
Anybody know of any substantive policy-based arguments against variable metering? Is it just a matter of inertia and reluctance to undertake a massive change in the infrastructure? Because if it is, I can think of a reasonably easy workaround.
In the white goods and home appliance industries, there's a strong trend toward more advanced microprocessor control and variable speed brushless motors. The increasingly small cost premium for the necessary power control unit is offset by higher efficiency, lower motor cost, and greater reliability. There's also a trend to internet connectivity--which sounds crazy at first, but actually turns out to be a good way to reduce the frequency and cost of service housecalls.
In that context, it's very easy for an appliance to query a central web site for rate data and to compute its own power bill. Since it's factory-installed firmware that we're talking about, the security issues for reliable accounting are easy to deal with. The customer is billed normally per their standard fixed-rate meter, but the appliance sends in a monthly certified rebate request for the difference between the fixed rate billing and the variable rate billing for power actually used.
All that's needed is for the utility to get permission to honor the certified rebate requests, and to maintain the site for posting real-time rates. In return, they get better utilization of their capital assets, and reduced headaches with load peaks.
And a few systems architects and sofware engineers, like myself, get to be honestly employed for a bit longer.
Jim Beyer 12.28.06
At the risk of being wrong, a few points on variable metering:
1) According to one of my professors, it is a idea that is being kicked around by grid controllers. Their idea is that they can turn on/off variable loads to keep the grid balanced.
2) I've heard a lot of griping about the meter costs. How much would this really save someone per year vs. the cost of the metering? If a fridge uses 500 kw-hrs per year, and say 30% of that can be re-rated at 50% of the rate, that would save what, $10 to $15 per year? Not a huge incentive, plus it means LESS overall revenue going to the utility. If a meter costs $50, then the payback is 5 years. That sounds pretty good, except I think there are other efficiency gains out there that are even more favorable.
3) At this point, even in California, renewable energy has such a small footprint that the whole discussion is largely academic at this point. Even if supplying by renewables approached 10 percent (which would be huge) I think the issue would still be pretty minor.
4) Yes, utilities do seem to be very stodgy, at least here in the Midwest. The recent scrapes concerning net-metering highlight this. On the other hand, the utilities on the West coast just seem to be crazed, which isn't so wonderful either.
5) It might be interesting to watch Germany or those other countries that have heavily subsidized grid-connected solar PV. Perhaps the utiilties there will do something to offset the losses of the buy-backs at retail prices they are contracted to do.
6) This might be a stretch, but it's possible that since the utility probably can't raise rates, they'd have to provide rebates for off-peak use, like you've stated. But that really doesn't serve them very well, does it? They would be setting up a system to reduce revenue. This would only make sense if it could serve to lower peak usage and forestall a new installation (see below).
I'd guess of all of these, point #3 is probably the most significant -- it doesn't matter yet, and won't for some time.
But on the other hand, many states are struggling with increased capacity demands, and the prospect of building a brand new coal plant, just as we are understanding the affects of CO2 emissions on climate change. I'd think any utility would jump on the chance to delay a build decision like that if they could forestall their capacity peaks for a few more years. But maybe they WANT to build them now before stricter regulation gets in place. It's hard to understand where they are coming from sometimes.
Roger Arnold 12.28.06
Jim, what you're missing is that there is already a large variation between on-peak and off-peak demand, which causes a lot of expensive equipment to sit around idle when it could be generating power. Rate-motivated load-shifting would allow the utility to meet higher net demand with its available assets. Irrespective of supply variations from renewables.
A flatter load curve also makes it easier to justify equipment upgrades for the newest and most efficient equipment. Raising the minimum demand point allows new equipment to be used for baseload supply, rather than load following.
You're right that the reduction in a homeowner's annual electricity bill for a single refrigerator would be pretty small. But with the workaround I was suggesting, it wouldn't be necessary to buy or for the electric company to install a new meter. That's the point. The capability to meter its own power usage and receive credit for off-peak power usage would be a "freeby" on a new appliance purchased for other reasons. But if it was a refrigerator actually designed to cool with ice made with low-demand power, I think the discount would end up applying to almost 100% of its power consumption, rather than just 30%.
James Hopf 12.28.06
This article was very informative (and encouraging) concerning the HVAC, TIC, and stored heat technologies. Also, I concur fully with the author concerning EVs & PHEVs and their ability to make use of off-peak power. I would, however, take his points on electrolysis even further.
