Many people expressed interest in the hybrid concentrated solar and natural gas plants discussed here: Game changer 3: New natural gas supplies “” great for low-cost climate action, bad for coal. So I asked guest blogger, Craig A. Severance, to do some research, and the result is below (first published here). Severance is co-author of “The Economics of Nuclear and Coal Power” (Praeger 1976) and a former Assistant to the Chairman and to Commerce Counsel, Iowa State Commerce Commission. He recently did one of the most detailed cost analyses publically available on new nukes (see “Exclusive analysis: The staggering cost of new nuclear power“).
By far the largest source of safe, clean energy that will never run out (i.e. renewable energy) available in the United States is the sunlight falling on the unused deserts of the Southwest. This attractive source of energy produces no nuclear waste, no carbon dioxide or mercury emissions, and none is imported from foreign countries.
According to the U.S. Department of Energy enough sunlght falls in just the unused, nonsensitive areas of our SW deserts to generate over twice the total kWh’s now consumed in the entire U.S..
SW Solar Now. In June, Interior Secretary Ken Salazar opened up 24 of the SW’s sunniest areas on Bureau of Land Management lands in six states to begin leasing for installation of up to 100,000 MW of solar power plants. (See here for article on the Interior Department announcement). The first plants could be operating within 3 to 4 years in these ideal locations, which were chosen for maximum clear sunny days and minimal impact on the environment or other land uses.
Sun Doesn’t Shine All the Time. Although the SW sunshine resource is enormous and largely untapped, critics of solar energy routinely note the sun does not shine all the time. The implication is that power is needed all the time, and since the sun is not always available, solar opponents say it would be foolish to invest in generating electricity from the sun.
Grid Can Use Solar. Utilizing solar electricity when the sun does shine is not really a major problem for the electric grid, until the percentage of power generated by solar reaches high percentages. This is because roughly 50% of the electrical capacity on the grid consists of load-following power plants (chiefly natural gas and hydroelectric), which can quickly reduce power output when a renewable resource such as solar or wind is available, and increase output when needed. The ability of the grid to absorb a high percentage of power from renewables has been documented by the U.S. Department of Energy and was discussed in my article “The Wind does NOT Blow Only 1/3 of the Time” here.
The output from a solar power plant also fits very well with the times when power is most needed. Most utilities see increased demand for electricity during daylight hours, with peak demands occurring on hot sunny days when a solar power plant produces well. By the same token, less power is needed at night.
It is generally agreed, however, that extending the percentage of our electricity generated by renewable power sources above 20-30% will require means to better regulate the grid (see “Smart Grid” article here), more efficiently supplement renewable power, or store it for later use.
Solar Thermal Offers More Choices. Solar photovoltaics (PV) require storage of their electrical energy output to extend their use into evening and cloudy hours. Methods the electric grid can use to store electrical energy include batteries, flywheels, pumped hydro or compressed air energy storage.
The “other” kind of solar power – Solar Thermal power — offers more choices to integrate with the grid to provide reliable power.
Instead of directly converting the sun’s rays into electricity, Solar Thermal plants use mirrored surfaces to concentrate sunlight to produce high temperatures. This is why they are also called Concentrating Solar Power (CSP) Plants.
The high temperatures are used to boil water to produce superheated steam to generate electricity. This different technology means there are now three different ways that Solar Thermal power plants can provide power when the sun is not shining:
1. Integrate a back-up source of heat (e.g. natural gas) to produce steam.
2. Produce excess solar heat during the day, and store that heat.
3. Grid storage of electrical energy (as with PV or wind).
This expansion of choices means that a Solar Thermal plant can function as a reliable source of “24/7″ power to the electrical grid.
Steam Generators Most Common Source of Electricity. The key to generating electricity for a century has been to produce high temperatures to heat water, superheat the steam (so it will not condense into water droplets inside the steam turbine and damage the blades), and then run this superheated steam past blades in a steam turbine to spin those blades to run a generator. After the steam passes through the turbine it is then cooled, and the water is re-used.
This same basic process is used in coal, oil, and most natural gas power plants. Even today’s nuclear power plants are just “a fancy way to heat water”.
Concentrating Sunshine to Produce Steam. Different Solar Thermal companies use different means to concentrate sunlight. They each cite their own advantages:
Troughs. Solar trough companies such as Skyfuel use long “trough” collectors (see picture at top, and immediately below) which rotate east-west during the day, to focus sunlight on tubes carrying hot oils. The hot oils then pass through a heat exchanger, to heat water into superheated steam.
