EROI negative for Coal-to-Liquids (CTL) at Shenuha Direct Coal Liquefaction plant

Kong, Z. et al. 23 January 2015. EROI Analysis for Direct Coal Liquefaction without and with CCS: The Case of the Shenhua DCL Project in China. Energies 8(2): 786-807.

Shenhua Direct Coal Liquefaction (DCL) Plant

Shenhua Direct Coal Liquefaction (DCL) Plant

 

Many nations see coal-to-liquids (CTL) as a way to avoid becoming dependent on oil producing nations and even essential for national security.  All eyes are on China, which has spent billions developing CTL technology, though policies there are somewhat schizophrenic. The central government is trying to put the brakes on CTL because of water scarcity, human health, CO2 emissions, other environmental issues, and business risks. But local governments in coal-rich areas are eager to build CTL plants for jobs and economic growth.

This paper calculates the EROI of making coal-to-liquids (CTL) at the only commercial-level Direct Coal Liquefaction (DCL) plant in the world, built by China’s Shenhua Group.

The other method of making CTL is indirect coal liquefaction (ICL), also known as Fischer-Tropsch (F-T). There are ICL plants in China (and South Africa), but they are not as efficient as the DCL plant looked at in this study.

But not all that efficient! The EROI results are negative when internal energy is included, .68-.81 (no by-product), and still negative even with by-product: .75-.90.

Internal energy certainly should be included. This is the coal energy used to liquefy coal. Some argue it shouldn’t count because society didn’t “pay for it”, the energy didn’t come from somewhere else, such as electricity generated outside of the CTL plant. But that’s rubbish. The energy to liquefy CTL has to come from somewhere, or you won’t have any liquefied coal, and diverting some of the coal to burn for the energy to make it also means less liquefied coal output.

Using by-product to push EROI out of negative territory is a tricky way to avoid the whole point of EROI: what is the ENERGY returned. Trucks and locomotives won’t move an inch burning CTL byproducts like benzene and xylene, unless perhaps they explode from trying such an experiment.

At best, if by-product is included and internal energy ignored, the EROI is 4.13 to 6.14. But that’s without carbon capture and storage, which would lower the EROI to 3.2-4.4. By 2020 the CTL EROI will be lower still as the EROI of coal production declines from 27:1 in 2010 to 24:1 in China (Hu).

The authors could find very few peer-reviewed estimates for CTL EROI.  The few that exist are for the ICL process, because DCL has been experimental until now.  Cleveland gives ranges of EROI both below and above the break-even EROI of 1 depending on assumptions regarding location, resource quality, and technology characterization. Two other ICL estimates range from 3.5 to 4:1 but don’t subtract carbon capture EROI.

The authors conclude: “In Section 3, we determined the EROI value of coal liquefaction to be less than 1…so any increases in production will not meaningfully affect the net energy available to society and accordingly, CTL should not currently be developed on a large scale in China.  A CTL project may generate a financial profit, but from this EROI analysis, the quantity of net energy delivered to society by CTL production is extremely low, perhaps even negative, which may be due to high investments in infrastructure and low conversion efficiency…. therefore, the Chinese government and investors should be prudent when developing it”.  They also say that given the dependency of China on imported oil, research should continue, and that perhaps innovations in technology will improve the EROI.

Environmental Effects (Greenpeace)

Water extraction. The Project extracts water through subterranean pipes from Haolebaoji, a region 100 kilometers away, with low precipitation rates 3 but relatively rich in groundwater. There, the Project relies on 22 wells dug well 300 meters deep to extract groundwater. As a result, groundwater levels in the region have dropped significantly 4 co mpared with 10 years ago. Also,the surface area of nearby Subeinaor Lake has decreased by 62% from 2004.

Water Pollution. The Project illicitly discharges industrial waste water into the surrounding environment at three locations.

As a result of pressure from Greenpeace and other organizations, Shenhua announced in 2013 that they were going to reduce the Project’s per ton water intensity of oil production to 6 m³ , compared to 10 m³

Statistics

This plant can produce 25,000 barrels of oil products per day from 6,000 tonnes of dry coal, or about 9 million barrels/year, and cost roughly $1.5 billion dollars. It takes 36,646.9 tonnes of raw coal to produce 10,000 tonnes of DCL oil and by-products.

References

Greenpeace. April 8, 2014. Key developments since Thirsty Coal 2: Shenhua’s Water Grab. Greenpeace.org

Hu, Y. et al. 2013. Energy return on investment (EROI) of China’s conventional fossil fuels: Historical and future trends. Energy, 54:352-364

Posted in Coal to Liquids (CTL), EROEI Energy Returned on Energy Invested | Leave a comment

CSP Barriers and Obstacles

Location must be in the desert Southwest

Unlike solar PV, CSP can’t cope with humidity or cloud cover, so it is limited to the southwest were the solar irradiation is high and there is no dust, haze, or smog.  Solar thermal power production is particularly sensitive to cloud cover relative to photovoltaic technologies because scattered light cannot be effectively concentrated by solar thermal collectors.

The lower the latitude is to 10 degrees north (or south), and the higher the altitude the better.  But the Southwest is 30-40 degrees north and rarely high altitude.  Latitude affects the angle and intensity of incoming sunlight.

Restricted to level land, ideally with a slope of 1% or less.

The best solar thermal resources are located in areas that are distant from existing population centers. New transmission is expensive and difficult to permit. Most sites are far from a connection to existing transmission lines. Like other renewables, such as wind, geothermal, and hydropower, achieving reasonable access to potential sites and connecting to existing transmission lines are major barriers to the implementation of additional solar thermal capacity. As a result, many high quality solar thermal resources in the southwest are expected to remain untapped for the foreseeable future, for the simple reason that new transmission facilities are (1) expensive to construct and (2) difficult to permit (Smith).

The average solar radiation (insolation) of a solar thermal power plant in the Southwest U.S. is 8.054 kWh/m2/day. In terms of power per unit area, this insolation is equivalent to 3.36E-04 MW/m2. The solar-to-electric efficiency of a solar thermal system is 14.3 percent, with low and high bounds of 10.6 and 17.0 percent, respectively (Sagent).

Water

Since the best solar thermal facility sites are located in the desert, the acquisition of sufficient volumes of water is a problem.

Blythe Solar Power Plant, located in the Mojave Desert of southeastern California, has a nameplate generation capacity of 1,000 MW. During operations, the project would require approximately 600 acre-feet (195 million gallons) of water per year for cooling. An additional 4,100 acre- feet (1.3 billion gallons) of water would be required in support of project construction (BLM). An acre-foot of water is equal to 1,234,000 kg of water.

The availability of water in order to support cooling during power generation is also a resource issue. Similar to fossil power plants, solar thermal plants must include a cooling system in order to support steam condensation and effective power production. Evaporative (water-based) cooling of power plants is generally much more effective and efficient than dry (air-based) cooling, because evaporative cooling has lower capital costs, higher thermal efficiency, and supports consistent efficiency levels year round. However, evaporative cooling also requires water – up to approximately 650 gallons/MWh – that might not be available in many portions of the Desert Southwest. Air cooling, in contrast, is less effective during high temperatures because it results in lower net efficiency and is more costly to install and operate (DOE, 2009). However, the best available solar resources are located in the Desert Southwest, where water supplies are severely limited. While dry cooling reduces water consumption by about 90 percent, it also reduces net power generation by approximately 5 percent (WorleyParsons), and may increase generated electricity cost by approximately 2 to 9 percent (DOE, 2009).