A sufficiently high CO2 tax may not save the variable-source electrolysis approach either, as there are low/no-CO2 options for generating H2 that are much less variable (if at all) as well as most likely cheaper. These include thermo-chemical H2 production from non-fossil heat sources such as nuclear, solar thermal or geothermal. Similar to the situation w/ coal, using the heat directly to make H2 is much more efficient than using it to make electricity and then using electrolysis.
Thermo-chemical H2 generation plants would be ideally suited to large, stationary H2 demand centers such as refineries (which will make up the lion's share of H2 demand for the foreseeable future). H2-powered cars may be another story (where local electrolysis could win out), but it is exceedingly unlikely that H2-powered cars will ever win out over PHEVs or EVs anyway.
Furthermore, even if one assumed that electrolysis is used, variable sources would be at an economic disadvantage relative to power sources with a more steady output. The reason is that the electrolysis equipment (and its associated capital costs) would have to be scaled to peak power output, versus the average. Thus, for a source like wind (CF ~ 30%), these electrolysis plant capital (and operating??) costs would be ~3 times higher, for a given amount of overall H2 output. I think these capital costs represent a significant fraction of final H2 cost.
None of the above necessarily means that variable sources like wind power (coupled w/ electrolysis) should not be used to make H2. It just shows that their kW-hr generation cost would have to be significantly lower than that of other less variable options before they would be the economic choice for H2 generation.
Concerning PHEV/EVs, I'd like to (again) link the following article giving the results of a promising PNL study which shows that most or all of the US vehicle fleet could be powered by electricity with no new power plants or transmission lines:
This, of course, assumes off-peak (night) charging. I'm also assuming that the theory is not that all cars would immediately (i.e., dumbly) start charging as soon as they are plugged in. I'm assuming that the charging load would be spread throughout the night using smart meters or some other device that tells each car when (and how quickly) to charge. I'm kind of with Len concerning the relative ease with with such metering technology could be employed. A similar "Smart" system could handle opportunistic sources of supply such as wind, by commanding cars to charge when a lot of surplus is available. This would certainly be true if high winds could be predicted a mere ~24 hours in advance (perhaps even 12). It would certainly beat any scheme that tries to use H2. IMO though, it will be harder to make use of wind power during the day, as it would require daytime charging to be arranged, something that I think will happen slowly, if at all, on mass scale.
I also concur that PHEV/EV car charging will act to lower power prices over the long run, as it will smooth out the power demand curve, allowing more power to be generated with baseload plants, which are cheaper over the long run. While it's true that no new power plants are actually necessary to handle the charging load, utilities will voluntarily replace gas plants with non-gas baseload units as the demand curve smooths out. Basically, as the minimum point in the curve moves up, gas plants will be replaced by baseload plants. At today's (and tomorrow's) gas prices, it just doesn't make sense to run a gas plant all the time. In the long run, PHEV/EVs will lower power costs, reduce CO2 emissions and pollution, and reduce our dependence on gas and general and foreign gas (and oil) in particular.
Len Gould 12.29.06
Agreed James: A smart PHEV strategy is simply a win-win-win situation all around, and should be strongly encouraged even as technology is still developing.
Jim Beyer: It seems to me that embedding the intelligence for market-based demand management in the appliance is the wrong approach for several reasons. 1) even if it were mandated that every appliance implement it tomorrow, it only works to full potential after a complete lifetime turnover of appliances. 2) it is only capable of achieving a percentage of desired ends, as many loads are not ever likely amenable. 3) it only works for single-family residential, whereas an intelligent meter infrastructure can also interact intelligently with eg. commercail and industrial sites as well. 4) it requires owners to set whatever limits / settings etc. they may be provided at a large number of points throughout the home every time they wish to adjust their price/convenience tolerance. 5) it likely provides only very crude tools to the distribution entity to eg. manage loads on feeders or substations etc. 6) it's a security nightmare, both when connecting a new appliance and for the network managers ongoing.
At best it achieves perhaps 50% of the benefit of an intelligent IP communicating meter / market system where the meter itself handles communication to the appliances via cheap local powerline carrier, for only double the cost.
Jim Beyer 12.29.06
Well, at the risk of being wrong (again):
Len: I'm not completely sure what you are referring to, but I'm not an advocate of my #1 above. I think it is very top-down and controlling, and indicative of how the grid folks seem to be thinking - which is why I included it. I think the particulars of how an appliance is connected and responds to a floating electricity price is less important than the problem that the utilities most likely won't do it - whatever the mechanism, at least not now.