Source: Skyfuel (Note trough rotates east to west as day progresses).
Trough supporters point to the long track record of the technology, including some 25 years of continuous production at the SEGS plants in Southern California, which has established clear performance and cost histories. Skyfuel’s key innovation is to develop a highly reflective coating film known as ReflecTech(TM) which eliminates the need for expensive curved glass mirrors for the troughs.
Flat Mirrors Focusing on Compact Linear Fresnel Reflector. Another “line” approach is typified by Ausra. In this approach, flat mirrors are ground-mounted and turn to concentrate reflected sunlight upward to a Compact Llinear Fresnel Reflector, which concentrates the sunlight onto a pipe carrying water which is turned into superheated steam (see figure from Ausra).
Ausra notes its technology saves costs by requring no curved mirrors, and does not use oil-to-water heat exhangers, as it uses water directly. Ausra’s mirrors are also tightly packed together, harvesting more sunlight per acre of ground. Ausra CEO Bob Fishman has said, “We can get twice as much steam per acre as power tower and twice as much as trough.”
Solar Power Towers. A radically different approach is the solar power tower, typified by Brightsource Energy and start-up eSolar. With the solar power tower, the solar field consists of tens of thousands of flat mirrors, each mounted with a 2-axis tracking motor to tilt the mirror in three dimensions to focus intense amounts of sunlight on a boiler mounted on the top of a tower. Superheated steam is produced in the boiler, and is fed to a ground-mounted steam turbine to generate power. See Brightsource Energy picture at top [right], and concept drawing below:
Proponents of the Solar Power Tower approach argue it has miles less piping and pumping, and the largest towers can operate at higher steam temperatures for better operating efficiency. They also claim higher kWh output on an annual basis because their mirrors can tilt upward to catch the lower sun in the wintertime.
Steam Plants in the Desert? While some locations may offer special opportunities to use water cooling, most solar thermal plants will be built with dry cooling. Keely Wachs of Brightsource Energy notes, “For our 410 MW Ivanpah site, the use of dry-cooling technology will reduce the projects’ overall water usage by 90%, from 1000 acre/ft to a little less than 100 acre/ft annually. 100 acre/ft is roughly the equivalent of 300 homes’ annual water usage. So we are producing enough energy to power 140,000 homes, while using 300 homes worth of water.”
[See also "The secret to low-water-use, high-efficiency concentrating solar power".]
Hybrid Solar/Gas: One Power Plant With One Steam Turbine. Because Solar Thermal power plants produce superheated steam to generate electricity in a steam turbine, they can be designed to share the same steam turbine generator as a conventional natural gas power plant. See, for instance, the schematic from Solar Thermal firm Ausra, below:
Instead of relying upon a separate power plant miles down the road to guarantee grid reliability to generate electricity when the solar plant cools off, just one plant can be built, with two sources of heat — sunlight and natural gas.
This saves on construction costs because only one steam turbine is needed instead of two. Also, much of the ancillary equipment such as controls, pumps, valves, etc. are not duplicated. Perhaps most importantly, duplicate sets of transmission lines are avoided.
Operating costs can be saved with just one team of workers, running one power plant, instead of needing two sets of skilled staff.
Finally, fuel costs for the natural gas component of operations may be saved by smoothly combining the two heat sources, gradually increasing natural gas use as the solar resource cools. This is expected to be more operationally efficient than ramping up and down a separate natural gas power plant.
This “hybridization” of solar thermal and natural gas power plants is an economical “bridge technology” approach to immediately reach fully dispatchable solar plants, providing “firm power” available to meet utility needs — whether or not the sun is shining.
Hybrid Solar/Natural Gas ”Load Following” Plants. In the ideal super-sunny locations in the desert Southwest where Solar Thermal plants are being erected, it is expected they will generate from solar, roughly 25-30% of the total kWh’s they could generate if they were able to operate 24 hours a day, 365 days of the year. This percentage is referred to as a “Capacity Factor”. (That’s actually very good, when you consider how many hours per day the sun shines.)
Most natural gas power plants in the U.S. actually are under-utilized, operated at an average of only 42% Capacity Factor. This is because they typically serve a “load-following” function, turned on only when needed, during the higher-demand parts of the day and year. When demand for power drops to minimum levels, they are turned off because “Base Load” power plants designed to run all the time, are already running all the time to provide this minimum (“base load”) demand. Most “Base Load” power plants are coal or nuclear plants.
If a “hybrid” solar/natural gas plant were also operated as a “Load Following Plant”, it might also be needed only 42% of year-round time. However, if 30% of year-round time it’s energy came from sunshine, the percentage of energy supplied by sunshine could be very high – 30% over 42% — or about 70% or more of the energy supplied.