Dry cooling avoids the need for water, but results in lower net power production and lower net efficiency, especially during the hottest periods (often when solar resources are best for generating power).

Ecological Impact

Habitat loss can be substantial for large solar thermal projects, such as the Blythe Solar Power Project, which has been approved and is expected to have a generation capacity of around 1,000 MW, would result in disturbance to approximately 7,025 acres of land area, equivalent to nearly 11 square miles of land area. Most of this land area would be used for the solar field, but other uses would include generation facilities, transmission lines, and various appurtenances. The facility would be stripped of existing desert vegetation and fenced, resulting in the loss of vegetative habitat within these areas. Other effects include loss of desert tortoise habitat and migration corridors, and loss of habitat for other desert wildlife. Key concerns included potential for interference with Colorado River flows and the consumption of water that could otherwise be utilized for agricultural, residential, or other purposes (BLM).

High water consumption (competes with agriculture)

Interference with geologic or geomorphic processes, such as sand migration and erosion

Flooding associated with desert washes and interference with natural drainage patterns. Most of the time there is no surface water in the vicinity. However, the southwest is subject to infrequent but very high-intensity monsoonal events when flash flooding can occur, which inundates desert washes. To protect solar facilities from floods, many projects have proposed installation of riprap- and levee-like features, flood control channels, and other modifications to re-route existing drainages around project sites. These structures can result in changes downstream, including changes in the distribution of vegetation, as well as altered erosional and sediment transport processes.

Airborne emissions (primarily dust but also other air pollutants)

Concerns regarding GHG emissions during construction

Potential to exacerbate secondary effects of climate change, such as heat waves

Cost

CSP plants with thermal storage are very expensive.

Decommissioning of solar thermal power plants are 10 percent of the capital costs of initial construction (DOE/NETL).

EROI

DOE calculated the EROI for solar thermal power generation as 8.2 to 1, but they didn’t subtract the EROI of energy storage (DOE/NETL). But at least they calculated it – 99.99% of government, university, and peer-reviewed research looks only at greenhouse gas emissions and how much more of whatever-is-being-studied needs to be built for growth rather than energy efficiency and conservation of resources.  There is no document I know of that discusses how to cope with shrinking once oil production declines and shortages occur.

References

BLM. 2010. Plan Amendment/Final EIS for the Blythe Solar Power Project. Palm Springs, CA: U.S. Bureau of Land Management  http://www.blm.gov/ca/st/en/fo/palmsprings/Solar_Projects/Blythe_Solar_Power_Project.html

DOE. 2009. Concentrating Solar Power Commercial Application Study: Reducing Water Consumption of Concentrating Solar Power Electricity Generation. U.S. Department of Energy  http://www1.eere.energy.gov/solar/pdfs/csp_water_study.pdf

DOE/NETL. August 28, 2012. Role of Alternative Energy Sources: Solar Thermal Technology Assessment. Department of Energy, National Energy Technology Laboratory.

Sagent & Lundy LLC Consulting Group. 2003. Assessment of Parabolic Trough and Power Tower Solar Technology Cost and Performance Forecasts. http://www.nrel.gov/docs/fy04osti/34440.pdf

Smith, M. et al. 2010. Permitting and Environmental Challenges for Wind Energy Conversion Facilities and Transmission Facilities.

WorleyParsons. 2008. FPLE – Beacon Solar Energy Project: Dry Cooling Evaluation: WorleyParsons.

 

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CSP with thermal energy storage is seasonal, so it can not balance variable power or contribute much power for half the year

Concentrated Solar Power not only needs lots of sunshine, but no humidity, clouds, dust, smog or or anything else that can scatter the sun’s rays.  Above 35 degrees latitude north or south, the sun’s rays have to pass through too much atmosphere to produce high levels of power, and these regions tend to be too cloudy as well.  Between 15 degrees north and south of the equator is also not ideal, it’s too cloudy, rainy, and humid.  That leaves very dry and hot regions in the 15-35 degrees of latitude.  Only deserts are suitable, such as America’s Southwest, southern Africa, the Middle East, north-western India, northern Mexico, Peru, Chile, the western parts of China and Australia,  the extreme south of Europe and Turkey, some central Asian countries, and places in Brazil and Argentina.

The problem with arid, dry regions is that CSP needs water for condenser cooling. Dry-cooling of steam turbines can be done but it costs more and lowers efficiency.

CSP doesn’t wean us totally from fossil fuels, nearly all use fossil fuel as back-up, to remain dispatchable even when the solar resource is low, and to guarantee an alternative thermal source that can compensate night thermal losses, prevent freezing and assure a faster start-up in the early morning.

Even in ideal locations, CSP is highly seasonal:

CSP electric production seasonal low Jan high May

 

The average CSP capacity factor in the United States in December 2014 was 5.5%, while in August it was 25% (EIA. 2015. Table 6.7.B. Capacity Factors for Utility Scale Generators Not Primarily Using Fossil Fuels, January 2008-November 2014. U.S. Energy Information Administration).

 

This means that CSP requires seasonal storage, since it provides almost nothing in winter, yet CSP with thermal energy storage (TES) IS one of the few ways even a few hours of energy storage can be accomplished, since there’s very limited pumped hydro storage, compressed air energy storge, and battery storage.

“Averages” are irrelevant.  The seasonal nature of CSP with thermal storage makes balancing variable renewables and year-round power on a national grid — or even within the Southwest some days, weeks, or seasons — impossible without months of energy storage.   

Concentrating Solar Power Average Daily Solar Radiation Per Month, 1961]1990 (NREL 2011b)

Concentrating Solar Power Average Daily Solar Radiation Per Month, 1961-1990 (NREL 2011b)

 

 

There will be days or weeks when solar radiation is very low.  Below are some minimums and maximums for an East-West Axis Tracking Concentrator Daily solar radiation per month (NREL 2011b).

January mininum

January minimum

January maximum

January maximum

 

 

 

 

 

July minimum

July minimum

July maximum

July maximum

 

 

 

 

 

This means, for example, that in central Nevada may reach 10 kWh/m2/day or higher during July, but January average values may be as low as 3 kWh/m2/day, or even zero on a daily basis as a result of cloud cover (NREL 2011a).

The best CSP is in just a few unpopulated, drought-stricken states (AZ, CA, NM, NV)(NREL 2012):

CSP NREL solar resource 2012

The Seasonal Nature of sunshine (International Energy Agency. 2011. Solar Energy Perspectives)

Seasonal storage for CSP plants would require stone storage. The volume of stone storage for a 100 MW system would be no less than 2 million m3, which is the size of a moderate gravel quarry, or a silo of 250 meter diameter and 67 meter high. This may not be out of proportion, in regions where available space is abundant, as suggested by the comparison with the solar collector field required for a CSP plant producing 100 MW on annual average.

Stones are poor heat conductors, so exchange surfaces should be maximized, for example, with packed beds loosely filled with small particles. One option is then to use gases as HTFs from and to the collector fields, and from and to heat exchangers where steam would be generated. Another option would be to use gas for heat exchanges with the collectors, and have water circulating in pipes in the storage facility, where steam would be generated. This second option would simplify the general plan of the plant, but heat transfers between rocks and pressurized fluids in thick pipes may be problematic.