Maybe it is better in other parts of the country, but I am ammazed at how stingy (and petty) the electrical utilities are here in the Midwest (which is slowly having an electricity crisis of its own - held in check somewhat by a stagnant economy). They would not even allow open-ended net metering of owner power sources (meaning that additional power pumped into the grid in excess of the owner's own use would not be compensated at all - not one penny.) due the costs of "metering and bookkeeping". Even though the actual cost to them would be miniscule, because so little power is generated by customers.
And I think Roger's web-based approach is a very good one, but again, I don't think it will happen anytime soon. First of all, who pays out the rebate? (Never mind it would be something tiny - that's beside the point) Second of all, why would they want to do something that gives them less revenue, and more bookkeeping, etc., to boot? I think you have to take into account how incredibly conservative and uncreative these people seem to be. (To be fair, maybe I or we don't understand the system well enough to be sniping at it.)
In the Midwest, something like 70% of our electricity is derived from coal. Which is cheap, but obviously dirty - in several ways. But they equipment use problem is more of an issue with peaking demand. Shaving the peak (and thus delaying new equipment deployment) is the main benefit that our utilities would likely be interested in. If I am understanding Roger correctly - he is pointing out the large day/night variation in power use. This technique would be considered far too radical to lower capacity requirements based on it. Utilities are wary about assigning any capacity to wind power at all, let alone a new metering scheme.
I want to stress that I do not think they way (I think) the utilities do, but that's how they seem to be. The majority of large power users are already doing coarsely efficient power usage, and they expected loads are fairly well-known, and large. (A stamping mill needs about the same amount of power from 9 to 5 each and every day.) Residential customers are an annoyance that require far too many resources for which they receive a pittance in revenue.
Roger Arnold 12.29.06
Len, don't ding Jim for suggesting embedding the intelligence for market-based demand management in appliances. That was my suggestion. But your comments notwithstanding, I think it's an idea that has merit.
You seem to assume that variable metering will produce load shifting by changing people's behavior. I don't think anyone seriously expects that. Any shifting will come about as a result of introducing appliances--refrigerators, freezers, HVAC systems, dryers--that are designed to exploit thermal storage and off-peak heat pumping. So point 1) is immaterial; regardless of how variable pricing is implemented, any load shifting is dependent on turnover of appiances.
Right now, unfortunately, we're stuck behind a chicken and egg impasse. Without variable metering, there's no reason to build appliances that use thermal storage. It adds cost, and the only market would be the tiny niche of off-grid homesteaders. But without an installed base of such appliances, there's no reason for a utility to undertake the costly replacement of all its electric meters. I was suggesting a way to break that impasse.
I don't understand your point 2). Of course not all loads can be shifted. That's their nature. What does it matter how variable metering is implemented? A non-discretionary load is not going to become discretionary because of the meter it's connected to. Unless, again, you're thinking in terms of behavior changing? "Let's check the meter rate before we decide to turn on the TV"? Somehow, I don't see that as likely.
As to point 3), why would it only work for single-family residential use? It would work for anything that was designed to use it--which is equally true for anything designed to work from an intelligent meter. Or are you thinking that the meter would operate relays to deliver power to individual circuits connected to it? Now there's a fine recipe for a nightmare!
Regarding point 4), I frankly don't see any future for any system in which a price / convenience tradeoff must be set--whether it's done globally, through a smart meter, or individually on each appliance. The fact that a refrigerator or HVAC system does its heavy lifting off-peak must be transparent to the user, or the product won't succeed.
Regarding point 5), right now the distribution entity has no tools to manage loads on feeders or substations. Only the big gun of a regional blackout. Are you really suggesting that anything beyond demand-based pricing is needed or desirable? I don't think most customers would be too happy with the notion that the utility company might employ rolling blackouts on a house-by-house basis as a way to "manage load". Plaintif's lawyers would love it, however.
Point 6) is simply wrong. Security nightmares arise when people who should know better deploy powerful, open-ended solutions to ill-defined problems. The cure is to make sure the problem is well-defined, and then deploy a solution for that specific problem. There are proven, bullet-proof ways to deal with the security issues for this type of system.