This is good news for those seeking to cut fossil fuel emissions from power plants. Solar power could cut fossil fuel use (and hence CO2 emissions) by load-following power plants by roughly 2/3 compared to current patterns of operation for these plants.
Economics of Hybrid Solar/Natural Gas “Load Following” Plants. The relatively low annual use of a “Load Following” plant has traditionally favored power plants with low initial construction costs. Low construction costs are important when you don’t use it very much.
A Combined Cycle Gas Turbine power plant today costs roughly $1,100/kW – $1,500/kW to build, one of the cheapest power plant options. However, unlike sunshine, natural gas isn’t free, so total generation costs (at $7/MMBtu gas) are likely to be around 11 cents/kWh for a new natural gas “Load Following” plant in the first year of operation. (WIth no specific “carbon penalty” for fossil fuel.)
Costs for Solar Thermal plants are becoming known as several have already been completed. The Nevada One plant completed in 2007 was built for roughly $3,600/kW of capacity, using older trough technology with curved glass mirrors. With technology advancements, new proposals are now being estimated at lower costs. For instance, planned 20 MW plants in Algeria and Morrocco were recently estimated as costing only $2,500/kW to build.
Since a Hybrid Solar/Natural Gas plant will not cost as much to build as two separate plants, these cost ranges imply total generation costs of a Hybrid Solar Thermal/Natural Gas “Load Following” plant may run approximately 13 cents/kWh (after today’s 30% Federal Tax Credit for solar, and assuming $7/MMBtu natural gas), in the first year of operation. Since roughly 2/3 of the Hybrid “Load Following” plant’s ”fuel” is sunshine, the Solar Hybrid plant has a powerful hedge against future increases in fuel costs, including increases driven by “carbon penalties” on CO2 emissions.
What happens when the 30% Solar Tax Credit expires in 2017? Solar Thermal companies argue that during this time mass production of the mirrors and other components of CSP plants will bring down costs. At the same time, fossil fuel prices and carbon penalties may increase.
Possible Costs for Hybrid Solar/Natural Gas ”Baseload” Plants. Operating the same plant as a “Baseload” plant can lower overall generation costs/kWh because the same capital cost is spread over more kWh output per year.
A new natural gas power plant operated as a “Baseload” plant, for instance, may cost roughly 9 cents/kWh total generation costs, lower than when the same power plant is used only about half as much in “Load Following” mode.
Operating a Hybrid Solar/Natural Gas plant as a “Baseload” plant will spread its total capital costs over more kWh’s per year, however the extra generation would come entirely from burning more natural gas. WIth the same assumptions as above but with more usage, a Hybrid Solar/Natural Gas might have total generation costs/kWh of roughly 10 cents/kWh (with no specific Carbon Penalty).
Note the two choices (each seen as One Power Plant) are near parity in total generation costs, but the Solar Hybrid plant would have less exposure to long-term increases in fossil fuel prices and carbon penalties.
The Solar Hybrid plant can also eventually further reduce its fossil fuel use by adding storage.
Adding Solar Storage. As natural gas prices rise, Hybrid Solar/Natural Gas power plants can raise the percentage of energy from sunshine by storing excess solar energy generated during daylight hours.
Storing heat instead of electricity can be very physically efficient. For instance, Skyfuel notes that heat can be stored, then used later, with a 90% efficiency of heat recovered.
Adding storage isn’t cheap, however.
First, it generally will require increasing the size of the solar field so that more heat is generated during the day than would be used to generate steam during the day. Next, this extra heat would be stored in a heat storage fluid, such as molten salts. This requires heat exchangers and heat storage tanks for the molten salts.
Hybridization with natural gas will make sense in a great many cases to start, and storage can be added incrementally as years go by, and it becomes important to reduce natural gas usage.
Skyfuel’s William Felsher notes, “The optionality is there. You can add storage and more collectors to increase Capacity Factor later.” With Solar Thermal’s modular technology, ”enhancements can be made incrementally.”
Adding Solar to Existing Power Plants. With growth in demand flat or even negative, many utilities may currently have no need to build totally new power plants. However, adding solar to an existing power plant can help the utility meet Renewable Portfolio Standards and gain valuable operating experience with Solar Thermal.
One economical way to achieve a hybrid solar/natural gas power plant is to add a solar thermal collection field to an existing natural gas combined cycle power plant. The solar field of mirrors, lines, or troughs (or a small Solar Power Tower) would feed superheated steam into the existing steam cycles used by the power plant to generate power, as a supplemental heat source. Typically no new land is needed and transmission connections are already in place.
