Sunoba

Cost of solar power (19)

2012-03-10T21:46:00.000-08:00

In this series of blog posts, I like to analyse the cost of solar power for projects at utility scale, say around 100 MW. Every now and then, however, a smaller project comes along, which is suitable for my analysis and might have some public interest.

One such case is the University of Queensland’s solar array on the rooftops of four of the largest buildings at UQ. The whole system is rated at 1.22 MW peak output from 5,004 polycrystalline silicon panels on a total rooftop space of 8,200 square metres. The panels were supplied by Trina Solar.

This project was officially opened on 15 July 2011. Engineering, procurement and construction cost AUD 4.85 million, and UQ spent (or I should say invested) a further AUD 2.65 million on a visitor centre, viewing platform, additional ground works, and the development of a public user interface.

Let’s use the AUD 4.85 million figure for the cost of power generation, and not the combined figure of AUD 7.5 million.

A feature of the project is that Brisbane-based RedFlow has supplied a prototype 200kW zinc bromine battery bank that is connected to a 339kW section of panels. The outcomes of this installation will be interesting to monitor, since the zinc bromine concept offers the promise of relatively cheap storage of electricity.

At the time of writing, a full year’s output has not been measured, but UQ says the system is on track to deliver 1.75 GWhr per annum and save emissions of 1,600 tonnes of CO2 annually. (Note that much of the electricity generated in Queensland is from black coal, at around 900 kg CO2 per MWhr.)

I now evaluate the Levelised Electricity Cost (LEC) using my customary assumptions

• there is no inflation,

• taxation implications are neglected,

• projects are funded entirely by debt,

• all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,

• all projects have the same annual maintenance and operating costs (2% of the total project cost), and

• government subsidies are neglected.

For further commentary on my LEC methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view and Cost of solar power (10). Note that I am now using annual maintenance costs of 2% rather than 3% as previously.

The results are:

Cost per peak Watt AUD 3.98/Wp

LEC AUD 316/MWhr

The components of the LEC are:

Capital {0.094 × AUD 4.85 × 10^6}/{1,750 MWhr} = AUD 261/MWhr

O&M {0.020 × AUD 4.85 × 10^6}/{1,750 MWhr} = AUD 55/MWhr

By way of comparison, LEC figures (in appropriate currency per MWhr) for all projects I’ve investigated are given below. The number in brackets is the reference to the blog post, all of which appear with the title “Cost of solar power ([number])”:

(2) AUD 183 (Nyngan, Australia, PV)

(3) EUR 503 (Olmedilla, Spain, PV, 2008)

(3) EUR 188 (Andasol I, Spain, trough, 2009)

(4) AUD 236 (Greenough, Australia, PV)

(5) AUD 397 (Solar Oasis, Australia, dish, 2014?)

(6) USD 163 (Lazio, Italy, PV)

(7) AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)

(8) USD 228 (New Mexico, CdTe thin film PV, 2011)

(9) EUR 200 (Ibersol, Spain, trough, 2011)

(10) USD 231 (Ivanpah, California, tower, 2013?)

(11) CAD 409 (Stardale, Canada, PV, 2012)

(12) USD 290 (Blythe, California, trough, 2012?)

(13) AUD 285 (Solar Dawn, Australia, CLFR, 2013?)

(14) AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)

(15) EUR 350 (Lieberose, Germany, thin-film PV, 2009)

(16) EUR 300 (Gemasolar, Spain, tower, 2011)

(17) EUR 228 (Meuro, Germany, crystalline PV, 2012)

(18) USD 204 (Crescent Dunes, USA, tower, 2013)

(19) AUD 316 (University of Queensland, fixed PV, 2011)

[Note: all estimates made using 2% annual maintenance cost.]

The Capacity Factor for the UQ installation is 1,750 / (1.22 × 24 × 365) = 0.164, about what one would expect from fixed panels in a sunny location that had average daily exposure of 19.3 MJ/m^2 in 2011.

The LEC for the UQ installation is a little high compared to other recent projects such as the recently-opened Meuro project and the yet-to-start Moree Solar Farm (which at last report was having trouble securing finance so that construction could start). It is, of course, a small project built on top of existing infrastructure, so it could not be expected to deliver the world’s best LEC.

Patent accepted

2012-02-23T21:55:00.000-08:00

There is good news to report. Today I received notification from my patent attorney that my patent application 2007240126 has been accepted.

My attorney writes:

“The acceptance will be advertised in the Australian Patent Office’s Official Journal of Patents on 1 March 2012. The deadline for any third party opposition is three months from that date. If no opposition is filed in that period then the patent will be granted shortly thereafter.”

This patent application refers to my concepts for an evaporation heat engine and condensation heat pump, both in piston-cylinder and continuous-flow forms. It’s a high-level application, which covers the thermodynamic cycles and their uses, rather than actual details of the devices (although examples are given).

As the patent number suggests, the provisional application was filed in 2007, then converted into a Patent Collaboration Treaty (PCT) application thus giving me international protection for 18 months, and then applied for in the national phase in Australia.

What have I learned from this long process?

My dominant realisation is that inventors have to exercise fine judgement in patenting. There are familiar arguments for patenting an invention: protection is obtained and the concept can be promoted to potential investors. But on the other hand, patenting is certainly not cheap and is time-constrained. If an inventor hasn’t secured funding to take the invention further, then patent bills still have to be paid and perhaps the number of national jurisdictions pruned back when the PCT application reaches the national phase. So it’s a fine judgement – to patent, or to protect your work through other means (such as good old-fashioned secrecy).

To complete this post, I’ll just mention that I’m currently working on computer simulations of thermal storage in a bed of loosely packed rock. This storage mechanism is very well suited to my evaporation engine, as powered by passive solar heat collection (see www.sunoba.com.au). I expect to be able to report on the storage simulations within several months.

Cost of solar power (18)

2012-02-15T19:02:00.000-08:00

Today I shall analyse the cost of power from a utility-scale solar thermal power station. It’s the Crescent Dunes project, located just northwest of Tonopah, Nevada in the USA.

From my vantage point in Sydney, Australia, it seems there is a thundering herd of utility-scale solar projects under construction in the USA, helped along by a loan guarantee program from the US Department of Energy. A recent article in greentechsolar makes the case – almost USD 5 billion was guaranteed on the last day of the program alone (in September 2011), including to the Desert Sunlight (partial guarantee for USD 1.88 billion, 550 MW PV) and Antelope Valley (USD 680 million, 230 MW PV) projects. In the last week of the program, loans were also guaranteed to Mesquite Solar 1 (USD 337 million, part of a 700 MW PV project) and Crescent Dunes (USD 737 million, 110 MW, solar thermal).

This blitzkrieg of financial and construction activity makes a mockery of negative articles about solar energy that appear frequently in our local mainstream media.

The Crescent Dunes project is being developed by Tonopah Solar Energy LLC, a wholly owned subsidiary of SolarReserve LLC. The peak and annual power outputs are 110 MW and 504 GWhr. The project is being built on a 640 Ha site and will have a 195 m central tower and 17,500 heliostats each of 62.4 m^2. Energy will be stored in molten salt so that the project can deliver power for up to ten hours after dark. The project is due for completion in 2013.

SolarReserve raised USD 140 million in venture capital in 2008 and the DOE loan guarantee is for USD 737 billion. That’s a total of USD 877 million, whereas this site reports that the project will cost USD 900 million. Let’s stick with the latter figure.