Damn! This was just a toss-off idea. Now here you've got me defending it and thinking seriously about business plans! I didn't need that! Thanks a lot, Len. ;-)
Len Gould 12.30.06
Roger: sorry to say it, but you're simply wrong on every point. You're limiting your imagination to what is current. Start thinking of what is technically possible. A very quick run-down:
1) meter vs. appliances. Naturally many benefits either way only accrue after upgrading appliances. However I personally prefer the programming of my "lifestyle change" rules to be under my control rather than dictated by some central utility. If I have guests arriving for a weekend, I'll want to use the key panel in my kitchen to set my hot water heater at full charge coutinuously, not managed by some long-term agreement with some huge centrally planned utility system, thank you all the same.
1 and 2) "changing people's behavior."
certainly not. Having appliances or connection plugs which can accept "permission signals" from the meter requires no behavior change. eg. a clothes dryer which can operate at 5 kw normally or 2.5 kw if the meter signals it via the powerline, with a simple "High Priority Load" button which will override if pressed, requires little or no "behavior change". Having a meter where the homeowner tells it once on installation "don't touch my lifestyle UNLESS the electricity price goes to $0.50 / kwh, then back loads off as available" is NOT IMO a huge scary lifestyle adjustment as you claim. (But of course you know that ....)
3) A smart meter which can simply use the powerline or a local network to turn certain adresses down or up would work just as effectively for an office or retail store's HVAC units etc. as for a home, simply by accessing the existing controls circuits. Your "strictly smart appliance" strategy does not
4) So you would preffer to NOT give me any option to set a price/convenience tradoff, no matter how convenient, eh? Why is that?
5) Your point is unclear. By what path did you get to "blackouts"? As described in my articles, the market manager can signal connected meters to any granularity they wish that they'd like a load reduction, simply by setting the price. It may even happen automatically, simply included in the load-sensitive "T&D" portion of the charges on particular feeders, substations etc.
6) There are proven ways to break EVERY security system, definitely including your network of hundreds of thousands of home appliances communicating with central headquarters. And no shortage of kids willing to play with it. I prefer to keep the communications local and not publicly accessable at any point.
At core, we disagree on "centrally planned" vs. "individually controlled". In your strategy, since there can be no way for the signalling entity to confirm who's appliances responded or not to a turndown request, then any financial benefits remaining after the utility's cut (if any) are simply shared among all customers regardless whether they responded or not. I prefer my approach, (see my articles on EnergyPulse) where the gains acrrue immediately to the persons making the reductions.
Roger Arnold 12.31.06
Len, as I started to read your comments above, I was thinking that you really need to define just what this "smart meter" that you prefer actually is, and how it is supposed to work. But then I came to where you mentioned your articles. So I looked, and found them here and here. I had not read them previously--I don't pay too much attention to articles on "industry structure", which perhaps betrays my bias.
Well, things are a bit clearer to me now, at least in terms of understanding the context for this dialog. Voltaire: "The best is the enemy of the good".
I don't quite know how to respond to what you put forward in your articles. I don't want to open up yet another rehashing of the deregulation debate, but it's almost impossible to comment without revisiting a lot of those issues. The lead sentence of your article makes no bones about the sweeping scope:
This is a discussion document to begin an investigation of implementing a completely new model for utility service delivery for all customers.
Whew! At least no one is going to accuse you of thinking small. Here all I want is to find a practical way around the "chicken and egg" impasse that is blocking introduction of load-shifting appliances. I want the ability to use "as available" power to play a larger part in the energy market.
The main difference we seem to have is in our thinking about loads. You have an abstract model of loads as discretionary, based on an implicit cost-benefit analysis by customers. Thus, it makes sense to you to refer to a price / convenience tradeoff that the individual user should control. Your "smart meter" is an automated proxy, programmed with the user's preferences, to make pricing by real-time auction feasible:
.. replacing all present utility meters with smart meters which can act as intelligent “purchasing or sales agents” for the customer by communicating with a centrally operated electronic market ..
You don't really say what all these discretionary loads are, or what life under this regime would look like. "Hey, meter, I'd like coffee and toast for breakfast. Go buy me some power for the coffee maker and toaster, but don't pay more than three cents for it. I'd rather go hungry than pay exhorbitant rates. Oh, and don't buy it from those jerks at U-mongous Power and Light. Their plants are really dirty".