Savings of fuel consumption typically in the range of 10-15% may be achieved with a small solar addition. Skyfuel’s FuelSaver(TM) program encourages utilities to add typically 5 – 50 MW of solar power to existing power plants, to reduce fossil fuel use and gain valuable experience with Solar Thermal power. Ausra is also encouraging solar retrofits, after reducing coal usage at an existing power plant in Australia.
A Solid Choice for Utilities. Utility managers seeking to add carbon-reduced firm electricity generation can now look to Solar Thermal as a viable choice. Decades of experience have proven the technology, and recent advances are reducing its cost.
American and overseas companies have operating power plants, and are competing for utility RFP’s on utility terms that protect utilities from massive cost overruns. Announced projects for Solar Thermal plants in the U.S. already total over 6,000 MW.
The desert is blooming with power.
Related Posts:
- Concentrated solar thermal power (CSP) aka solar baseload is a core climate solution
- Concentrated solar power goes mainstream: Lockheed-Martin to build large CSP plant with thermal storage in Arizona
- World’s largest solar plant with thermal storage to be built in Arizona “” total of 8500 MW of this core climate solution planned for 2014 in U.S. alone
Previous in TP Climate Progress
Wholly enthalpy, Romm-Man! Speaking of dynamic duos, Boone and Ted are suggesting a “cash for clunkers” program for old coal plants. And, I sitll wonder if it is feasible to divert the used turbines to the constuction of plants such as suggested in this post.
But then – what about getting the power to where there’s less sunshine? I thought the major limitation to implementing solar on a wide scale here is that the SW sunshine can’t power air conditioners in Boston or Seattle. Isn’t there a bigger challenge in building transmission capacity, to deliver plains wind and SW sunshine to the cloudy/hilly coasts?
A couple of information sites:
http://nationalatlas.gov/articles/people/a_energy.html
http://tonto.eia.doe.gov/state/
Andrea Boykowycz, in the long term, a larger grid can be built to move electricity around from different regions. But it’s always going to be cheaper and wiser to use electricity as close as possible to its source.
While solar and wind are being built inland, along the coast, it would make sense to build nuclear and off-shore wind. Nuclear in the desert makes less sense because of severe water constraints. On the sea-shore, that won’t be an issue.
At some point you can dispense with the entire idea of baseload power. We can bundle demand response, baseload energy savings, wind, solar with natural gas firming (on site, or more likely, through exisitng plant) and see significant carbon reductions. We will need: 1) Continued subsidies for RE – solar especially. 2) the creation of very large ballancing areas – ideally 3-5 RTO like enetities. 3) carbon pricing, 4) Incentives for utilities such as decoupling, ownership of replacement resources and sharing mechanism for meeting carbon goals at the lowest cost (if traditionally regulated).
Not thermal, but solar…
“According to a survey from Photon Consulting, while it costs a German firm such as Ersol 1.01 dollars per watt to produce a solar cell, Chinese company Suntech can manufacture the same cell for 35 cents per watt.”
http://www.physorg.com/news169792072.html
Is $0.35 per watt not a game changer?
Some folks were getting excited about thin film reaching the $1 per watt threshold.
The relevance to thermal solar?
The ‘best economic choice’ might be solar PV close to the point of use during the sunny hours. Stick it on roofs and over parking lots in the urban areas. That would cut down on transmission line needs.
Then capture solar heat during the sunny hours and use storage to shift that production into evening peak hours. And, by making the thermal solar turbines “gas friendly” we’ve got backup sitting and waiting.
(Don’t forget that we can add biogas from land fills, sewage systems, farms, etc. into the NG pipeline.)
Let wind take care of the low demand hours.
If existing coal plants could be refitted (or even just the sites reused) to accomodate natural gas + solar or any combination of low-carbon or carbon-neutral power generation, then at least we wouldn’t need to worry about long lead times for siting or for building new power lines. The same efficiencies might be possible by upgrading existing natural gas plants to more efficient designs plus incorporating solar or wind power.
Nifty technology. How much will it cost?
In the section ‘Grid can use Solar’ the argument goes that variable generators (eg solar) can be accommodated today because 50% of *capacity* (as opposed to actual power supplied) is from sources that can be easily switched on and off. Now if such load-following capacity is there to augment the baseload when demand is high, then the total capacity (baseload + load-following) *is* presumably required in times of high-demand. If so, then what happens when that demand level occurs and there is ‘no’ wind or sun? I realise there are plenty of solutions to this issue (many of them well-presented in this piece), but it seems misleading to imply that because there is plenty of load-following capacity then a ‘high percentage’ of renewables can be integrated. Or maybe it depends what a ‘high percentage’ means?