Annual storage may emerge as a useful option, as generation of electricity by CSP plant in winter is significantly less than in other seasons in the range of latitudes – between 15° and 35° – where suitable areas for CSP generation are found. However, skeptics point out the need for much thicker insulation walls as a critical cost factor.

Square miles needed to produce 25,000 TWh/year with CSP

CSP is more efficient than PV per surface of collectors, but less efficient per land surface, so its 25,000 TWh of yearly production would require a mirror surface of 38,610 square miles (100,000 sq km) and a land surface of about 115,831 square miles (300,000 km2).

Best locations for CSP

Tropical zones thus receive more radiation per surface area on yearly average than the places that are north of the Tropic of Cancer or south of the Tropic of Capricorn. Independent of atmospheric absorption, the amount of available irradiance thus declines, especially in winter, as latitudes increase. The average extraterrestrial irradiance on a horizontal plane depends on the latitude (Figure 2.4).

IEA 2011 figure 2.4 average yearly irradiance by latitude

 

 

 

 

 

 

 

Irradiance varies over the year at diverse latitudes – very much at high latitudes, especially beyond the polar circles, and very little in the tropics (Figure 2.5).  Seasonal variations are greater at higher latitudes:

IEA 2011 figure 2.5 total daily irradiance on a plane horizontal to earth surface

 

 

 

 

 

IEA 2011 figure 2.8 yearly profile mean daily solar radiation

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Figure 2.8 The yearly profile of mean daily solar radiation for different locations around the world. The dark area represents direct horizontal irradiance, the light area diffuse horizontal irradiance. Their sum, global horizontal irradiance (GHI) is the black line. The blue line represents direct normal irradiance (DNI). Key point: Temperate and humid equatorial regions have more diffuse than direct solar radiation.

So for solar CSP, the blue line is important and needs to be above 6 for a project to be commercially viable.  The South Pacific Islands have too much moisture (blue line), and northern europe likewise plus not enough irradiance.  Concentrating technologies can be deployed only where DNI largely dominates the solar radiation mix, i.e. in sunny countries where the skies are clear most of the time, over hot and arid or semi-arid regions of the globe. These are the ideal places for concentrating solar power (CSP), concentrating photovoltaics (CPV).  PV can work fine in humid regions, but not CSP or CPV.

Formulations such as “a daily average of 5.5 hours of sunshine over the year” are casually used, however, to mean an average irradiance of 5.5 kWh/m2/d (2 000 kWh/m2/y), i.e. the energy that would have been received had the sun shone on average for 5.5 hours per day with an irradiance of 1,000 W/m2. In this case, one should preferably use “peak sunshine” or “peak sun hours” to avoid any confusion with the concept of sunshine duration.

Ground data measurements for 1-2 years before building a CSP plant

Ground measurements are critically necessary for a reliable assessment of the solar energy possibilities of sites, especially if the technology is CSP or CPV. Satellite data can be used to complement short ground measurement periods of one or two years with a longer term perspective. Ten years is the minimum necessary to have a real perspective on annual variability, and to get a sense of the actual average potential and the possible natural deviations from year to year. Satellite data should be used only when they have been bench-marked by ground measurements.

All parabolic trough plants currently in commercial operation rely on a synthetic oil as heattransfer fluid (HTF) from collector pipes to heat exchangers, where water is preheated, evaporated and then superheated. The superheated steam runs a turbine, which drives a generator to produce electricity. After being cooled and condensed, the water returns to the heat exchangers. Parabolic troughs are the most mature of the CSP technologies and form the bulk of current commercial plants. Investments and operating costs have been dramatically reduced, and performance improved, since the first plants were built in the 1980s. For example, special trucks have been developed to facilitate the regular cleaning of the mirrors, which is necessary to keep performance high, using car-wash technology to save water.

Most first-generation plants have little or no thermal storage and rely on combustible fuel as a firm capacity back-up. CSP plants in Spain derive 12% to 15% of their annual electricity generation from burning natural gas. More than 60% of the Spanish plants already built or under construction, however, have significant thermal storage capacities, based on two-tank molten-salt systems, with a difference of temperatures between the hot tank and the cold one of about 100°C.

Salt mixtures usually solidify below 238°C and are kept above 290°C for better viscosity, however, so work is needed to reduce the pumping and heating expenses required to protect the field against solidifying [my comment: so fossil energy to keep the salts hot subtracts from efficiency]

Energy storage

Worldwide energy storage: The volume of electricity storage necessary to make the electricity available when needed would likely be somewhere between 25 TWh and 150 TWh – i.e. from 10 to 60 hours of storage. If 20 TWh are transferred from one hour to another every day, then the yearly amount of variable renewable electricity shifted daily would be roughly 7,300 TWh. Allowing for 20% losses, one may consider 9,125 TWh in and 7,300 TWh out per year.

Studies examining storage requirements of full renewable electricity generation in the future have arrived at estimates of hundreds of GW for Europe (Heide, 2010), and more than 1,000 GW for the United States (Fthenakis et al., 2009). Scaling-up such numbers to the world as a whole (except for the areas where STE/CSP suffices to provide dispatchable generation) would probably suggest the need for close to 5,000 GW to 6,000 GW storage capacities. Allowing for 3,000 GW gas plants of small capacity factor (i.e. operating only 1 000 hours per year) explains the large difference from the 2,500 GW of storage capacity needs estimated above. However, one must consider the role that large-scale electric transportation could possibly play in dampening variability before considering options for large-scale electricity storage.

V2G possibilities certainly need to be further explored. They do entail costs, however, as battery lifetimes depend on the number, speeds and depths of charges and discharges, although to different extents with different battery technologies. Car owners or battery-leasing companies will not offer V2G free to grid operators, not least because it reduces the lifetime of batteries. Electric batteries are about one order of magnitude more expensive than other options available for large-scale storage, such as pumped-hydro power and compressed air electricity storage.

IEA 2014. Technology Roadmap. Solar Thermal Electricity. International Energy Agency

Global horizontal irradiance (GHI) is a measure of the density of the available solar resource per unit area on a plane horizontal to the earth’s surface. Global normal irradiance (GNI) and direct normal irradiance (DNI) are measured on surfaces “normal” (i.e., perpendicular) to the direct sunbeam. GNI is relevant for two-axis, sun-tracking, “1-sun” (i.e., non-concentrating) PV devices.

DNI is the only relevant metric for devices that use lenses or mirrors to concentrate the sun’s rays on smaller receiving surfaces, whether concentrating photovoltaics (CPV) or CSP generating STE. All places on earth receive 4,380 daylight hours per year — i.e., half the total duration of a year – but different areas receive different yearly average amounts of energy from the sun.

When the sun is lower in the sky, its energy is spread over a larger area and energy is also lost when passing through the atmosphere, because of increased air mass; the solar energy received is therefore lower per unit horizontal surface area.

Inter-tropical areas should thus receive more radiation per land area on a yearly average than places north of the Tropic of Cancer or south of the Tropic of Capricorn.

However, atmospheric absorption characteristics affect the amount of this surface radiation significantly. In humid equatorial places, the atmosphere scatters the sun’s rays. DNI is much more affected by clouds and aerosols than global irradiance. The quality of DNI is more important for CSP plants than for concentrated photovoltaics (CPV), because the thermal losses of a CSP plant’s receiver and the parasitic consumption of the electric auxiliaries are essentially constant, regardless of the incoming solar flux. Below a certain level of daily DNI, the net output is null (Figure 2 above).