I now evaluate the Levelised Electricity Cost (LEC) using my customary assumptions

• there is no inflation,

• taxation implications are neglected,

• projects are funded entirely by debt,

• all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,

• all projects have the same annual maintenance and operating costs (2% of the total project cost), and

• government subsidies are neglected.

The results are:

Cost per peak Watt USD 8.18/Wp

LEC USD 204/MWhr

The components of the LEC are:

Capital {0.094 × USD 900 × 10^6}/{504,000 MWhr} = USD 168/MWhr

O&M {0.020 × USD 900 × 10^6}/{504,000 MWhr} = USD 36/MWhr

(2) AUD 183 (Nyngan, Australia, PV)

(3) EUR 503 (Olmedilla, Spain, PV, 2008)

(3) EUR 188 (Andasol I, Spain, trough, 2009)

(4) AUD 236 (Greenough, Australia, PV)

(5) AUD 397 (Solar Oasis, Australia, dish, 2014?)

(6) USD 163 (Lazio, Italy, PV)

(7) AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)

(8) USD 228 (New Mexico, CdTe thin film PV, 2011)

(9) EUR 200 (Ibersol, Spain, trough, 2011)

(10) USD 231 (Ivanpah, California, tower, 2013?)

(11) CAD 409 (Stardale, Canada, PV, 2012)

(12) USD 290 (Blythe, California, trough, 2012?)

(13) AUD 285 (Solar Dawn, Australia, CLFR, 2013?)

(14) AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)

(15) EUR 350 (Lieberose, Germany, thin-film PV, 2009)

(16) EUR 300 (Gemasolar, Spain, tower, 2011)

(17) EUR 228 (Meuro, Germany, crystalline PV, 2012)

(18) USD 204 (Crescent Dunes, USA, tower, 2013)

[Note: all estimates made using 2% annual maintenance cost.]

The Capacity Factor for Crescent Dunes is 504,000 / (110 × 24 × 365) = 0.52, somewhat less than the 63% CF that I calculated for Gemasolar in Spain, which is a natural project for comparison. At the current exchange rate USD 1 = EUR 0.76, the Crescent Dunes LEC is much less (almost half!) than that for Gemasolar.

It’s also of interest to compare Crescent Dunes with Ivanpah. Both are under construction; both are heliostat-tower systems; Crescent Dunes has thermal storage whereas Ivanpah does not; both are Rankine cycle steam plants: Ivanpah has air-cooled condensers whereas Crescent Dunes has a hybrid cooling system (mainly dry cooling, with some wet cooling in summer); and the LECs are USD 231/MWhr (Ivanpah) versus USD 204/MWhr (Crescent Dunes).

For my next Cost of Solar Power analysis, I’ll try to get some figures on Asian projects.

Cost of solar power (17)

2012-02-06T17:42:00.000-08:00

It has been six months since I last blogged on the cost of solar power, during which time the press has been full of reports that the cost of PV modules has fallen sharply. Does that translate into a falling cost of solar power at utility scale? Let’s find out by analysing the Meuro Solar Park in Brandenburg, Germany.

To start, however, let’s remind ourselves about the concept of “learning rate” for PV, see figure below.

Figure 1: PV module price [USD2011/W] against cumulative PV installations [MW], from Breyer & Gerlach, “Global Overview of Grid Parity Dynamics”, Proc 2011 Solar World Congress, Kassel.

The learning rate is the reduction in module cost per doubling of installed capacity, and, as Breyer & Gerlach show, this was 22.8% over the period 1976-2003 and 19.3% over 1976-2010. In 2011, feed-in tariffs were wound back in various countries and production capacity increased, particularly in China. The outcome, as reported in Renewable Energy Focus (Dec 2011), was a 40% fall in PV panel prices in 2011. So it can be assumed we are still tracking at or better than the blue curve in Figure 1.

The Meuro PV Park is located in the German state of Brandenburg. The 152 Ha project consists of four fields on the site of a former brown coal mine, not far from the Lieberose project described in Cost of solar power (15). The 306,000 crystalline PV panels are from Canadian Solar, with installation complete in September 2011. According to this blog, installation was completed in three months, an outstanding performance. The peak output is 70 MW and the annual output is 70 GWhr. According to most reports I read, the cost of the project is EUR 140 million.

I now evaluate the Levelised Electricity Cost (LEC) using my customary assumptions

• there is no inflation,

• taxation implications are neglected,

• projects are funded entirely by debt,

• all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,

• all projects have the same annual maintenance and operating costs (2% of the total project cost), and

• government subsidies are neglected.

The results are:

Cost per peak Watt EUR 2.00/Wp

LEC EUR 228/MWhr

The components of the LEC are:

Capital {0.094× EUR 140 ×10^6}/{70,000 MWhr} = EUR 188/MWhr

O&M {0.020× EUR 140 ×10^6}/{70,000 MWhr} = EUR 40/MWhr

(2) AUD 183 (Nyngan, Australia, PV)

(3) EUR 503 (Olmedilla, Spain, PV, 2008)

(3) EUR 188 (Andasol I, Spain, trough, 2009)

(4) AUD 236 (Greenough, Australia, PV)

(5) AUD 397 (Solar Oasis, Australia, dish, 2014?)

(6) USD 163 (Lazio, Italy, PV)

(7) AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)

(8) USD 228 (New Mexico, CdTe thin film PV, 2011)

(9) EUR 200 (Ibersol, Spain, trough, 2011)

(10) USD 231 (Ivanpah, California, tower, 2013?)

(11) CAD 409 (Stardale, Canada, PV, 2012)

(12) USD 290 (Blythe, California, trough, 2012?)

(13) AUD 285 (Solar Dawn, Australia, CLFR, 2013?)

(14) AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)

(15) EUR 350 (Lieberose, Germany, thin-film PV, 2009)

(16) EUR 300 (Gemasolar, Spain, tower, 2011)

(17) EUR 228 (Meuro, Germany, crystalline PV, 2012)

[Note: all estimates made using 2% annual maintenance cost.]

The Capacity Factor for the Meuro PV park is 70,000 / (70 × 24 × 365) = 0.114, identical to that for the nearby Lieberose project, which is not a surprise. Note however the big drop in LEC between Lieberose and Meuro over a three-year period. The Meuro LEC is 21% more than for the Andasol solar thermal trough project, which admittedly is in a far sunnier location.

Details on other recent projects soon …

Beyond-Carnot heat pump (2)

2012-01-22T17:10:00.000-08:00

In my post on 8 December 2011, I introduced a heat pump with a superior Coefficient of Performance to a Carnot heat pump. The 2^nd Law of Thermodynamics is not violated because my heat pump does not operate on a closed-loop cycle (as is required for Carnot heat pumps). Today’s post explores how this out-performance depends on the inlet temperature to my heat pump.

Please read on …

By way of introducing the topic, the next part of today’s post is identical to my post of 8 December 2011.

In 2004 I invented a new heat pump which I grandiosely called the Barton Drying Engine (BDE). This has the following features:

> Mechanically expand a parcel of moist air; this lowers the temperature of the air as well as the partial pressures and densities of its component gases.

> Condensation forms immediately when dew point is reached, and any further expansion takes place along a moist adiabat.

> After the expansion is complete, collect the condensed droplets and remove them from the parcel of air.

> Re-compress the parcel of air back to ambient pressure; this involves an increase in temperature and partial pressures and densities. Re-compression takes place along a dry adiabat. Overall, work must be supplied to complete the cycle.

> The exhaust stream is hotter and drier than the inlet air stream.

I published a theoretical analysis of the BDE cycle in 2008 [1], with the main assumptions that air and water vapour are ideal gases with constant specific heat capacities. The principal results are shown in Figure 1.