I don't see a price / convenience tradeoff as a factor in a realistic system for load shifting to exploit "as available" power. The aim of the system isn't to reduce the total amount of energy consumed--just its timing over the course of a day. It's sufficient to focus on the loads that account for the lion's share of energy consumption, and are (coincidentally) the most naturally suited for load shifting: heating and air conditioning, refrigeration, and hot water. And once PHEVs arrive, battery charging. None of these things involve a price / convenience tradeoff. The use of "as available" power is transparent. The appliances simply work, and that's all the customer really cares about.
You bring up the example of a hot water heater, on weekends when you have house guests. Why should you have to use a key in the kitchen to override your meter and have the water heater work to full capacity? Thermal storage in any appliance would be sized for "normal" use, but in all cases, if the thermal store is depleted--or about to be depleted--the policy would be to switch on the heat pump, never mind the time of day or rates. Works fine, since it's only the large scale statistical behavior that matters, in terms of electricity supply.
Of course, if you want your guests to run out of hot water, or are a real scrooge about your electricity bill, I suppose your water heater's web page could be given a setting for that. ;-)
Charles Kleekamp 1.1.07
Mr. Arnold, thank you for a very informative series on wind variability. As a prelude to your Part III on storage, I would hope you will address the viability of pumped storage as a complement to wind. Without re-posting, I would suggest you refer to my late comments of 12/31/06 at the end of your Part I.
As noted there, geographical regions such as New England have much different wind resource characteristics (such as offshore) as well as capability for pumped storage (currently 5.4% of ISO NE grid capability). Here pumped storage is used on a daily basis. Pump for about 16 hours when cheap and generate for 8 hours... at 75% efficiency and a big price differential, a good profit is made.
And as you pointed out in Part I, conventional hydro is perfect for load following and I would add that pumped storage is as well. I would contend that pumped storage is also the perfect load management and storage option for wind variability.
My point is that in the hay-day of nuclear power, with plants that could only or mostly operate at full load, no one suggested that the cost of pumped storage to load shift nuclear was a problem or even talked about the extra cost for delivered electricity to my knowledge.
In New England we have only 14% of nuclear left in the ISO capacity pool, and yet we have 5.4% pumped storage (1,650 MW) and 5.5% conventional hydro. So it seems that there would be no additional cost to integrate wind in New England unless the mix gets at least to several percentage points.
And by always offsetting the use of expensive oil (24% of ISO NE capacity) and natural gas (38% of ISO capacity), wind with pumped storage seems an ideal well proven and economic match to reduce the importation of oil and gas relieving all the attendant international risks. After all, a barrel of oil avoided is a barrel saved, the same with natural gas.
Charles Kleekamp, P.E. Ret.
Kenneth Kok 1.2.07
I find the comment reguarding metering very interesting. Some years ago I lived in the Phoenix, AZ area and we had time of day metering. I do not know how the utility, Arizona Public Service, measured it but I suspect it had to do with the type of meter that was in the house.
In the home we put timers on things like the water heater, dish washer, and clothes dryer. In addition we were careful about using major cooking appliances during the peak morning and afternoon periods. By the way these periods only applied to week days The cost of power during those periods was about twice the cost of power at other times.
The system seemed to work very well.
Jim Beyer 1.2.07
Roger and Len,
I think we are drifting into the realm of tyranny of small differences - your positions seem too close to be so vehemently argued over. Again, I think if you look and see where most utilities are NOW, you will see you are basically standing right next to each other.
I think Len is coming from the standpoint of wanting to arbitrage potentially multiple major suppliers. Well, I don't think that will practically happen anytime soon. That would involve too much potentially wasted capacity that frankly would never be built with that kind of uncertainty of pricing in the system. (The cost of bringing in electricity from even 200-300 miles to serve a demand peak is very high.) It should be pointed out that major energy users (factories, etc.) negotiate electricity pricing anyway. (One problem in Michigan due to partial deregulation is that major power users can negotiate contracts with suppliers out-of-state. This allows the out-of-state suppliers to cherry pick the big users. The in-state suppliers lose the large (and profitable) contracts but are still forced to carry the unprofitable residential contracts. The in-state providers claim they are being pushed into bankruptcy. At least that's their side of it.)
On the other hand, I think in a world of greater DG, there may be hundreds or thousands of microsources. The most likely scenario is 1 to 3 major sources to choose from (any more than that would be too far away and most likely too expensive 99% of the time) and a froth of microsources. How are the microsources organized and marketed? Without knowing much about this, I'm tempted to look toward the SOES system set up by NASDAQ after the 1987 crash.