High DNI is found in hot and dry regions with reliably clear skies and low aerosol optical depths, which are typically in subtropical latitudes from 15° to 40° north or south. Closer to the equator, the atmosphere is usually too cloudy, especially during the rainy season. At higher latitudes, weather patterns also produce frequent cloudy conditions, and the sun’s rays must pass through more atmosphere mass to reach the power plant. DNI is also significantly higher at higher elevations, where absorption and scattering of sunlight due to aerosols can be much lower. Thus, the most favorable areas for CSP resource are in North Africa, southern Africa, the Middle East, north- western India, the south-western United States, northern Mexico, Peru, Chile, the western parts of China and Australia. Other areas that are suitable include the extreme south of Europe and Turkey, other southern US locations, central Asian countries, places in Brazil and Argentina, and some other parts of China.

Areas with sufficient direct irradiance for CSP development are usually arid and many lack water for condenser cooling (Box 1). Dry-cooling technologies for steam turbines are commercially available, so water scarcity is not an insurmountable barrier, but it leads to an efficiency penalty and an additional cost. Wet-dry hybrid cooling can significantly improve performance, with water consumption limited to heat waves.

Almost all existing CSP plants use some fossil fuel as back-up, to remain dispatchable even when the solar resource is low and to guarantee an alternative thermal source that can compensate night thermal losses, prevent freezing and assure a faster start-up in the early morning.

Investment costs for CSP plants have remained high, from USD 4 000/kW to 9 000/kW, depending on the solar resource and the capacity factor, which also depends on the size of the storage system and the size of the solar field, as reflected by the solar multiple.

Costs were expected to decrease as CSP deployment progressed, following a learning rate of 10% (i.e., 10% cost reduction for each cumulative capacity doubling). This decrease has taken a long time to materialize, however, because market opportunities for CSP plants have diminished and the cost of materials has increased, particularly in the most mature parts of the plants, the power block and balance of plant (BOP). Other causes are the dominance of a single technology (trough plants with oil as heat transfer fluid

The few larger plants that have been or are being built elsewhere are either the first of their find in the world, with large development costs and technology risks (e.g., in the United States),

Levelized cost of electricity (LCOE)3 of STE varies widely with the location, technology, design and intended use of plants. The location determines the quantity and quality of the solar resource (Box 1), atmospheric attenuation at ground level, variations in temperature that affect efficiency (e.g., cold at night increases self-consumption, warmth during daylight reduces heat losses but also thermodynamic cycle efficiency) and the availability of cooling water. A plant designed for peak or mid-peak generation with a large turbine for a relatively small solar field will generate electricity at a higher cost than a plant designed for base load generation with a large solar field for a relatively small turbine. LCOE, while providing useful information, does not represent the entire economic balance of a CSP plant, which depends on the value of the generated STE.

Recent CSP plant in the United States secured PPA at USD 135/MWh, but taking investment tax credit into account, the actual remuneration is about USD 190/MWh.  The US DoE’s Sunshot program expects more rapid cost reductions based on current trends, and even aims for LCOE of USD 60/MWh as soon as 2020 [dream on…]

Barriers encountered, overcome or outstanding

Developers have encountered several barriers to establishing CSP plants. These include insufficiently accurate DNI data; inaccurate environmental data; policy uncertainty; difficulties in securing land, water and connections; permitting issues; and expensive financing, leading to difficult financial closure Inaccurate DNI data can lead to significant design errors. Ground-level atmospheric turbidity, dirt, sand storms and other weather characteristics or events may seriously interfere with CSP technologies. Permits for plants have been challenged in courts because of concerns about their effects on wildlife, biodiversity and water use. Some countries prohibit the large-scale use as HTF of synthetic oil or some molten salts, or both.

The most significant barrier is the large up-front investment required. The most mature technology, PT with oil as HTF, with over 200 cumulative years of running, may have limited room for further cost reductions, as the maximum temperature of the HTF limits the possible increase in efficiency and imposes high costs to thermal storage systems. Other technologies offer greater prospects for cost reductions but are less mature and therefore more difficult to obtain finance for. In countries with no or little experience of the technology, financing circles fear risks specific to each country.

In the United States, the loan guarantee program of the DoE has played a key role in overcoming financing difficulties and facilitating technology innovation.

Medium-term outlook

There are no new CSP projects in Spain, as incentives have been cut.

Plants in the approval process or ready to start construction represent 20 MW in France and 115 MW in Italy, while other projects are under development. The Italian environment legislation does not allow for extensive use of oil in trough plants, limiting the technology options to more innovative designs, such as DSG or molten salts as HTF. Projects that would produce several gigawatts are still under consideration or development in the United States, although not all will succeed in obtaining the required permits, PPAs, connections, and financing.

Current average LCOE is high because most existing plants have been built in Spain, which has relatively weak DNI. [my comment: if there is money for energy projects it’s spent regardless of how expensive and foolish – look at all the fracked natural gas by companies deeply in debt, the massive building of solar PV and CSP in Spain, ethanol subsidies, and all kinds of wasteful projects (and research) across the board.  I think this is why there’s no funding for EROI research — nobody wants to know!  Plus foolish projects provide jobs, it’s more important for democrats to provide “green” jobs than whether or not it’s a good idea. And why not, as long as there is oil we can build cities like Las Vegas in the desert that will be abandoned as soon as 2024 or whenever Lake Mead dries up, parking lots, cheap ugly housing projects, and so on]

As deployment intensifies in the southwestern United States and spreads to North Africa, South Africa, Chile, Australia and the Middle East, better resources will be used, improving performance.

Table 4: Projections of LCOE for new-built CSP plants with storage in the hi-Ren Scenario

The possible role of small-scale CSP devices – from 100 kW to a few MW – off-grid or serving in mini-grids, has not been included in the ETP model. There is too little industrial experience of such systems to make informed cost assumptions, whether the systems are based on PT, LFR, parabolic dishes, Scheffler dishes or small towers, using organic Rankin cycle turbines, micro gas-turbines or various reciprocating engines. If they allow thermal storage4 or fuel backup, small-scale CSP systems have to compete against PV with battery storage or fuel backup. They may find a role, although the fact that CSP technology seems to benefit more than PV from economies of scale suggests that smallscale CSP systems may face a greater competitive challenge than large-scale ones. Finding local skills for maintenance may also be challenging in remote, off-grid areas.