Bob Wallace –
the $0.35/watt for Chinese PV refers -alas – only to the cost of the silicon in the cell, not the total cost.
So $1/watt is still the target game-changing cost for PV modules. . . but it is getting closer.
I’ll agree that rooftop PV complements solar baseload well.
This is a great post Craig
I have questions about the efficiency of the hybrid plants. Combined cycle gas plants are optimized for the fairly high temperatures from combustion of natural gas. For those who haven’t had thermodynamics the maximum possible efficiency is the temperature difference divided by the maximum temperature (in absolute degrees say Kevin instead of Centigrade). So the question arises as to what sort of compromises must be made to use the same turbine for both types of inputs? If the inefficiency created by the hybrid turbine is great enough, the benefits of the solar thermal part could be overwhelmed. I’ve yet to see this issue discussed. Although it is almost inconceivable that this wouldn’t have been considered. But, the loss of potential inefficiency should be discussed.
If the hybrid concept is indeed viable, it provides a nice pathway towards round the clock solar thermal with thermal storage. By adding additional heat collecting hardware and thermal storage capacity, the fraction of time that the turbine is operated
from solar can be increased at a later date. As the cost of natural gas increases over time this could provide a mechanism for a smooth transition towards a solar dominated system. I.e. without throwing out capital investment we can gradually move the system towards an ever greater fraction of solar input.
If we were wise, but you know we are not so very wise at all.
How easy it were to make a Paradise with clever humans. What a pity to look around and see the mess we have made…
Good, informative post, and I love the concept.
2 nagging questions – How many desert sites have 100 acre-ft/year of water available? And how many have utility-scale natural gas distribution?
Aren’t we talking about massive pipeline projects to get water and gas to where the sun shines?
Mark – thanks for correcting me. Thirty-five cents is part of the manufacturing cost, not all inclusive.
I did a follow up email with Photon, the company who released the report, and received the following back:
“Quick answer: $0.35/W is a processing cost turning wafer to cell. That cost is called “cell processing cost”. It varies by technology, location, size, operation factors (utilization rate, yield, etc.) That means company processing cost is very different among others. A weighted average cell processing cost is about $0.50-$0.55/W. But we see a cost close to $1.00/W (or even higher) and $0.30/W for the best practice.”
So apparently $0.35/W is not the cost of the silicon,but the price of taking a created wafer and turning it into a functioning solar cell. That price does not include the cost of the original wafer.
None the less, we are seeing some large decreases in the price of PV solar. Best retail prices around here have dropped by 25% or more.
And I would expect even more. We now have excess silicon refinement which is bringing/will bring down the cost of the wafer and added to this decrease in post-wafer manufacturing it bodes well….
What happened to the Smart Grid? It’s being developed. See Reuters: “Green dollars moving to smart grid, energy storage”
http://tinyurl.com/nqsdav
If we invested more money into the research, “when the sun doesn’t shine” wouldn’t be a problem. New solar panels are being developed that can store energy. I can’t believe this constant claim that we need more fossil fuels to get us our “baseload power”. We have to drop fossil fuels entirely. All of them.
What we need is centralized solar — See this from Green Inc.
“We can’t do it solely with established technologies, though it is mind-numbing when we consider how much existing technology remains on the shelf. We need to do it with new discovery. We need centralized solar, also known as concentrated solar, as well as indirect, or distributed solar. These two paths involve different technologies, but my fellow scientists are ready to set out on both courses. ….
When the sun is shining, we take some of the output from the PV system and feed it to a water-splitting electrolyzer to produce hydrogen and oxygen. Then we store the oxygen and hydrogen, either as a gas or by fixing it with carbon. Then, when the sun goes down, we can recombine the oxygen and hydrogen in a fuel cell in order to get the energy back out.
We are now working on a new design where the PV and the electrolyzer are combined. The recent discovery of the new catalyst enables this possibility.”
http://tinyurl.com/odahy3
People need to work on new solar discoveries and let’s dump the fossil fuels. We need to invest in clean energy, not natural gas.
Rockfish – as for water, and probably NG, we start with the sites that are close to urban populations. I believe that one thermal solar plant is using treated waste water from a small city and returning most of that water, post additional cleaning, to the aquifer.
Question re: water to steam.