From the standpoint of demand, you are basically in the same camps. I think one can see that time of day, day of week, day of year, and weather conditions are excellent predictors of electricity demand. Given that, relatively little information needs to be sent to the consumer to inform him/her of instantaneous energy value. A bigger problem (thinking like a utility) is how does one note amount AND time of energy use in a verifiable and secure manner? The plan outlined by Roger makes good practical sense, and would be simple to implement, but there is no way to verify the user did not cheat. (Just as there is no way to know if the user has spun back their meter back.)
Kenneth's comment was interesting. Check out the Arizona Public Service utility at www.aps.com, and see how they offer different rates based on time of day, and peak demand usage.
From the standpoint of demand, it seems that getting better meters into the system is the only real way. Perhaps some concept such as Roger was proposing would make sense as a way to get things started.
From the standpoint of supply, I think this is more difficult, and also even more important (because DG should be economically encouraged, for a variety of reasons). Realistically, I think the total kwh produced by small DG sites is so small that some simple system (that encourages DG) should be enacted until the total energy production exceeds some small amount for a region (like .2% of grid loading or what not). It should be clear to all involved that the rules will change when small DG production rises above this threshold. At that point, the extra generation will be significant enough (at least potentially) to give some more careful thought about a fair method of selling it. A reverse version of time of day metering would make sense, so production during peak use would most profitable. Something to account for grid use would also make sense, so if a DG source can supply a site only a few miles away, then it should be rewarded for it's low grid-miles-kwh use.
I think it is safe to say that time-of-day metering, like PHEV development, is a GOOD THING, and some way to do this technologically is quite possible. The details may be unclear, but we can clearly do it.
Like PHEVs, the benefits of doing this should be examined and more clearly and quantitatively explained (has anyone done this?) The PHEV people are pretty good, but I think they have garbled that message a tad by expousing the CO2 reduction benefits (there are few, at least right now) and linking PHEVs with biofuels (there should be none.)
I think time-of-day metering has enough real advantages to not push for the less credible ones as well. And if it doesn't, then perhaps it's not such a great thing after all.
Len Gould 1.2.07
Roger: excellent comment, agreed on most. Let me say that I don't really anticipate much if any consumption reduction with a well-designed system as proposed. What I am aiming for is that we not waste the largely still un-spent budget for the next level of metering, eg. AMR and TOU, on a system which is only "half-vast". The goal of the system I propose is to significantly increase the load factors of central generating stations, and encourage and fairly reward distributed micro-CHP, eg. Whispergen's 1.1kw Stirling home heating appliance etc. but allowing those to become large enough to actually heat a North American home (say 5 kwe and 15 kwt) without giving away all the excess electrical power for free as in current systems. Also the islanding logic and disconnects enables eg direct connection of generators w/out a) the power loss and cost of an inverter. b) the exhorbitant network study costs now typical. c) some others.
Andrew Gill 1.3.07
Great article, and an earlier commenter's remarks about energy saving fridges made me wonder about the domestic consumer of the future.
I think that household utility bills have to be relatively low, because that is the only way to balance the average household budget. That budget gets even smaller every time the breadwinner's workplace has to pay more for energy, and therefore pays out less in wages. Consequently, high-tech energy-saving wizardry matters LESS to home consumers as energy prices rise, not more.
Homes can save energy by not using air conditioning, having an indoor temperature of 40F all winter, by going to bed at sunset, by washing with cold water, and by not going anywhere without good reason. If it sounds like dreadful poverty, millions have done these things within living memory, and we survived!
If consumers are forced to behave this way, then I think the power load will be determined by industry much more than home consumers. Load management will be more professional and therefore more accepting of variable supplies.
Edward Reid, Jr. 1.3.07
"...on a system which is only "half-vast"."
Brian Braginton-Smith 1.3.07
Roger, Great work, truely valuable pieces on important enabeling technology for a more sustainable future. I eagerly await the next piece.
Len, I was pleased to see the dispatchable distributed co-generation topic brought up. If we can utilize the thermal load and the electricity with monitization of the reourcs we can achieve economic viability. The dispatchable capacity could begin with conventional ICU or microturbine technology with the capacity to shift to belnded or pure hydrogen fuel as the consumer based hydrogen market develops. The benefit of the high efficiency utilization of capacity for the full spectrum of output from the distributed resource is important in reducing our climate change impacts and our resource use. Our soceity has numerous stand-by power capacity sites. Instead of just having the capacity idle utilize the captive load as a base load and exploit the thermal resource as described in the article.