Figure 1: Results from [1] for the loss-free condensation heat pump. The inlet air stream is saturated and at the temperature shown. The results also depend on the expansion ratio. Clockwise from top left: specific mass change in water vapour during cycle [kg/kg dry air], specific work output per cycle [J/kg dry air], temperature increase from inlet to outlet [°C], COP as a heat pump [dimensionless].

Here the Coefficient of Performance (bottom left diagram in Figure 1) was defined by

COP = m_a C_aP (T₄-T₁) / W

in which C_aP is the specific heat capacity of dry air at constant pressure, m_a is the mass of dry air in the parcel, T₄ is the outlet temperature, T₁ the inlet temperature and W is the work required to complete the cycle. In words, the COP is the desired output (heat increase in the parcel of air) divided by the necessary input (work to complete the cycle).

We now come to the new material in today’s post.

We are going to compare the COP for the BDE to the COP for a Carnot heat pump operating over the same temperature range. The emphasis will be on how the ratio COP_BDE : COP_Carnot varies with the inlet temperature.

Figure 2 shows the outlet temperature T₄ for the BDE as a function of the expansion ratio r for six different inlet temperatures T₁. Note that the inlet air stream is saturated.

In the subsequent discussion, COP values are calculated as follows:

COP_BDE = { m_a C_aP + [m_v – δm_v] C_vP } (T₄ – T₁) / W,

COP_Carnot = T₄ / (T₄ – T₁). [temperatures in K]

Here m_a and m_v are the original masses of air and vapour in the parcel of air that passes through the device, δm_v is the amount of vapour condensed, T₄ is the outlet temperature and T₁ is the inlet temperature. C_aP and C_vP are the heat capacities of air and water vapour at constant pressure, and W is the work required to complete the thermodynamic cycle. COP_BDE takes account of the heating of the water vapour component of the parcel of air. This correction is minor.

As seen in Figure 1 (bottom-left), COP_BDE does not vary significantly with inlet temperature, but does have a pronounced variation with the expansion ratio r. (This is true whether or not heating of water vapour is considered; that is a minor effect compared to the heating of the dry air component.)

Figure 3 shows the ratio COP_BDE : COP_Carnot for the six cases in Figure 2.

For T₁ = 5°C, the BDE in fact has sub-Carnot performance.

The ratio COP_BDE : COP_Carnot improves as the inlet temperature T₁ increases, rising to a peak value of about 1.5 for T₁ = 30°C at an expansion ratio of approximately 1.2. It is conjectured that the ratio would continue to improve for higher inlet temperatures. For all inlet temperatures there is a modest variation in the ratio COP_BDE : COP_Carnot as the expansion ratio r is allowed to vary.

The performance of the BDE depends on how much water can be condensed. But the saturation water content of air increases faster than linearly with temperature, suggesting that the beyond-Carnot performance will become more pronounced as the inlet temperature is increased. That has been confirmed by the results.

These results are affected strongly by inevitable losses in expansion and re-compression. I have analysed these losses for the continuous-flow case, but the outcomes will have to remain a commercial secret for now.

Finally, I should point out that this beyond-Carnot performance might also be achievable – in the loss-free case – with other condensing heat pump dryers.

Acknowledgement

Thanks to Anthony Kitchener for his conjecture about the importance of the inlet temperature. That has been confirmed by this study.

Reference

[1] N G Barton, “An evaporation heat engine and condensation heat pump”, ANZIAM Journal, 49 (2008), 503-524.

2011 Retrospective

2011-12-29T17:16:00.000-08:00

This is my 41st and last blog post for 2011. It’s a good opportunity to review what I have written about and to consider adjustments. I hope those who visited the blog (3,800 page views in total) have found topics of interest.

An index of postings is provided at the end. You’ll see that about half the posts relate to the cost of solar power. This was more or less as anticipated at the start of the year. I’ll comment further below on my methodology, as well as on the results and lessons I’ve learned.

My research this year remained focussed on evaporation heat engines and condensation heat pumps. The highlight was the investigation of the Expansion-Cycle Evaporation Turbine [2011-05-12, 2011-05-16, 2011-06-13], which culminated in a substantial paper accepted for the ASME Journal of Engineering for Gas Turbines and Power.

Despite best efforts, I didn’t get much traction with this idea from the manufacturers of gas turbines, huge companies all of them. But I persist in the expectation that the concept might find application to provide a power boost at times of peak demand in the electricity grid.

The ECET work also featured in a paper I presented to the 2011 Conference of the Australian Solar Energy Society [2011-11-12]. That was a comparison of bottoming cycles to boost the power output of solar hybrid gas turbines.

Personally, my biggest learning experience this year was the Fukushima disaster, triggered by the earthquake and tsunami on 11 March. I had been preparing a post about the cost of nuclear power at the time of the accident, and completed the post on 14 March [2011-03-14], before the full implications of Fukushima were clear. At the time, my stance was that I was prepared to accept nuclear power in a handful of countries that were technologically advanced and stable enough to manage all the issues, provided the comparative cost of power was assessed in an honest way. Japan was one of the few countries that I thought would be suitable.

The events at Fukushima made it clear to me that nuclear energy is to be avoided completely. Human nature simply cannot be trusted where there are commercial incentives to compromise on safety. If energy technology is local in scale, doesn’t pollute the air and is easily decommissioned, then commercial shortcuts won’t cause a long-term threat to our planet. But that’s not the case with nuclear – the effects of long-tail (i.e. rare, high damage) accidents might persist for millennia, and that is a risk that I find simply unacceptable. So I came to the same conclusion as the German government – phase out existing nuclear plants and don’t build any more!

My most viewed posts are “How long until fossil fuels are all used?” and “Atmospheric levels due to fossil fuels” [2011-03-15, 2011-03-20]. On an occasional basis, perhaps in 2012, I’ll provide updates for the first of these.

I investigated CO2 emissions in power generation, particularly how the cost of power would be affected by imposing a social cost on Carbon or a CO2 tax [2011-04-23, 2011-05-16, 2011-06-13, 2011-10-10]. The general conclusion here is that fossil power involves many externalities, which, if properly accounted for, would make coal-fired power much more expensive than it is at present.

I was pleased with two posts unrelated to the mainstream of my work. The first [2011-06-09] investigated the long-term effect of burning one kg of fossil fuel – how much would the CO2 emissions contribute to global warming, and how does that compare to the energy released at the time of combustion? The second [2011-10-19] looked at issues with CO2 uptake in algal ponds.

At the end of the year, I turned my attention to the condensation heat pump. I realised that the theoretical Coefficient of Performance, as I defined it, is better than Carnot, so that had to be a blog topic [2011-12-08]. I also investigated the performance of existing condensing heat pump dryers [2011-12-22]. This was an instance in which I have told the truth but not the whole truth, since I also looked at the expected performance of my condensation heat pump in continuous-flow format, as affected by inevitable turbine and compressor losses. That’s commercially sensitive information, so I won’t give the results at this stage.

What remains is the major thrust of the whole blog – the cost of solar power. I determined a methodology for cost comparisons and applied it to data I gathered on 16 large-scale solar projects around the world. My approach was simple but fair. The Levelised Electricity Cost (LEC) was assessed using the assumptions:

· there is no inflation,

· taxation implications are neglected,

· projects are entirely funded by debt,

· all projects have the same interest rate (8%) and payback period (25 years), which means that the rate of capital return in 9.4%,

· all projects have the same annual maintenance and operating costs (3% of the total project cost), and

· government subsidies are neglected.