Storage is a particular challenge in CSP plants that use DSG. Because water evaporation is isothermal, unlike sensible heat addition or removal in the salt, a round-trip storage cycle would result in severe steam temperature and pressure drops, thereby destroying the efficiency of the thermodynamic cycle in discharge mode. Storing latent heat of saturated steam in pressurised vessels is expensive and provides no scale effect on cost. One option would use three-stage storage devices that preheat the water, evaporate the water and superheat the steam. Stages 1 and 3 would be sensible heat storage, in which the temperature of the storage medium changes. Stage 2 would best be latent heat storage, in which the state of the storage medium changes, using some phase change material. Another option could be to use liquid phase-change materials. The growing relevance of thermal storage in the context of intense competition from cheap PV favors using molten salts as both the heat transfer fluid and the storage medium (termed “direct storage”). If DSG spares heat exchangers for steam generation, the use of molten salts as HTF spares heat exchangers for storage. Salts are less costly than oil. Using salts allows raising the temperature and pressure of the steam, from 380°C to 530-550°C and from 10 to 12-15 megapascals (MPa) in comparison with oil as HTF, increasing the efficiency of the power block from 39% to 44-45% (Lenzen, 2014). Thanks to higher temperature differences between hot and cold salts (currently used salt mixtures usually solidify below 238°C), plants using molten salts as HTF need three times less salts than trough plants using oil as HTF, for the same storage capacity. This lowers the storage system costs, which represent about 12% of the overall plant cost for seven-hour storage of a trough plant. Also, the “return efficiency” of thermal storage, at about 93% with indirect storage (in which heat exchangers reduce the working temperature), is increased to 98% with direct storage. Finally, another advantage of molten salts as HTF over steam is that heat transfer can be carried out at low pressure with thin-wall solar receivers, which are cheaper and more effective. Overall, the substitution of molten salts for oil in CSP would allow for 30% LCOE reduction, according to Schott, the lead manufacturer of solar receiver tubes (Lenzen, 2014). Several companies are developing the use of molten salts as HTF in linear systems, and have built or are building experimental or demonstration devices. One challenge is to reduce the expense required to keep the salts warm enough (usually above 290°C) for better viscosity in long tubes at all times and protect the field against freezing.

Apart from the fundamental choice between DSG and molten salts for HTF, towers currently also offer a great diversity of designs – and present various trade-offs. The first relates to the size (and number) of heliostats that reflect the sunlight onto the receivers atop the tower. Heliostats vary greatly in size, from about 1 m2 to 160 m2. The small ones can be flat and offer little surface to winds. The larger ones need several mirrors that are curved to send a focused image of the sun to the central receiver, and need strong support structures and motors to resist winds. For similar collected energy ranges, however, small heliostats need to be grouped by the thousand, multiplying the number of motors and connections. Manufacturers and experts still have divided views about the optimum size. Heliostats need to be distanced from one another to reduce losses arising when a heliostat intercepts part of the flux received (“shading”) or reflected (“blocking”) by another. While linear systems require flat land areas, central receiver systems may accommodate some slope, or even benefit from it as it could reduce blocking and shadowing, and allow increasing heliostat density. Algorithmic field optimization may help reduce environmental impacts and required ground leveling work while maximizing output (Gilon, 2014).

In low latitudes heliostat fields tend to be circular and surround the central receiver, while in higher latitudes they tend to be more concentrated to the polar side of the tower. Larger fields tend to be more circular to limit the maximum receiver heliostat distance and minimise atmospheric attenuation.

Proper aiming strategy must be ensured by the heliostat field’s control system in order to optimise the solar flux map on the receiver, thereby allowing the highest solar input while avoiding any local overheating of the receiver tubes. This is more difficult with DSG receivers. The heat flux on the different types of solar panel of a DSG receiver differs significantly: superheater panels (poorly cooled by superheated steam) receive a much lower flux than evaporator and preheater panels. Another important design choice relates to the number of towers for one turbine. Heliostats that are in the last rows far from the tower need to be very precisely pointed towards it, and lose efficiency as the light must make a long trip near ground level. They also have greater geometrical (“cosine”) optical losses.

At over 1 million m2, the solar field associated with the 110 MW tower built by SolarReserve with 10-hour storage at Crescent Dunes, (Nevada, United States) is perhaps close to the maximum efficient size.

The additional costs of building several towers may be made up for by the greater optical and thermal efficiencies of multitower design (Wieghardt et al., 2014). However, the optimal field size and number of towers may depend on the atmospheric turbidity of the site considered, which varies greatly among areas suitable for CSP plants. The Californian company eSolar proposes 100 MW molten salt power plants based on 14 solar fields and 14 receivers on top of monopole towers (similar to current large wind turbine masts) for one central dry-cooled power block with 13-hour thermal storage and 75% capacity factor (Tyner, 2013).

As the share of variable energy increases, base load plants, even if technically flexible (which all are not) will become less economically efficient as their utilization rate diminishes. At the same time, more peaking and mid-merit plants become necessary. Below a certain load factor – about 2,000 full load hours – open-cycle gas turbines become a better economic choice than combined-cycle plants, but they are less energy-efficient as they generate large amounts of waste heat.

Open-cycle gas turbines could be integrated with a CSP plant with storage, however, of which the steam turbine is not being used with a very high capacity factor. When the sun does not shine, the otherwise wasted heat could be collected to a large extent in the hot tank of a two-tank molten-salt system. This energy could afterwards be directed to the steam turbine to deliver electricity whenever requested. If more power is needed when the sun shines sufficiently to run the steam turbine by itself, the heat from the gas turbine could be directed to the thermal storage. In both cases, a large part of the waste heat will be used. This concept differs from the existing ISCC in which solar only provides a complement, as the presence of thermal storage allows for a complete reversal of the proportion of solar and gas, which remains a backup, though a more efficient one (Crespo, 2014). The Hysol project, funded by the European Union’s Seventh Program for research, technological development and demonstration, aims to demonstrate the viability of the concept. Similarly, in areas with both high wind penetration and CSP plants, some thermal storage, which is equipped with electric heaters for security reasons, could be used in winter to reduce curtailment from excess wind power.

Molten salts decompose at higher temperatures, while corrosion limits the temperatures of steam turbines. Higher temperatures and efficiencies could rest on the use of fluoride liquid salts as HTFs up to temperatures of 700°C to 850°C,

There are a number of potential pathways to solar fuels. The straightforward thermolysis of water is the most difficult, as it requires temperatures above 2 200°C and may produce an explosive mixture of hydrogen and oxygen. The division of the single-step water-splitting reaction into a number of sub- reactions opens up the field of so called thermochemical cycles for H2 production. The necessary reaction temperature can be decreased even below 1 000°C, resulting in intermediate solid products like metals (e.g., aluminium, magnesium, or zinc), metal oxides, metal halides or sulphur oxides. The different reaction steps can be separated in time and place, offering possibilities for long-term storage of the solids and their use in transportation. These thermochemical cycles are also able to split CO2 into CO and oxygen. If mixtures of water and CO2 are used, even synthesis gas (mainly H2 and CO) can be produced, which can be further processed to synfuels, for example by the Fischer-Tropsch process.

Concentrated solar radiation can also be used to upgrade carbonaceous materials. The most developed process is the steam reforming of methane to produce synthesis gas. Sources are either natural gas or biogas. Methane can also be cracked into hydrogen and carbon, thus producing a gaseous and a solid product. However, the required process temperature is extremely high and a homogeneous carbon product is unlikely to be produced because of the intermittent solar radiation conditions. Additionally, there is a discrepancy between the huge demand for hydrogen and the low demand for high-value carbon, such as carbon black or advanced carbon nano-tubes.

Hydrogen produced in concentrating solar chemical plants could be blended with natural gas and thus used in today’s energy system. Town gas, which prevailed before natural gas spread out, included hydrogen up to 60% in volume or about 20% in energy content. This blend could be used for various purposes in industry, households and transportation, reducing emissions of CO2 and nitrous oxides. Gas turbines in integrated gasification combined cycle (IGCC) power plants can burn a mix of gases with 90% hydrogen in volume. Many existing pipelines could, with some adaptation, transport such a blend from sunny places to large consumption centres (e.g. from North Africa to Europe).