What is actually happening in the “boiler”? Is the incoming water injected under high pressure or do the systems work in some piston-like fashion where one loading of water is changed to steam, the boiler allowed to vent into the turbine system thus dropping the pressure, and another dose of water introduced?
Bob –
Good research. I celebrate every drop in PV module prices. I also want the installation costs and inverter costs to drop – to zero.
Drop installation costs through building integration (BIPV). Drop inverter costs (and losses) with a DC standard. All electronic devices, batteries, and now LED lighting are DC. So why pay twice – converting PV DC to AC and then back to DC? At least cell phone makers have announced then intent to make a standard DC phone charger — a big step forward.
DC standard would be fine if we were building the country from scratch. But think of the cost of replacing every appliance, every air conditioner, every electric shop tool, every fan, light bulb, etc.
I doubt we’d ever recover much of that energy via the savings accrued from AC to DC loss to charge cell phones and run laptops. (Wart standardization is wonderful. Let’s have more of that. And are you aware that the “phantom load” from warts has apparently disappeared?)
Installation. We need ‘plug and play’ retrofit kits and integrated roofing. I’ve got a raised seam metal roof. There should be thin-film roofing panels that could be installed in the same way, making the new roof cost difference simply the cost of the thin film itself.
Craig Severance is misleading when he writes “most solar thermal plants will be built with dry cooling” and then refers to BrightSource Energy’s plans in the Mojave Desert at Ivanpah Valley as example.
That particular design incorporating dry cooling is the exception amongst the CSP plants proposed for the Arizona and California deserts. Most of those companies plan to evaporate water to the air in the condenser.
Natural gas is NOT clean energy. Natural gas drilling methods, especially slickwater hydraulic fracturing, suck up millions of gallons of water from lakes, rivers, streams, drinking water aquifers, mix that water with toxic chemicals, push the mixture into the ground via a well bored through the aquifer layer, pull up the gas along with no more than 60% of the toxic fluid, store the fluid into plastic lined pools which have torn or spilled over. Drinking wells have been contaminated in Wyoming and in Pennsylvania. Farm animals have died. Earthquakes have resulted in an area of Texas never known before for earthquakes. Do you homework and stop touting natural gas as a solution or even as a transition. Natural gas drilling has destroyed vast areas of Colorado, Wyoming and Texas. Now PA is being hit and next is New York State.
Bob –
Not replacing the whole AC infrastructure, just running parallel to it. And I would be satisfied if the new cell phone charger standard were robust enough to handle the majority of electronic devices, (though I doubt it will handle TVs or computers).
But imagine if power strips started appearing with a few standard DC outlets along with the AC outlets. Imagine how easy it would be to add a battery backup, also DC . . .
Mark – seems like what you’re wanting is a set of outlets in some rooms to let you easily charge your portable devices. You’ve left out TVs, computers, washing machines, blenders, all the big wattage draws.
That’s many steps down from switching from an AC to a DC grid. (And remember even if we could find ample justification for doing so, we would need two grids during the transition.)
I’m not sure we lose that much power in our switch from AC down to low voltage DC for our cell phones and whatever. They just aren’t pulling all that much to start with.
Better to hope for, I suspect, standardization of low DC voltages and standardization of plugs. Then you can have a multiple outlet wart in every room where you might want one and can plug in wherever. Or even uni-warts that have standardized 5vdc and 12vdc outlets. (The last three warts I’ve tested pull zero watts when plugged in but ‘at rest’.)
As for switching to DC so that we don’t need inverters for the solar panels on our roofs, I’m not sure very many people will put panels on their roofs. It’s just too much up front money for a lot of people and too much bother for others.
Additionally, and I’m not certain about this, I think there is an advantage in having inverters and putting one on each panel. That way if one panel is partially shaded/dirty it doesn’t pull down the performance of all the others.
I’ve got two racks of panels in my yard. There’s a month or so in the shortest day part of the year when the ‘lower’ panel is shaded by a tall Douglas fir. The output from both panels fall. And if the panel output voltage falls below the battery bank voltage the charge controller opens the circuit so that power doesn’t flow from the batteries back into the panels.
I’m planning on using my backup charge controller and separating the two panels so that each are independently controlled. It wouldn’t be as good as having separate inverters, but it would let the ‘upper’ panel pour a full load of sunlight into my batteries.
Having separate DC/AC inverters on each panel would mean that whatever the incoming DC voltage from a panel, it would be jacked to 110vac so that whatever wattage it is producing would be fed to the grid, however small it might be.