Those assumptions are perfectly suitable for comparisons between projects, even if they wouldn’t be suitable for an investment case to financiers. In retrospect, I now think the maintenance costs are too high, so I’ll reduce the 3% rate to 2% in future.

Below I summarise the results of these investigations. The first two entries are for my evaporation engine at Wellington in inland New South Wales. The annual maintenance costs for these are retained at 4% of total project cost. For all the others, I’ve adjusted the annual maintenance cost to be 2% of total project cost. The entries with asterisks * are where I had to estimate annual output from claimed CO2 emissions avoided, always a risky process.

On these numbers, my evaporation engine would be highly competitive, world-beating even. However I’m the first to point out that more work is required to firm up my estimates.

Project	Cost	Cost	Capacity
	per peak Watt	per MWhr	Factor %
Wellington	AUD 1.38	AUD 173	13.0
(horizontal)
Wellington	AUD 1.42	AUD 128	17.9
(sloping)
Nyngan*	AUD 3.00	AUD 183	21.3
Olmedilla	EUR 6.40	EUR 503	16.6
Andasol	EUR 6.00	EUR 188	41.0
Greenough	AUD 5.80	AUD 236	32.0
Solar Oasis	AUD 5.75	AUD 397	18.8
Lazio	USD 2.08	USD 163	16.6
Kogan Creek	AUD 2.38	AUD 271	11.4
New Mexico	USD 4.64	USD 228	26.5
Ibersol	EUR 6.00	EUR 200	38.8
Ivanpah	USD 5.56	USD 231	31.5
Stardale	CAD 4.24	CAD 409	13.5
Blythe (first half)	USD 5.79	USD 290	25.9
Solar Dawn	AUD 4.80	AUD 285	21.9
Moree Solar Farm*	AUD 6.15	AUD 263	30.4
Lieberose	EUR 3.03	EUR 350	11.4
Gemasolar	EUR 14.52	EUR 300	63.1

In the coming year, I’ll continue with research on the evaporation heat engine and condensation heat pump. I’ll also persevere with this blog, again with the prime focus being the cost of solar power. The price of PV systems fell steeply in 2011, so I expect I’ll observe a significant reduction in the cost of installations. We’ll see.

I close with an index of my posts for 2011 and my best wishes for 2012.

2011-01-02 Welcome to my new blog

2011-01-07 Cost of solar power – 1

2011-01-11 Cost of solar power – 2

2011-01-22 Research update

2011-01-28 Cost of solar power – 3

2011-02-28 Cost of solar power – 4

2011-03-03 Cost of solar power – 5

2011-03-14 Cost of nuclear power

2011-03-15 How long until fossil fuels are all used?

2011-03-20 Atmospheric CO2 levels due to fossil fuels

2011-03-31 Cost of solar power – 6

2011-04-14 Cost of solar power – 7

2011-04-23 Real cost of coal-fired power

2011-04-27 LEC – the accountant’s view

2011-05-03 Cost of solar power – 8

2011-05-12 Research update – ECET etc

2011-05-16 Cost of power – ECET

2011-05-17 Cost of solar power – 9

2011-05-21 Cost of solar power – 10

2011-06-05 Cost of solar power – 11

2011-06-09 Atmospheric temperature increase due to coal combustion

2011-06-13 Savings in CO2 emissions – ECET

2011-06-15 Cost of solar power – 12

2011-06-20 Cost of solar power – 13

2011-06-21 Cost of solar power – 14

2011-07-01 Cost of solar power – 15

2011-07-02 Cost of solar power – 16

2011-07-16 ECET paper accepted

2011-07-27 Colloquium at UniMelb

2011-08-03 AuSES Sydney talk

2011-08-15 Yet more on LEC

2011-08-22 2011 Solar World Congress

2011-08-25 Blythe switches to PV

2011-09-30 2011 Solar World Congress

2011-10-10 Cost of coal-fired power - more

2011-10-19 CO2 for algal fuels

2011-10-27 Climate Science for Business Champions

2011-11-12 Paper accepted for AuSES

2011-12-08 Beyond-Carnot heat pump?

2011-12-22 Condensing heat pump dryers

2011-12-30 2011 retrospective

Condensing heat pump dryers

2011-12-21T19:51:00.000-08:00

In my last blog post, I discussed why the Barton Drying Engine has a remarkable Coefficient of Performance as a heat pump. Moreover the BDE is a drying device as well – it heats and dries the air at the same time. That leads to a question – how good are existing condensing heat pump dryers? Perhaps the answer to that question will encourage me to pursue putative financiers with greater gusto.

The answer is now provided …

The figure below is a schematic of a conventional condensing heat pump dryer, such as is now widely available. In this design, moist air from the tumble dryer is cooled in the evaporator for the refrigerant circuit. This causes condensation of some water vapour to water, with water removed from the circuit. The dry cold air is then warmed in the condenser for the refrigerant circuit, before being returned to the tumble dryer where it again picks up moisture. Two necessary components not depicted in the figure are an inline filter and a blower to keep the air circulating.

Schematic of a heat pump dryer. Here black lines indicate airflow, blue lines indicate flow of refrigerant, and the purple squares are heat exchangers (evaporator and condenser for refrigerant). The X on the refrigerant circuit is a throttling valve that lets condensed high-pressure refrigerant escape to the evaporator.

Palandre & Clodic [1] have experimentally studied the performance of condensing heat pump dryers. Their paper also includes dryers based on mechanical steam compression, but I won’t discuss that aspect here.

For the conventional dryer studied by P&C, temperatures at the various parts of the circuit are:

drying temperature, Td 40°C

evaporator temperature, Te 15°C

condenser temperature, Tc 60°C

blowing temperature, Tb slightly less than Tc

Introduce the notation:

Qe heat transfer in evaporator [J_th/sec]

Qc heat transfer in condenser [J_th/sec]

W work done by compressor in refrigerant circuit [J_e/sec]

W′ work done by blower and tumble motor [J_e/sec]

COP_heatingQc / W

global COP_heatingQc / (W+W′)

P&C give the results

COP_heating = 3.35 ([1], Table 3),

global COP_heating = 2.2 ([1], Figure 13).

From these it follows that

(W+W′) / W = 3.35 / 2.2 which gives W′/W = 0.52.

P&C Figure 14 gives the total energy consumption of the heat pump dryer as 1,730 Wh = 1730 × 3600 J in 105 × 60 seconds. It follows that

W+W′ = 1730 × 3600 / (105 × 60) = 989 J /sec.

Then since W′/W = 0.52, the various quantities can be calculated explicitly:

W = 650 J_e/sec,

W′ = 338 J_e/sec,

Qc = 2,179 J_th/sec.

That tells us the nameplate performance of this particular condensing heat pump dryer. Let’s now interpret the results …

Neglecting heat exchanger losses, heat transfer Qc raises the temperature of the air from Te to Tc, an increase of 45°C. But note that the overall effect is to raise the air temperature from Td to Tc, an increase of only 20°C from inlet to outlet. Thus to compare P&C results with my drying engine (BDE), COP_heating as calculated by P&C needs to be multiplied by 20/45:

(1) COP_{heating, comparison} = 3.35 × 20/45 ≈ 1.49.

Note also that the comparative global COP would be even lower, namely

(2) global COP_{heating, comparison} = 2.2 × 20/45 ≈ 0.98.