Solar-produced hydrogen could also find niche markets today in replacing hydrogen production from steam-reforming of natural gas in its current uses, such as manufacturing fertilizers and removing sulfur from petroleum products. Regenerating hydrogen with heat from concentrated sunlight to decompose hydrogen sulphide into hydrogen and sulfur could save significant amounts of still gas in refineries for other purposes. Coal could be used together with methane gas as feedstock, and deliver dimethyl ether (DME), after solar-assisted steam reforming of natural gas, coal gasification under oxygen, and two-step water splitting. DME could be used as a liquid fuel, and its combustion would entail similar CO2 emissions to those from burning conventional petroleum products, but significantly less than the life-cycle emissions of other coal-to-liquid fuels.

Besides solar fuels, CSP technology could find a great variety of uses in providing high temperature process heat or steam, such as for enhanced oil recovery, and mining applications (where CSP is already in use), smelting of aluminium and other metals, and in industries such as food and beverages, textiles and pharmaceuticals. Various forms of cogeneration with STE can also be considered. For example, sugar plants require high temperature steam in spring, when the solar resource is maximal but electricity demand minimal. Solar fields providing steam for sugar plants could run a turbine and generate STE for the rest of the year.

STE is not broadly competitive today, and will not become so until it benefits from strong and stable frameworks, and appropriate support to minimise investors’ risks and reduce capital costs.

As with any large industrial projects, STE projects require several permissions, often delivered by many different government jurisdictions at various geographical levels, as well as many branches or agencies of each – local, regional, state, federal or national. Each may protect different interests, all of them legitimate.

Future values of PV and STE in California Researchers at the National Laboratory of Renewable Energy (NREL) in the United States have studied the future total values (operational value plus capacity value) of STE with storage and PV plants in California in two scenarios: one with 33% renewables in the mix (the renewable portfolio standard by end 2020), including about 11% PV, another with 40% renewables (under consideration by California’s governor), including about 14% PV. In both cases there is over 1 GW of electricity storage available on the grid. The main results indicate that at 33% renewable penetration, the bulk of the gap in favour of STE comes from its greater capacity value, which avoids the costs of building additional thermal generators to meet demand (Table 5). At 40% renewable penetration, the value of STE increases slightly, but the value of PV drops significantly, mostly reflecting the drop of its own capacity value (Jorgenson et al., 2014). For investment decisions and planning, system values are as much important as LCOE. Table 6: Total value in two scenarios of renewables penetration in California Value component 33% renewables 40% renewables STE with storage PV Value value (USD/MWh) (USD/MWh) STE with

The built-in storage capability of CSP is cheaper and more effective (with over 95% return efficiency, versus about 80% for most competing technologies) than battery storage and pumped-hydropower storage. Thermal storage allows separating the collection of the heat (during the day) and the generation of electricity (at will). This capability has immediate value in countries having significant increase in power demand when the sun sets, in part driven by lighting requirements. In many such countries, the electricity mix, which during daytime is often dominated by coal, becomes dominated by peaking technologies, often based on natural gas or oil products.

The greatest possible expansion of PV, which implies its dominance over all other sources during a significant part of the day, creates difficult technical and economic challenges to low-carbon base-load technologies such as nuclear power and fossil fuel with CCS. Natural gas is more suited to daily “stop-and-go” with rapid ramps up and down, and is more economical for mid-merit operations (between about 2,000 and 4,000 full-load hours).

changes in the rules applicable to investments already being made or in process can have long-lasting deterrent effects on investments if they significantly modify the prospects for economic returns. This is precisely what has happened over the last few years in Spain, where a series of measures aimed at reducing the return on investment on existing CSP plants. The high risk of losing investors’ confidence may have been deemed acceptable, as these measures followed the decision to stop CSP deployment. However it may have detrimental effects for future investments in CSP plants; for other investments in the energy sector; for other investments in any other sector that requires government involvement; and for investments in other countries

Financing CSP plants, like most renewable energy plants, are very capital-intensive, requiring large upfront expenditures. Financing is thus difficult, especially in new, immature markets, and for new, emerging sub-technologies. In the United States, some private investors have large amounts of money available and might be willing to invest in clean energy for a variety of reasons; but even in this context the risks may have appeared too high for large, innovative CSP projects – costing around USD 1 billion – to materialize, without the loan guarantee program of the US DoE. This program has been essential to the renaissance of CSP in the United States, in allowing projects to access debt at very low cost from a US government bank and facilitating financial closure at acceptable WACC of large projects.

In other countries, such as India, Morocco and South Africa, public low-cost lending has been essential for jump-starting the deployment of CSP. In India and South Africa, private banks would have not provided capital for the very long maturity involved. In Morocco, the presence of a government agency as equity partner significantly reduced the perception of policy risks among other partners. In Morocco and South Africa, international finance institutions provided concessional grants that reduced the overall costs of large CSP projects.

Subsidizing renewable energy projects through long-term and/or low-cost debt-related policies could reduce the total subsidies compared with per-kWh support. However, this transfers the burden of high capital-intensivity to governments, which may not have enough money at hand, and this carries a risk of slowing deployment. Interest subsidies and/or accelerated depreciation have much higher one-year budget efficiency.

Research is under way to test and evaluate methods of measuring DNI accurately using lower-cost instrumentation, and for producing long-term, high-quality DNI data sets by merging long-term, satellite-derived data of moderate accuracy with high-quality, highly accurate ground-based measurements that may only cover a year or less. This research also includes important studies on sunshape and circumsolar radiation, and how these factor into both DNI measurements and STE system performance. In addition, satellite-based methods for estimating DNI are constantly improving and represent a reliable and viable way of choosing the best sites for STE plants. Furthermore, the ability to accurately forecast DNI levels – from a few hours ahead to a few days ahead – is constantly improving, and will be an important tool for utilities operating STE systems.

Abbreviations: ARRA American recovery and reinvestment Act CCS carbon capture and storage CO2 carbon dioxide CPI Climate Policy Initiative CSF concentrated solar fuels CSP concentrating solar power CPV concentrating photovoltaic CRS central receiver system CTF Clean Technology Fund DC direct current DII Desertec Industry Initiative DLR Forschungszentrum der Bundesrepublik Deutschland für Luft- und Raumfahrt (German Aerospace Centre) DME Dimethyl ether DNI direct normal irradiance DSG direct steam generation EDF Électricité de France EIB European Investment Bank EPC engineering, procurement and construction ETP: Energy Technology Perspectives EU European Union EUR euro FiT feed-in tariff FiP feed-in premium G8 Group of Eight GHG greenhouse gas(es) GHI global horizontal irradiance GNI global normal irradiance Gt gigatonnes GW gigawatt (1 million kW)  GWh gigawatt hour (1 million kWh) Hi-Ren high renewables (Scenario) HTF heat transfer fluid HVDC high- voltage direct current IA implementing agreement IEA International Energy Agency IFI international financial institution IGCC integrated gasification combined cycle IRENA International Renewable Energy Agency ISCC Integrated Solar Combined-Cycle (plant) JRC Joint Research Centre kW kilowatt kWh kilowatt hour LCOE levelized cost of electricity LFR linear Fresnel reflectors MW megawatt (1 thousand kW) MWe megawatt electrical MWh megawatt hour (1 thousand kWh) MWth megawatt thermal NGO non-governmental organisation NREAP national renewable energy action plan NREL National Renewable Energy Laboratory (United States) OECD Organization for Economic Co-operation and Development O&M operation and maintenance PPA power purchase agreement PT parabolic trough  TWh terawatthour (1 billion KWh)

IEA (2014a), Technology Roadmap: Solar Photovoltaic Energy, 2014 Edition, OECD/IEA, Paris. IEA (2014b), Energy Technology Perspectives 2014, OECD/IEA, Paris. IEA (2014c), Technology Roadmap: Energy Storage, OECD/IEA, Paris. IEA (2014d), Medium-Term Renewable Energy Market Report, OECD/IEA, Paris. IEA (2014e), The Power of Transformation: Wind, Sun and the Economics of Flexible Power Systems, OECD/ IEA, Paris. IEA (2011), Solar Energy Perspectives, Renewable Energy Technologies, OECD/IEA, Paris. IEA (2010), TechnologyRoadmap: Concentrating Solar Power, OECD/IEA, Paris.