The author replies:
We have a good discussion going, touching on some key implications. I’ll comment on some of the key points:
1. Getting the Power to Where it is Needed: It helps to examine the maps of the 24 areas recently announced by BLM for solar farm development. http://energyeconomyonline.com/Interior_Dept_Solar_Plan.html
maps here: http://www.blm.gov/wo/st/en/prog/energy/solar_energy/Solar_Energy_Study_Areas.html
Some of the best high-intensity sunshine areas are fairly close to urban areas and/or existing transmission corridors. The Western Governor’s Association WREZ (Western Renewable Energy Zone) Initiative is approaching the transmission issues with sophisticated modeling, using the resource Zones identified in the Phase I report referenced in my article.
The output from these SW CSP plants will be used just in the SW for decades to come. There are major urban areas throughout this region that can use all of this power. The distances involved are comparable or even shorter than several Midwest transmission projects now planned to bring power from, e.g., North Dakota and Wyoming to major urban areas, plus the SW areas crossed are largely uninhabited desert.
2. Other Regions: While there is enough power available just from desert sunshine to power the entire U.S., other regions will be developing their own resources also. Wind power will continue to grow
both in the Midwest, and with offshore wind farms along the Eastern Seaboard. Geothermal resources where available will also be tapped as geothermal seems to be shaping up as a “first-choice” option whenever it is available.
3. “Baseload” (“Capital B”): I agree the whole idea of “Baseload” plants is now obsolete, if one means by this plants that are designed to run essentially all the time, and cannot be operated efficiently in load-following mode (e.g. nuclear and coal plants). Instead of this traditional “Baseload” concept, a far more valuable plant is one that is “Dispatchable”. A “Dispatchable” plant — such as the hybrid solar/natural gas plants discussed in this article — can provide power when needed, but also can reduce output or shut down when not needed.
4. “baseload” (“small b”): A far more useful concept of “baseload” is the plant with the lowest marginal operating cost. In other words, if you have a plant with zero fuel cost, you use it FIRST (as your “base” — the power used first) in the dispatch order. Thus, a wind turbine is actually categorized as a “baseload” power plant because its power would always be chosen to be used first, shutting down plants that require buying fuel to operate. Late at night, when CSP hybrid solar/gas plants must burn natural gas, energy available from wind power plants would actually take priority in the dispatch order. The ability to always be there when needed, but to “get out of the way” to allow zero-fuel-cost power to be used instead when available, is a description of a truly useful power plant.
5. Distributed PV versus centralized CSP: In California this is now a major discussion as the major utilities there have issued RFP’s for the utilities themselves to each own hundreds of MW’s of distributed PV, to be installed on commercial building rooftops, parking lots, etc. This has as noted, the advantage of providing power close to the source with no transmission lines. My sense is that both Distributed PV and centralized CSP plants will be used. Perhaps most importantly, the average homeowner or small business cannot erect a CSP plant, but virtually everyone with a rooftop can install PV. PV is therefore something WE can do. See: “Solar Panels: Tapping the Power of “We”" here:
http://energyeconomyonline.com/Tapping_the_Power_of_We.html
6. Justin raised the fact the grid needs the capacity of all the plants — including the load-following plants — at times of peak demand, and questioned therefore how this allows renewables to come into the mix. Dispatchable power plants such as the hybrid solar/natural gas plants in this article (or hydropower, or geothermal plants) can be counted upon to provide their share of this overall capacity. Non-dispatchable renewable generators such as wind farms provide zero-fuel-cost (small-b-baseload) energy. When the free power is available you simply shut down a load-following plant and save fuel cost (and CO2 emissions). You still HAVE that capacity as it is then being supplied by the wind power, the load-following plant simply got out of the way to save fuel.
7. The Smart Grid (and the utility-scale energy storage to be an integral part of any Smart Grid) will play a major role in utilizing non-dispatchable renewables.
http://energyeconomyonline.com/Smart_Grid_88MD.html
Recall that I mentioned CSP plants now have THREE choices to provide power when the sun isn’t shining: supplemental fuel (i.e natural gas), storing heat, AND having the grid store their electrical energy. This last choice WILL be used for the other renewable power sources. In reality even 20-30 minutes of utility grid storage and smoothing of variations in power output (to allow time for load-following plants to efficiently play their role) can allow enormous amounts of wind and PV power to enter the grid as zero-fuel-cost power. The technologies to provide this level of utility-scale storage of ELECTRICAL energy already exist and are being implemented.
CP readers are clearly onto the main implications. The overall message is we have more functionality. This is all good news.
Doug – water vs. air cooling.