Heat exchanger inefficiencies are not expected to dramatically alter the above conclusions. These would mean that the temperature of the air circuit would not reach Te after the evaporator; rather it would be Te + δe. Nor would the temperature reach Tc after the condenser; rather it would be Tc – δc. Thus the temperature increase over the condenser would be Tc – δc – (Te + δe) = Tc – Te – (δc+ δe). Equation (1) then would become

(3) COP_{heating, comparison} = 3.35 × (20 – δc) / (45 – {δc + δe}).

Provided the condenser and evaporator are both reasonably efficient, then estimates (1) and (3) should not differ greatly.

To sum up …

The COP quoted by P&C is as conventionally defined in heat pumps. However it overstates the actual performance of condensing heat pump drying by a factor of 45/20 = 2.25. Equation (1) is a better way to assess the heat pump effect for drying. Once other power requirements are taken into account, equation (2) gives the actual performance that a user would see.

I have compared P&C’s results with my BDE condensation heat pump (in continuous-flow form). At the present time, the results are a commercial secret.

Acknowledgement

Thanks to Anthony Kitchener for comments on this work and for providing the reference by Palandre & Clodic.

Reference

[1] L Palandre & D Clodic, “Comparison of heat pump dryer and mechanical steam compression dryer”, International Congress of Refrigeration, Washington, D.C. (2003).

Beyond-Carnot heat pump?

2011-12-07T21:32:00.000-08:00

Figure 3 below shows a heat pump that has a Coefficient of Performance superior to a Carnot heat pump operating over the same temperature range. But that contradicts the 2nd Law of Thermodynamics. How is this paradox to be resolved?

Please read on …

In 2004 I invented a new heat pump which I grandiosely called the Barton Drying Engine (BDE). This has the following features:

Mechanically expand a parcel of moist air; this lowers the temperature of the air as well as the partial pressures and densities of its component gases.
Condensation forms immediately when dew point is reached, and any further expansion takes place along a moist adiabat.
After the expansion is complete, collect the condensed droplets and remove them from the parcel of air.
Re-compress the parcel of air back to ambient pressure; this involves an increase in temperature and partial pressures and densities. Re-compression takes place along a dry adiabat. Overall, work must be supplied to complete the cycle.
The exhaust stream is hotter and drier than the inlet air stream.

Here the Coefficient of Performance (bottom left diagram in Figure 1) was defined by

COP = m_a C_aP (T₄-T₁) / W

Let’s remind ourselves about Carnot heat pumps, as shown in Figure 2. This depicts a theoretical heat pump that takes heat energy Q_L from a reservoir at temperature T_L and delivers heat energy Q_H to a reservoir at temperature T_H. This requires work W.

Figure 2: Illustrating heat transfer and work requirement of a heat pump.

The COP of the heat pump is COP = Q_H / W. But conservation of energy gives Q_L + W = Q_H and so

COP = Q_H / (Q_H – Q_L) = 1 / (1 – Q_L/Q_H) .

The 2nd Law of Thermodynamics gives that for a reversible process

Q_L/Q_H = T_L/T_H (temperatures in Kelvin),

so that the COP can be written

COP_Carnot = 1 / (1 – T_L/T_H) = T_H / (T_H – T_L).

This is the highest COP that a heat pump operating on a closed cycle between T_L and T_H can have.

Now let’s take the COP shown in Figure 1 (bottom left) for the case when T₁ = 25°C and compare it to the Carnot COP (with T_L = T₁ and T_H = T₄). I’ll now also explicitly take account of the water vapour that passes through my heat pump as follows

COP_BDE = { m_a C_aP + (m_v- δm_v )C_vP } (T₄-T₁) / W.

Here m_vis the mass of vapour in the parcel of air at the inlet and δm_v is the mass of vapour that condenses into water. C_vP is the specific heat capacity of water vapour at constant pressure. (This expression for COP_BDE gives almost identical results to the previous COP expression used in Figure 1.)

Figure 3 has the results …

Figure 3: Plots of COP_BDE and COP_Carnot for the case when the inlet air is at 25°C and saturated.

But this says COP_BDE is greater than COP_Carnot, which is not possible according to the 2nd Law of Thermodynamics. I have done similar plots for other saturated inlet conditions, with similar results: COP_BDE > COP_Carnot. Assuming I haven’t made any numerical mistakes (I have checked very carefully!), and assuming the 2nd Law of Thermodynamics isn’t wrong (it isn’t!), how can this be so?

The paradox is resolved with the aid of Figure 4.

Figure 4: Schematic diagram of the condensation heat pump.

In Figure 4, the BDE is a mechanical device indicated by the yellow box. It takes in work W and moist air at temperature T₁, and gives out condensed water at temperature T₃ and drier air at temperature T₄. Let h denote specific enthalpy and subscripts a, v and w denote dry air, water vapour and water respectively. The change in enthalpy of the water vapour that condenses is

Δ = δm_v× { h_v(T₁) – h_w(T₃) } = δm_v × { h_v(T₁) – [h_v(T₃) – L(T₃)] }

in which L(T₃) is the latent heat at T₃, i.e. the specific enthalpy required to evaporate water. Since we are assuming ideal gas theory with constant specific heats, it follows that

Δ = δm_v × { C_vP (T₁ – T₃) + L(T₃) }.

Both terms in Δ have the same sign, and Δ is large and positive.

By conservation of energy, if the condensed water loses an amount Δ in enthalpy, then the gaseous components that pass through the heat pump must gain enthalpy (W + Δ). Therefore the COP of the BDE heat pump is

COP_BDE = (W + Δ) / W = 1 + (Δ/W).

As an illustrative example, consider the following data from the loss-free computations published in [1]:

inlet temperature: T₁ = 25°C and saturated

lowest temperature: T₃ = 4.9°C

outlet temperature: T₄ = 52.7°C

expansion ratio: r = 1.6

water condensed: 0.01067 kg/kg dry air

work requirement: W = 1,765 J/kg dry air

latent heat: L(T₃) = 2,489,600 J/kg water

With the above data, Δ/W evaluates to 15.3, and so COP_BDE is 16.3, which agrees exactly with the results shown in Figure 3 at r = 1.6. (For the same temperature range, COP_Carnot = (52.7 + 273.15) / (52.7 – 25) = 11.8, also as shown in Figure 3.)

Thus the gas mixture (air plus vapour) that passes through the BDE has an excellent COP, which is sustained by the large loss of enthalpy in the vapour that is condensed.

Finally, to resolve the paradox in words …

A Carnot heat pump must operate on a closed-loop cycle, with the state of the device at the end of the cycle identical to its state at the beginning. Also the internal workings of the device must not generate any entropy, so that everything is reversible.

It’s easy to see from Figure 4 that the BDE heat pump does not satisfy this condition, and its COP, as I have defined it, is therefore not subject to the Carnot constraint. The expansion and compression processes are indeed reversible, but removal of condensate means that the conditions at the end of the cycle are not the same as those at the beginning.

To finish, a brief practical comment. Theoretically the BDE has great promise. I am currently evaluating how the performance is affected by inevitable losses in the device.

Reference

[1] N G Barton, “An evaporation heat engine and condensation heat pump”, ANZIAM Journal, 49 (2008), 503-524.

Paper accepted for AuSES

2011-11-11T21:30:00.000-08:00

I learned this week that my paper entitled “ECET Boost to Solar-Hybrid Gas Turbines” has been accepted, subjected to minor modifications, for the peer-reviewed section of the 2011 Conference of the Australian Solar Energy Society (AuSES).