Jorgenson, J., P. Denholm and M. Mehos (2014), Estimating the Value of Utility-Scale Solar Technologies in California under a 40% Renewable Portfolio Standard, NREL/TP-6A20-61695, May.

RED electrica de España (REE) (2014), The Spanish Electricity System – Preliminary Report 2013, RED, Madrid, Spain, http://www.ree.es/sites/default/files/downloadable/preliminary_report_2013.pdf.

 

 

REFERENCES

DOE/NETL. August 28, 2012. Role of Alternative Energy Sources: Solar Thermal Technology Assessment. Department of Energy, National Energy Technology Laboratory.

NREL. 2011a. Solar Radiation Data Manual for Flat Plate and Concentrating Collectors. National Renewable Energy Laboratory.

NREL. 2011b. U.S. Solar Radiation Resource Maps: Atlas for the Solar Radiation Data Manual for Flat Plate and Concentrating Collectors. National Renewable Energy Laboratory.

Maps: http://www.nrel.gov/gis/solar.html

NREL. 2012. Concentrating solar resource of the united states. National Renewable Energy Laboratory.

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Concentrated Solar Power: Water Constraints

CRS. 2009. Water Issues of Concentrating Solar Power (CSP) Electricity in the U.S. Southwest. Congressional Research Service.

As you can see in the two maps below, the best sites for CSP are also the most water challenged.

CSP water constraint map USA

 

 

 

 

 

 

 

 

Source: EPRI. 2003. A Survey of Water Use and Sustainability in the United States with a Focus on Power Generation

CSP NREL capacity in 2050

 

 

 

 

 

 

 

 

 

 

Source: N. Blair, Concentrating Solar Deployment Systems (CSDS) – A New Model for Estimating U.S. Concentrating solar Power Market Potential (undated).

Growing populations and changing values have increased demands on water supplies and river systems, resulting in water use and management conflicts throughout the country, particularly in the West. In many western states, agricultural water needs can be in direct conflict with urban needs, as well as with water for thermoelectric cooling, threatened and endangered species, recreation, and scenic enjoyment. Debate over western water resources revolves around the issue of how best to plan for and manage the use of this renewable, yet sometimes scarce and increasingly sought after, resource. Traditional users of water supplies often are wary of new water demands that may compete or result in reduced deliveries to farms (leading to lost agricultural production). Deployment of CSP would add an additional demand to existing freshwater competition in the Southwest.

The Western Governors’ Association has established a goal of 8 GW by 2015 for solar energy capacity. 15 If this goal is achieved through wet-cooled CSP without storage (i.e., with a 25% capacity factor), the water requirements would be roughly 43 thousand acre-feet per year.If the premium solar sites are selected for these first investments, they likely would be concentrated in Arizona and California. To provide a sense of scale for this water consumption, it can be compared to the overall state-level water consumption. For example, if all of the 8 GW was constructed in Arizona, the increased water demand would represent roughly 1% of the state’s consumptive water use.

NREL projected as part of its Concentrating Solar Deployment System (CSDS) that 55 GW of CSP would be deployed by 2050 and assumed that the CSP fac ilities would all have six hours of storage. 18 NREL estimated the mean capacity factor for these facilities at 43%.  If 55 GW of capacity by 2050 is achieved using wet cooling, the water requirements would be roughly 505 acre feet per year. CSP water use would be less if more water-efficient cooling is employed and if not all the facilities under the 55 GW deployment projection have thermal storage. Alternatively, electricity generated and water use could be higher if 12 hours of thermal storage are employed in some or all facilities.

A Department of Energy (DOE) report, Concentrating Solar Power Commercial Application Study: Reducing Water Consumption of Concentrating Solar Power Electricity Generation , found that dry cooling could reduce water consumption to roughly 80 gal/MWh for solar troughs and 90 gal/MWh for solar towers, compared to the cooling water consumption shown in Table 1. However, DOE also found that electricity generation at a dry-cooled facility dropped off at ambient temperatures above 100°F. Dry cooling, thus, would reduce generation on the same hot days when summer peak electricity demand is greatest. For parabolic troughs in the Southwest, the benefit in the reduction in water consumption from dry cooling resulted in cost increases of 2% to 9% and a reduction in energy generation of 4.5% to 5%. The cost and energy generation penalties for dry cooling depend largely on how much time a facility has ambient temperature above 100°F.

Many of the counties identified as potential locations for CSP also were identified by EPRI as having some level of susceptibility to water supply constraints. The potential use of water by CSP in moderately constrained counties (e.g., Grant and Luna, NM) and in highly constrained counties (e.g., La Paz and Maricopa, AZ) may lead to the adoption of or requirement for more freshwater-efficient CSP facilities. For some Southwest counties with relatively low water use, large-scale deployment of CSP, even with water-efficient cooling technologies, could significantly increase the demand for water in the county (e.g., Grant, NM, and Mineral, NV).

According to NREL’s analysis, significant amounts of the 55 GW generated would be transmitted outside of the CSP-generating states, thereby resulting in a virtual export of the water resources of the producing states to the consuming states. 21 The higher the water consumed per kilowatt-hour, the more the Southwest’s limited water resources would be virtually exported to other regions. The virtual export of water raises policy questions about concentrating electricity generation and its impacts in a few counties and states while its benefits are distributed more broadly. Virtual water imports and exports, however, are not unique to electricity. For example, water is embedded in locally produced agricultural products and manufactured goods that are distributed nationally or globally.

CSP facilities using wet cooling can consume more water per unit of electricity generated than traditional fossil fuel facilities with wet cooling. Options exist for reducing the freshwater consumed by CSP and other thermoelectric facilities. Available freshwater-efficient cooling options, however, often reduce the quantity of electricity produced and increase electricity production costs, and generally do not eliminate water resource impacts.

No water is used or consumed in dry cooling. Air, however, has a much lower capacity to carry heat than water; therefore, dry cooling generally is less efficient than wet cooling in removing heat. 7 Often, massive cooling fans are used to remove the heat from the pipe array in dry cooling. These fans consume a portion of the electricity generated by the power plant. Although dry cooling reduces water use, its consumption of energy for cooling fans and reduction of thermal efficiency of the steam turbines, especially on the hottest days of the year, when summer-peaking utilities most need power, is a significant factor impeding its adoption.

The Electric Power Research Institute (EPRI) developed an index of the susceptibility of U.S. counties to water supply constraints. The index was derived by combining information on the extent of development of available renewable water supply, groundwater use, endangered species, drought susceptibility, estimated growth in water use, and summer deficits in water supply. EPRI produced Figure 1 , which shows the susceptibility to constrained water supplies. Comparing the water constraint index to NREL’s projection of CSP deployment by 2050, in Figure 2, shows overlap, particularly in Arizona and California. NREL’s analysis did not consider water availability as a constraint on CSP deployment.