I would imagine that the availability of water will help determine where the initial CSP sites are located. As I recall one of the sites being designed/built intends to use treated waste water from a nearby small city, further clean the water, then return it to the aquifer.
Long term those sites will be used up. Then is when, I suspect, we’ll see air cooled sites constructed.
You might wish to read Joe’s article on air cooling thermal solar plants. Here’s my takeaway sentence…
“Heller systems can reduce water consumption in a CSP plant by 97% with minimal performance impact.”
Downside? Higher up front capital costs which would drive sites close to water initially.
http://climateprogress.org/2009/04/29/csp-concentrating-solar-power-heller-water-use/
Bob,
That post was actually by Michael Hogan, Power Programme Director for the European Climate Foundation, and here’s my favorite quote:
“In the desert areas where CSP will thrive, the consumption of large amounts of water by conventional wet cooling systems is clearly unsustainable. Dry cooling alternatives will be required, and CSP will have to demonstrate its commercial viability despite the capital cost and performance penalties this will entail.”
But most of the companies getting US govt deficit-financed help to quickly build these plants (many on public land) are proposing to build them anyway with wet cooling for obvious reasons related to profit.
As for the use of reclaimed water in the condenser, I’m not impressed. Most of the reclaimed water will be evaporated, thus preventing it from recharging the desert aquifer.
Some notes on cooling:
1.Heller systems aren’t a big cost increase compared to conventional wet cooling (parabolic) towers. Couple hundred bucks to the kiloWatt electrical. Big deal.
2. Notice the figures in the article: 140,000 homes for 300 homes worth of water use. Even with wet cooling towers that’s 3,000 homes of water use for 140,000+ homes of electricity (a bit more power due to increased efficiency). Clearly, if water shortages were an issue, we’d be looking into increasing efficiency and supporting conservation in homes rather than electric power generation!
Basically, this implies that the concerns over power plant water use are exaggerated in the first place. Only once through water cooling uses relatively big amounts of water but these plants are typically using water from large natural waterbodies (seas, oceans, big lakes) – it’s just not economical anywhere else.
Inverter prices: look at the SolarBuzz website, inverter prices are around 72 cents per Watt. They are very efficient, typically over 90 and still improving. Evidence from the automotive industry suggests small capacity, standardized, mass produced inverters would result in at least a halving of the current price.
First Solar is claiming manufacturing cost of 83 cents per Watt at the module level. They will probably get under 70 cents per Watt modules before this year’s end, bet y’all a case of beer for it! (they won’t be selling anywhere near that price since they are the cheapest right now so they just get more margin and make a lot of bucks so they can continue to expand rapidly and remain one of the leaders in large scale PV).
Cyril R.,
No, the current wet cooling designs do NOT include a hyperbolic tower, they just evaporate right out of the condenser (small building near the turbine). But IF they decided conserve water in the desert by dry cooling with the Heller system, they’d have to ADD the hyperbolic tower (ie, dry cooling in the tower with NO plume of steam). This would add real money to the capital cost AND reduce the plant’s efficiency because you’re cooling with hot desert air.
Like I said, couple hundred bucks to the kWe. Not a big deal. Hyperbolic towers look big and expensive but in fact they’re dead simple things that add little cost compared to the rest of the powerplant equipment. Efficiency disadvantage is small because a Heller is efficient even in a hot dry climate, and the lower efficiency is partially compensated by reduced water costs (which tend to be high in arid areas).
http://theenergycollective.com/TheEnergyCollective/39691
Then why aren’t they doing it?
Why aren’t they doing it? Actually thermal plants in arid areas routinely use direct or indirect dry cooling. But a lot of wet cooling is still used yes. At least three reasons I can think of.
First, water use of a CSP powerplant compared to total power use is small. Look at the figures as were mentione by Brightsource above: 3,000/140,000 = about 2% of total households water use. Dry cooling brings that down to 0.2%. A 1.8% reduction in household water use isn’t going to make the difference in the event of severe water shortages.
Second, indirect dry cooling systems have only been perfected fairly recently, while most concentrating solar thermal electric powerplants have been built before that.
Third, water resource use wasn’t high up in the agenda until recently. Now that it is getting on the agenda we are realizing that powerplant evaporative water use is relatively tiny compared to total water consumption.
Fourth, pure economics, as with many other things. Why pay more for a powerplant when you can deplete aquifers at ultra low cost without paying for the external costs? Why pay more for imported desalinated water from the ocean to irrigate your field if you can get away with an unsustainable but cheap water use? Sadly, there is a lack of will to pay a bit more in securing sustainability of a vital resource.
Thanks Cyril, for confirming my central point.