The abstract for the paper is as follows:

In the SOLGATE project, a solar-hybrid gas turbine system was developed, built and tested (ORMAT et al., 2005). The concept involves gas turbine systems in which air is first compressed, then heated through a combination of concentrated solar radiation and gas combustion, and finally passed through a turbine to generate power. The hybrid nature of the system enables savings on fuel and emissions, but also power delivery when the sun is not shining. The exhaust from the gas turbines is very hot, and therefore suitable for some kind of bottoming cycle to boost the output.

Recently, the author (Barton, 2012) analysed a new bottoming cycle based on evaporative cooling of hot air at reduced pressure. This concept is called the Expansion-Cycle Evaporation Turbine (ECET). Barton showed that the ECET can typically boost the output of utility-scale open-cycle gas turbines by around 20%, without any extra fuel consumption or emissions, and at a specific capital cost expected to be no more than that for the upstream gas turbine. With these attributes, the ECET is expected to be suitable for peak duty in the electricity grid.
The present work investigates the suitability of the ECET to boost the power output of solar-hybrid gas turbines such as in the SOLGATE project. Power boosts of approximately 20% are expected. The Levelised Electricity Cost (LEC) with ECET boost is also compared to that for two other bottoming cycles – the Rankine steam cycle (which gives the solar-hybrid combined-cycle gas turbine) and an Air Heat Recovery Turbine Unit (AHRTU, Romanov et al., 2010). In these comparisons, the three bottoming cycles give a 10-14% reduction in the LEC when compared to the original solar-hybrid gas turbine. The LEC for the ECET-boosted system is marginally lower than that for the Rankine-boosted system, which in turn is marginally lower than that for the AHRTU-boosted system. The percentage by which the LEC is improved by the bottoming cycles does not depend strongly on the capacity factor.

This study provides a preliminary assessment of the benefits of three bottoming cycles when used in conjunction with solar-hybrid gas turbines for power generation. According to this analysis, all three cycles clearly lead to benefits; the output is boosted by around 17-22%, the levelised electricity cost is reduced by around 10-14%, and CO₂ emissions are reduced by around 14-18%.

The AuSES conference will be held in Sydney from 30 November to 2 December 2011.

Climate Science for Business Champions

2011-10-26T17:46:00.000-07:00

I’m writing this post to publicise an upcoming event:

Climate Science for Business Champions 2011

3.00 – 6.00 pm, Thursday, 17 November

CSIRO Auditorium, Lindfield

From the publicity for the event:

Climate Science for Business Champions will provide an opportunity for business, industry, community leaders and the general public to hear accurate and verified information about global warming, the problem, the causes and the need for solutions and leadership.

Over the course of this 3-hour forum, climate science experts will provide information that is easy to understand, and participants will have an opportunity to ask questions about what climate change means for their business and communities.

Importantly, the forum will enable delegates to take practical knowledge back into their workplaces and communities with the confidence to lead change.

I am promoting this forum for two reasons – firstly it is a cause that I’m passionate about and secondly because I played a minor role in its development. The suggestion to hold the forum came after a meeting held by Business Events Sydney, for which I’m an honorary ambassador. Subsequent development of the concept was carried out by Science & Technology Australia, the peak body for science advocacy in Australia.

For the list of speakers, further details and registration, please visit the Science and Technology Australia website and follow the link to “Climate Science for Business Champions”.

CO2 for algal fuels

2011-10-18T20:17:00.000-07:00

Introduction

I’m grateful to Warren Flentje of the University of Melbourne’s Energy Institute for a recent discussion on issues associated with algal production of biofuels from power station flue gas. Such biofuels are expected to be economically important in the future, and they also enable re-use of CO2 that would otherwise go directly to the atmosphere in the flue gas.

Algal fuel production can take place in seawater, so water availability is not a show-stopper. However other major issues to be resolved include

· the very large amount of hot flue gas to be handled,

· how to dissolve the CO2 component of this gas in water,

· the amount of water required, and

· the energy required to pump the water.

Here, some preliminary estimates are made for how my Evaporation Engine [1] might be of assistance in this process. With respect to algal fuels, I’m learning on the job; corrections or comments to this post are welcome.

Exhaust gas flow-rate from a 1,000 MW coal-fired power station

Assumptions:

· overall efficiency of the Rankine-cycle steam plant is 33%

· energy content of coal is 26 MJ/kg

· Carbon content of coal is 65% by mass

· coal feed rate is r kg/sec

Considering the energy requirements of the power station, r × 26 ×10^6 = 10^9 / 0.33, so r = 117 kg/sec, comprising 76 kg/sec of Carbon, or 76/0.012 = 6313 moles/sec.

Carbon reacts with air to produce one mole of CO2 from each mole of C, so 6313 moles/sec of O2 are required, which means the O2 mass flow-rate is 6313 × 0.032 = 202 kg/sec.

Now suppose the inlet air to the power-station is at 300K with ambient pressure 101300 Pa and density 1.176 kg/m^3. This air contains approximately 21% O2 by volume, so the partial pressure of O2 is 21273 Pa. At 300K, the ideal gas constant for O2 is 260 J/(kg.K), so the density of O2 in the air is 21273 / (260 × 300) = 0.273 kg/m^3. If 75% of the O2 is combusted, the required volume flow-rate Fa at the inlet is given by 0.75 × 0.273 × Fa = 202, so that Fa = 987 m^3/s. The mass flow-rate of air is 987 × 1.176 = 1161 kg/sec.

Algal fuel output

If the power station operates at 100% capacity factor, the amount of Carbon consumed per year is 76 × 3600 × 24 × 365 = 2.40 × 10^9 kg. If all the Carbon is converted by algal production into fuel with average chemical composition CH2, then the mass of algal fuel is 2.80 billion kg. At a density of 0.9 kg/litre, that gives 3.11 billion litres, or 19.4 million barrels at 160 litres/barrel.

At USD 100 per barrel, that output is worth USD 19.4 billion, and would be enough to meet the earth’s oil demand for approximately 5.4 hours (at a global consumption rate of 86 million barrels per day).

If the algal fuel system produces 60,000 litres of algal fuel per Hectare per year, the land requirements of the algal system would be 5.18 × 10^4 Ha = 518 km^2.

Power output of the Evaporation Engine

Assume that the hot exhaust from the coal-fired power station is used in the Evaporation Engine [1] to generate power and to cool the air stream.

Make the following assumptions:

· coal-fired power station exhaust temperature is 180°C

· partial pressures of exhaust are Pair = 98.3 kPa, Pvap = 3 kPa; here, it is assumed that CO2 and O2 have similar ideal gas properties for the purposes of operation of the EE, which is an assumption that would need to be modified in a thorough study

· expansion ratio of the EE is 2.5

· temperature of injected water is 20°C

Then, from the thermodynamic model for the EE [1],

· loss-free power output is 24.5 kJ/kg air

· back-work ratio is approximately 0.8

· water consumption is 0.046 kg H2O per kg air

· EE exhaust stream is saturated and at temperature 46°C

After allowing for inevitable engine losses, the power output is estimated at 17 kJ/kg air. The total power output from the EE would be 1161 kg air/sec ×17 kJ/kg air = 19.7 MW, or 2% of the primary output from the power station. The water requirement for the EE would be at least 1161 × 0.046 = 53 kg/sec, which, as will now be shown, is only a tiny fraction of the water requirement for dissolving the CO2.

Water requirement to dissolve CO2

The exhaust stream from the EE is transferred at ambient pressure into a closed vessel in which CO2 is dissolved into water. As assumed earlier, 75% of the O2 in the airstream has been replaced by CO2, which implies the partial pressure of CO2 at the entry to the vessel is approximately 0.15 bar. (The presence of water vapour in the EE exhaust complicates this estimate and would need to modelled properly in a careful analysis.)