Village infrastructure development and redevelopment should incorporate responsive, smart systems technology in order to maximize grid efficacy and resource conservation. We must bring about change for the sake of our environment and future generations.
Keep up the great work Roger, I think 2007 is going to be a good year. - BBS
Martin Tampier 1.3.07
Roger - thanks for mentioning the swappable batteries. I have always been wondering why nobody discusses this solution to refilling battery cars, although I had always thought it would be the obvious way to do it. Am looking foward to a future article discussing this in more detail - guess you will need some lifting equipment at gas stations in the future...
Graham Cowan 1.4.07
Plus a five-megawatt grid connection for each "gas station", unless it's like the "hydrogen stations" that were recently springing up by the, um, by the one around the world: underbuilt due to an anticipated lack of customers due to being a despicable sham. I guess that 5 MW would come as what, 26000 V 200 amps? 4400 V one kiloamp? Or hey, why not just cover the roof that used to shelter the pumps with a solar array that can average 500 December watts?
The concept of swappable batteries is, as above suspected, frequently thought of, but there are also obvious difficulties, beyond the moving tonne masses around, which after all automatic car washes seem to have in hand. A liquid hydrocarbon station that the tanker comes to once a day has, as that tanker leaves empty, about 30 tonnes of stock on hand. Will the swappable-battery station have 4,000 tonnes at all times? (On an equal-energy basis it would be 12,000 tonnes, but EV powertrains are more efficient.)
Graham, thanks for raising the numbers issue. It's always good to be specific. However..
Five megawatts is way too high. A mid-sized EV (Prius class) averages about 250 watt-hours per mile. Taking 200 miles per week as a "typical" driving range, that's 50 kWh / vehicle / week, or a 24-hour average power rate of 300 watts. A local station providing charging service for 100 neighborhood vehicles would therefore need a minimum electrical service of 30 kW. But since the whole point of EV battery charging as a responsive load is to use power "as available", that should be bumped to 1 kW per vehicle serviced, or 100 kW for a 100-vehicle neighborhood. 100 kW service for commercial buildings is not at all exceptional.
Assuming current-technology li-ion battery modules at 150 watt-hours / kg., a 100-vehicle station would be delivering an average of 5000 kg of charged battery modules per day. If the average residence time for a module at the charging station is 48 hours, that's a standing module inventory of 10 tonnes. Note that exchanges are always one-to-one, so the only deliveries to the station would be electrons and a trickle of replacements for modules that were being EOL'd.
Most stations of this class would probably be unattended. Remote monitoring and trouble alerts at the home office, plus a "call this number" sign for customers, and the address of the nearest alternate station.
BTW, I don't see lifting equipment as part of the operation. No opening the hood or even getting out of the car. Service would be from under the car--depleted battery modules excreted to a conveyor system at one end, and fresh modules fed in at the other end.
Kind of a modern version of a horse.
Len Gould 1.5.07
Roger: Your numbers look suspiciously low, eg. my estimates on another thread placed the average daily consumption for driving at 17 kwh / vehicle (3 miles / kwh x 50 miles per day) or 85 kwh / week. Presuming, per Graham, 30,000 kg / day of gasoline, then each station is servicing a neighborhood of perhaps 1000 x 7 = 7000 vehicles, or 1000 / day. To charge 17,000 kwh in eg 12 hrs would require a 3 phase 600 V service of 1,600 amps (given eg. 80% loading allowed by code).
But battery swapping at a central station is an over-complex solution anyway. An owner's auto can pick up it's required 17 kwh per day at home each night in 12 hrs from a 120 volt circuit at 12 amps. Or if quicker charge required, run a 30 amp 240 V plug to the garage (eg same as clothes dryer), which will re-charge it in 3 hours. Central charging / swapping stations are just not logical.
Len Gould 1.5.07
And plugging in each evening provides the added advantage of allowing the vehicle, on command from the drivers remote key-fob-control or timer, to run the A/C or heater to pre-condition the interior using cheap line power rather than battery power while driving, making it cheaper and more comfortable for the driver to enter. Toyota was already implementing this on their RAV4EV in 1998.