How might the CO2 be dissolved? I can imagine some sort of a counter-current process, in which the air progressively loses its CO2 component whilst the molarity of the CO2 in the water progressively increases. The air could be sparged through the water; or perhaps better mass transfer rates could be achieved if small water droplets could be introduced into the vessel. Whatever, there will be a requirement to pump water around, and that will be estimated in a moment.

First let us calculate the water requirement. By Henry’s Law (see e.g. [2, p.539]), the amount of CO2 dissolved in water is given by

PCO2 = kH × MCO2

in which PCO2 (bar) is the partial pressure of CO2 above the water, MCO2 is the molarity (moles/litre) of dissolved CO2, and Henry’s constant, kH, actually varies with temperature (i.e. is not a constant). Using data from [2] and [3], kH is estimated to be 48 bar / {moles CO2/litre} at the exhaust temperature of the Evaporation Engine (46°C).

From Henry’s Law, the molarity of dissolved CO2 will be

MCO2 = PCO2 / kH = 0.15 bar / [48 bar{moles CO2/litre}^-1] = 0.0031 moles CO2/litre

At this partial pressure for CO2, 1/0.0031 = 323 litres is required to dissolve 1 mole of CO2, and 323 litres/mole × 6313 moles/sec or 2.04 × 10^6 litres/sec of water is required to dissolve the CO2 output from the power station. This water requirement is nearly 40,000 times that required to operate the EE.

In simpler units, 2040 m^3/sec of water is required to dissolve the CO2 output of the power station. This very large amount of water needs to be transferred from the sea, then used to dissolve the CO2, then pumped to remote algal ponds, and finally returned to the ocean.

At the very minimum, a head of 5 m water pressure or 50 kPa would be required. The corresponding power requirement to pump the water is 2040 × 5 × 10^4 = 102 MW, which must be viewed as optimistic.

Conclusions

Let me state the obvious. Although the estimates presented here are preliminary, they nevertheless highlight difficulties involved in cooling the exhaust stream from a 1000 MW power station exhaust, dissolving the CO2 component in water, and managing water flows through a large expanse of algal ponds.

The EE could certainly be used to cool the coal-fired power station exhaust. At the same time, the amount of power generated in the EE would contribute towards the power required to transfer CO2 from the EE exhaust stream into water and pump the water around the algal ponds.

A final comment on the Evaporation Engine is pertinent. If the inlet temperature for the EE is 180°C, the engine could not be operated in continuous-flow mode; rather a piston-in-cylinder mechanism would be required. The resulting engine that would process all of the power station exhaust would be very bulky, although it should be feasible to construct it at specific capital cost significantly less than $ 1 million/MW. The thermodynamic cycle of the piston-in-cylinder EE is protected by patent applications, and essential aspects of the mechanical principle to execute the cycle are maintained as commercial secrets. Introductory details of the EE are available at www.sunoba.com.au.

Thanks to Warren Flentje for drawing this topic to my attention and comments on a preliminary draft.

References

[1] N G Barton, “An Evaporation Heat Engine and Condensation Heat Pump”, ANZIAM J, Vol 49 (2008), 503-524.

[2] D A McQuarrie & P A Rock, General Chemistry, (Freeman & Co, New York, 1987)

[3] J J Carroll & A E Mather, “The System Carbon Dioxide-Water and the Krichevsky-Kasarnovsky Equation ”, Journal of Solution Chemistry, Vol. 21 (1992), 607-621.

Cost of coal-fired power (more)

2011-10-09T22:14:00.000-07:00

In my post of 23 April 2011, I analysed how the inclusion of a Social Cost on Carbon (SCC) would affect the Levelised Electricity Cost of coal-fired power. The SCC is measured in $ per tonne of CO2 emitted. As a rule of thumb, every $ increase in the SCC translates to an extra $ on the LEC for coal-fired plants when expressed in $/MWhr.

My post referred to an authoritative report [1] on externalities associated with coal-fired power.

Recently, dana1981 at Skeptical Science has commented on the results of another study on the cost of externalities on coal-fired power. This study [2] claims a mid-range SCC of USD 27/t, with lower and upper estimates USD 6/t and USD 65/t respectively. dana1981 points out that cost of externalities in reference [2] are significantly less than those in [1], mainly because of differing treatments of (non-CO2) air pollution effects.

Despite the discrepancies in the figures, both studies agree that the cost of coal-fired power generation does not include the cost of externalities and, therefore, the true cost of coal-fired power generation is definitely more than the price that we pay. We can expect further publications in the economic literature to clarify these important issues. Hopefully the studies will also include the effect of hidden subsidies to the coal industry.

For further discussion, I refer you to the excellent post by dana1981.

Note added (16 October 2011):

dana1981 has made a supplementary post on this topic,
http://www.skepticalscience.com/correction-to-true-cost-of-coal-power-mmn11.html,

in which it's noted that the social cost of carbon discussed by Muller, Mendelsohn & Nordhaus was based on C emitted, not CO2. To convert the SCC of MMN into the more conventional form, divide the MMN figure by 44/16 = 2.75 to get the cost of CO2. The MMN figures were low already; with this correction they are just too low to be taken seriously.

References

[1] P R Epstein et al. “Full cost accounting of the life cycle of coal”, Annals of the NY Academy of Sciences 1219 (2011), 73-98.

[2] N Z Muller, R Mendelsohn & W Nordhaus, “Environmental accounting for pollution in the United States economy”, American Economic Review, 101(5) (2011), 1649-75.

2011 Solar World Congress

2011-09-29T23:27:00.000-07:00

I was one of 692 delegates privileged to attend the 2011 Solar World Congress in Kassel, Germany, from 28 August to 2 September 2011.

To recite a few facts about the Congress, the delegates came from 66 countries with 434 of them from Europe, 101 from Asia, 79 from America, 33 from Africa and 26 from Australia. (Yes, I know that doesn’t add up to 692, but those were the numbers provided by the Congress Chair at the concluding session.)

The overall Congress message was “rapid transition to a renewable energy world”. There were six major themes (solar heating and cooling, solar buildings, renewable electricity, rural energy supply, resource assessment, and renewable energies and society), which were further broken down into 31 sub-themes. These topics were addressed by 267 oral and 278 poster presentations.

Some big points were made in the opening session. In the last year, investments in electricity generation capacity, worldwide, came 47% from renewables and 53% from fossil fuels. For the decade from 2000-2010, investments in wind power increased at an annual rate of 27%, whilst the corresponding growth rates for solar thermal (mainly solar heating) and photovoltaics were 13% and 40% per annum. Germany is undertaking a dramatic restructuring of its energy system. By 2050, overall greenhouse gas emissions in Germany are to be reduced by 80% compared to 1990 levels, whilst renewables are to be expanded to represent 80-95% of the total energy mix. As part of these targets, primary energy use is to be lowered by 50%. Nuclear energy is to be completely eliminated by 2022.

The concept of the “learning curve” was emphasised frequently during the congress. By this is meant the reduction in cost of a technology as a function of installed capacity or time. The most famous example is Moore’s Law for semiconductors, and there is now a well-established learning curve for the cost of photovoltaic cells (Breyer & Gerlach, 2010).

Over the period 1976-2003, the price of a PV module (in 2010 USD/W) decreased by 22% for each doubling of the installed capacity. For a while in recent years, it seemed as if a variety of issues (including supply problems with pure silicon production) meant that the learning curve was no longer valid, but the curve has now returned to its historic trend.