Len Gould 1.5.07
Also notable, T-Zero (small custom EV mfgr) has figured out a way to use the auto's existing inverter as charging rectifier, it's motor windings as an inductor / transformer. It's controller already has the battery managment logic programmed in because it's needed for regen braking, which means the car always carries it's charger around with it (and it costs no extra). BTW, they can also use these circuits to feed power back into the grid .... 9<]
Roger Arnold 1.5.07
Len, about the numbers: you're using 333 watt-hours / mile, 50 miles / day; I used 250 watt-hours / mile, ~ 30 miles / day. Not a large difference. 50 miles / day is 18,000 miles / year; I think the national average is more like 10 - 12 K / year. But the bigger difference in our assumptions is in the number of vehicles served by each station.
Big superstations off the freeway may indeed serve 1000 vehicles per day, and require daily tankerloads of fuel. But that's exceptional. Most neighborhood gas stations are doing well to sell one tankerload per week.
I used an even smaller number for cars serviced at each swapping station, because of the nature of the nature of a battery swap station. I see it as occupying the surface area of one parking space at the neighborhood convenience store. The capital cost for one swapping station can be quite small compared to a conventional gas station. It doesn't have to include large double-walled tanks for three grades of gasoline and accommodation for tanker trailers of hazardous liquid.
As to watt-hours / mile, one of the reasons I used the lower figure is that the availability of battery swapping facilitates lighter vehicles. It isn't necessary to carry 500 kg battery packs with a 250-mile range, because swapping would be so quick and easy. I think that in the first generation, the average swap-capable EV will carry only about 100 kg of battery modules, for a range of around 80 miles. They'll be mainly for commuting and shopping. For road trips, people will mostly rent mini-vans.
Swapping wouldn't replace home plug-in capability, it would supplement it. It gives one the option of an "instant recharge" any time it's needed.
Edward Reid, Jr. 1.6.07
I hope that, in the process of designing these "upholstered battery packs with wheels", someone remembers to include enough headroom so that those of us over 6' tall can actually sit up straight in them. Today, that is frequently not the case in vehicles referred to as "full sized". I realize that adequate headroom makes low drag coefficients more difficult to achieve, but I still put the potential for safe operation first on my list.
Regarding battery swapping, I suggest a visit to a warehouse which uses electric lift trucks. It might be possible to install the lifting equipment plus the storage and charging equipment in a single parking space at a convenience store, but I have my doubts. It might also be possible to exchange batteries without damaging the vehicle or the batteries, but my experience suggests it is not typical.
The real challenge might be designing a battery swapping station which can be operated successfully (and neatly) by a female commuter in business dress, since not all commuters are burly guys in coveralls and work gloves. The end result would likely be something like a "touchless car wash", in which a computer-controlled system identifies the vehicle and battery type, checks inventory to assure availability, aligns itself with the vehicle to assure extraction without damage, extracts the discharged battery and moves it to storage/charging, inserts the new battery and assures proper installation.
Roger Arnold 1.6.07
One of the things that has to happen before a battery swapping system can be successful is that a standard form factor has to embraced. A good standard for EVs would be a 40V module of standard rectangular dimensions. I don't know exactly what the standard dimensions would be, but in li-ion technology, the module should weigh in at about 5 kg. A single module would be suitable for a 40V automotive starting battery, or for powering an electric scooter or moped, an electric lawn mower, or quite a range of other things.
Given a standard voltage and form factor, the swapping station needn't stock different battery types for each make of EV. The mechanism for loading and unloading battery modules must of course be standardized as well. I see the station as using a robotic arm load modules into standard receiving ports, and probably another robotic arm to transfer depleted modules from an exit port to a conveyor into the charging station.
Within the vehicle, various arrangements might be used for moving the modules from the receiving port to their running position. The simplest is probably the best, and that would be to carry the modules in rectangular tubes that were integrated into the vehicle frame. The receiving and exit ports would just be covered openings at either end of each tube. The coverings would open for battery swapping, and pushing a charged module in one end of the tube would automatically push a depleted module out the other end.
There are a great many details that that description doesn't cover, but the gist is that it's a totally hands-off operation. The driver wouldn't normally even get out of the car. Just pull up to the changing station the same way one pulls up to an automated car wash, and let the robotic system do its thing. The significant works would all be in a pit under the car, which is why it doesn't need much surface area.