So, with increasing installations and public support, the cost of electricity from PV continues to decrease, at the same time that the cost of electricity from fossil fuel and nuclear increases. Cost parity will be achieved – it’s just a matter of time, and it won’t be long.

From a societal perspective, the solar industry is now a major source of employment. The German Solar Industry Association estimates that German solar employment will increase from 80,000 in 2009 to 180,000 in 2020. Moreover solar power offers the promise of electrification to the 1.4 billion people on the planet who don’t currently have access to electricity.

Solar thermal power generation also featured in many presentations. Rapid progress is being made with several competing concepts (trough, tower, Fresnel arrays), with the eventual market winner not yet clear to this observer. Solar thermal also allows for energy storage that is relatively cheap and easy over a period of around 24 hours, and major research agencies in Europe are active in this field.

Over a longer term, say weeks or months, chemical storage seems to be the best option as described in presentations from the Fraunhofer Institute for Wind Energy and Energy Systems Technology. The key idea here is that hydrogen produced from electrolysis of water is then converted via the Sabatier reaction into methane, which is an excellent energy carrier and for which an extensive storage and distribution infrastructure is already in place.

So the storage problem is solvable, at a cost, and will be solved. But can renewables completely meet the electricity needs of major economies such as the USA? That topic was addressed in an important paper by David Mills, based for many years at the University of Sydney and the celebrated proponent of Fresnel arrays for solar thermal power. Mills’ answer is that wind and solar can completely provide the needs of the USA, provided enough spare capacity and storage is included in the system.

This requires a new way of thinking about the structure of the electricity grid. It’s instructive to think as wind and solar as providing a fluctuating underlying contribution that is augmented by quick-response storage such as batteries, pumped hydro or thermal. For the worst cases when the sun doesn’t shine and the wind doesn’t blow for two weeks, chemical storage will meet the need.

From a local perspective, the Australian legacy to the international solar energy community is significant. Of the ten most recent Presidents of the International Solar Energy Society, two were Australians (David Mills, 1997-9, and Monica Oliphant, 2008-9). The Society, founded in 1954, was headquartered in Melbourne from 1970 to 1995. With 26 participants, Australia was the 6th best represented country at the congress (behind Germany, Japan, Spain, Brazil and France). And there have been major Australian contributions to solar power generation; names that occur in this context are David Mills, Martin Green and Shi Zhengrong. These are achievements to be honoured.

It is abundantly clear that the solar industry is developing rapidly; for example solarbuzz reports that the PV industry generated global sales of USD 38.5 billion in 2009, with expected annual growth rates of around 30%. Solar thermal power generation is not as developed as PV, but is poised for growth, as are the solar heating and cooling markets.

Overall, the 2011 Solar World Congress gave a snapshot of research underlying this rapidly developing industry. In the words of Berthold Goeke, one of the speakers at the opening ceremony of 2011 SWC, Germany’s single greatest contribution to the world is transformation of its energy network. The world will move to a post-fossil and non-nuclear basis; Germany is showing us how to do it, and the solar industry will be an indispensable part of the process.

Reference

C. Breyer and A. Gerlach (2010), Global Overview on Grid-Parity Event Dynamics, in Proceedings 25th European Photovoltaic Solar Energy Conference, Valencia.

Blythe switches to PV

2011-08-24T18:19:00.000-07:00

There have been dramatic, astonishing and significant developments with the 1000 MW Blythe solar project in California, the biggest solar project in the world. On 18 August 2011, the developer (Solar Trust of America, a joint venture between the German companies Solar Millenium and Ferrostaal) announced that the first 500 MW of the project will now be powered by PV, and not solar thermal as previously announced.

Dramatic news? Absolutely – the Solar Millenium share price collapsed from around EUR 20, where it had been for around a year, to around EUR 4.

Astonishing? Absolutely – the foundation stone for this project had already been laid, approvals had been secured, funding was in place, and construction of the solar thermal plant was under way. A switch at such a late stage in a multi-billion dollar project is truly surprising. One might well wonder at the quality of the decision-making process in the first place.

Significant? Some might argue this is proof that PV has decisively triumphed over solar thermal in the mortal struggle for market share. That would be taking things too far, but it does say that in SE California where water is scarce, at the present, PV gives cheaper power than parabolic troughs with air-cooled condensers and no thermal storage.

I analysed the Blythe installation in Cost of Solar Power (12). According to my standard assumptions, I found the cost per peak Watt was USD 5.79 and the Levelised Electricity Cost was USD 315/MWhr. I thought the costs were high and commented at the time that “the LEC for the Blythe project is 25% higher than for another big US project currently under construction – Ivanpah”. The Ivanpah installation, which I analysed in Cost of Solar Power (10), uses heliostats and towers, and will be able to collect heat at a higher temperature than the parabolic trough technology proposed for Blythe. That indicates a technological advantage for power towers over troughs when air-cooled condensers are used.

According to Solarbuzz data, the cost of PV modules in the USA has fallen from USD 4.75/Wp in mid 2008 to below USD 3.00/Wp today. Solarbuzz comments that the “module price is 50-60% of the total installed cost of a solar energy system”. Presumably this led the decision-makers at the Solar Trust of America to turn away from their tried and tested parabolic trough technology. It must have been a painful decision.

What does this mean for Solar Millenium and their parabolic trough technology? Well, that technology still offers the great benefit of thermal storage. Moreover, where water-cooled condensers are possible, the peak power output will be higher than with air-cooled condensers as proposed for Blythe.

My view is that there remains a place for solar thermal power with storage. Several contenders are slugging it out for dominance – troughs, heliostats/towers, Compact Linear Fresnel Reflectors and dishes – without a clear winner in sight yet. (I might also modestly draw attention to my evaporation engine, see www.sunoba.com.au.) I also think that costs for solar thermal power station components will continue to fall as more large-scale installations are constructed.

I expect the battle between solar thermal and PV to continue. It will be a tough fight.

2011 Solar World Congress, Kassel

2011-08-21T19:43:00.000-07:00

Several German visitors visit this blog occasionally, especially when I comment on the activities of Solar Millenium, for example in association with solar installations at Andasol, Ibersol, and Blythe. Therefore, I’ll just mention that I’ll be attending the 2011 Solar World Congress in Kassel from 28 August to 2 September.

I’ll be presenting a poster paper entitled “Output of the Evaporation Engine (Sloping Canopy)”. My session is scheduled for Thursday morning, 1 September.

The figure below contains my main findings (click to see full size image). This shows the simulated output of my evaporation engine at a suitable site for a complete year. Both horizontal and sloping canopies have been studied; the figure shows the output from a 1,000 m^2 canopy with canopy losses included, but not engine losses. Engine losses were evaluated in my paper in the congress proceedings, and are expected to reduce the estimates in the figure by around 25-30%.

The table below summarises my results for the 1,000 m^2 canopy, with all losses included. If achievable in an actual system, these results would be highly pleasing. It is noteworthy that the sloping canopy gives greater annual output than the horizontal canopy. Moreover the output occurs in a more uniform fashion and can be achieved with a slightly smaller engine.

	Units	Horizontal	Sloping
Peak power	kW	65	60
Annual output	MWhr/yr	74	94
Water consumption	m^3/yr	1,181	1,422
Cost per peak Watt	AUD/(W_p)	1.38	1.42
Levelised Electricity Cost	AUD/(MWhr)	173	128

I would be very happy to discuss these issues with delegates, developers and fellow enthusiasts. More generally, I’d also be very happy to discuss the cost of solar power, as investigated in this blog since the start of 2011.