CSP water intensity of electricity by technology fossil nuclear geothermal coal etc

 

 

 

 

 

 

 

 

 

Source: Unless otherwise noted, data calculated from DOE, Energy Demands on Water Resources: Report to Congress on the Interdependency of Energy and Water , Dec. 2006. Notes: a. Data is for cooling tower technology, b. DOE, Energy Demands on Water Resources: Report to Congress on the Interdependency of Energy and Water, included some of the other water consumed onsite at the generation facility, but appears not to have captured all of the non-cooling water consumed. Collection and dissemination of data that captures all non-cooling water consumed would improve comparison across technologies. c. DOE, Concentrating Solar Power Commercial Application Study: Reducing Water Consumption of Concentrating Solar Power Electricity Generation (undated) This source captured more of the non-cooling water consumed during generation than the source cited in note b. d. NREL, Fuel from the Sky: Solar Power’s Potential for Western Energy Supply , NREL/SR-550-32160 (July 2002), p. 99. e. CRS provided note. f. Cooling ponds, which are commonly used at nuclear facilities, consume roughly 720 gal/MWh. g. IGCC is Integrated Gasification Combined-Cycle.

Capacity factors for CSP plants with storage are highly uncertain given the early stage of CSP storage technology. As the cost of thermal storage is reduced, future parabolic trough plants could yield capacity factors greater than 70%, competing directly with future baseload combined cycle plants or coal plants. 13 Increased capacity factors mean more energy is generated at a facility, and represent an increase in the quantity of water consumed for each MW of installed capacity. Therefore, without knowing the capacity factor, projections of installed capacity in the Southwest provide incomplete information for producing reliable estimates of the water that may be required for future CSP installations.

This concentration of CSP in a region of the country with water constraints has raised questions about whether, and how, to invest in large-scale deployment of CSP. Most electricity generation requires and consumes water (see Table 1 . Wind is an exception, and PV consumes water only for washing mirrors and surfaces. 11 The water consumed per megawatt- hour (MWh) of electricity produced is referred to as the energy technology’s water intensity.

Why is there concern specifically about the CSP water footprint? CSP using wet cooling (i.e., solar trough and solar tower) consumes more water per MWh than some other generation technologies, as shown in Table 1. The water intensity of electricity from a CSP plant with wet cooling generally is higher than that of fossil fuel facilities with wet cooling. However, its water intensity is less than that of geothermal-produced electricity.

As previously discussed and as shown by comparing the second and third columns in Table 1 , the majority of water consumption at a CSP facility occurs during the cooling process. The fourth column in Table 1 depicts the water consumed in producing the fuel source; this water consumption generally does not occur at the same location as generation. Although CSP cooling technologies are generally the same as those used in traditional thermoelectric facilities, the CSP water footprint is greater due to CSP’s lower net steam cycle efficiency. Options exist for reducing the water consumed by thermoelectric facilities, including CSP facilities; however, with current technology, these options reduce the quantity of energy produced and increase the energy production cost.

A February 2009 memo from the Regional Director of the Pacific West Region of the National Park Service (NPS) to the Acting State Director for Nevada of the Bureau of Land Management illustrates the trend toward more freshwater-efficient cooling. The memo identifies water availability and water rights issues as impacts to be evaluated in permitting of renewable energy projects on federal lands. The memo states: “In arid settings, the increased water demand from concentrating solar energy systems employing water-cooled technology could strain limited water resources already under development pressure from urbanization, irrigation expansion, commercial interests and mining.” 14 The memo also cites rulings in 2001 and 2002 by the Nevada State Engineer identifying reluctance to grant new water rights for water-cooled power plants.

CSP in 5 states and water use

 

 

 

 

 

 

 

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Concentrated Solar Power: location, location, location

Location, Location, Location:

CSP best locations by direct normal irradiance

 

What follows is from: SBC. June 2013. Concentrating Solar Power. SBC Energy Institute.

The best sites are between 10° and 40°, South or North. As you can see in the chart below, this makes a huge difference, a CSP in Chile might cost half as much as one in Spain. Locating a plant with a solar irradiance of 2,700 kWh/m2 would decrease the generation cost by 25% compared with the same plant with 2,100 kWh/m2. Minimum suitable DNI for CSP is 2000 kWh/m²/year.

CSP DNI and cost

 

The problem with less than 10° north or south is that the atmosphere is usually too cloudy and wet in summer, and above 40° the weather is too cloudy. DNI is also significantly better at higher altitudes, where absorption and scattering of sunlight are much lower. DNI looks also to be related to land mass, with levels higher over the continent of Africa than the island chains of the Caribbean and Indonesia.

CSP best locations

 

CSP installed capacity was just 2.8 GW at the end of 2012. Investment in CSP very limited, with 18 USD billion invested in 2011 compared with 125 USD billion for solar PV and 84 USD billion for Wind. pain and the US dominate the market, with 69% and 28% of installed capacity respectively. The US should continue to drive the market, with 3.4 GW of capacity additions by 2017. CSP’s land requirement averages 50 MW per km², midway between solar PV and Wind.

Water use

As you can see, the best places are deserts where there’s little water. Like any thermal power plant, CSP needs water for cooling processes, which may have a significant environmental impact in arid and semi-arid areas.

CSP water consumption liters per MWh

 

 

 

 

 

 

 

Maximum Water consumption of various plants liters/MWh: 3,780   CSP – Fresnel, 3,024 CSP – Parabolic Trough (294 dry cool), 2,835 CSP – Solar Tower (340 dry cool),  19 Solar PV. Source: CRS (2009), “Water Issues of Concentrating Solar Power (CSP) Electricity in the U.S. Southwest

Water consumption refers to water that disappears or is diverted from its source, for example by evaporation, incorporation into crops or industrial processes, drinking water…It is smaller than water withdrawal, which refers to water that is essentially “sucked up” for a given use, but then returned to its source.

Unless dry cooling technology is used, CSP requires a significant volume of water for cooling and condensing processes.  But dry cooling is more costly, with efficiency reduced by up to 7% because more energy is required to power the fans and because higher re-cooling temperatures result in higher condensing pressures and temperatures. As a consequence, 2-10% more investment is required to achieve the same annual energy output as a water-cooled system.

Water has several advantages. Direct steam generation, which uses water as the direct working medium rather than oil, allows a higher process temperature and increases efficiency. Higher steam temperature (up to 500°C instead of maximum 390ºC with oil) results in higher efficiency and lower investment and O&M costs due to simpler balance of plant configurations (no need to circulate a second fluid, which in turn reduces pumping power and parasitic losses).  And finally, there’s a reduced environmental risks because oil is replaced with water

CSP 8-10% of global electricity?

In the long run, the International Energy Agency (IEA) estimates that CSP would need to meet 8%-10% of global electricity demand by 2050 to limit the average global temperature increase to 2°C, requiring an installed capacity of 800 GW.  By comparison, 2,000 GW of solar PV capacity is required to supply the same amount of electricity. The higher load factor for CSP explains this difference.

For CSP to meet 8% of electricity demand, significant deployment outside the OECD and China would be required.  That will require long-distance HVDC transmission lines and add significantly to costs.

The IEA believes the LCOE of CSP would need to fall by more than 75% for their plan to succeed mainly via economies of scale, decrease in component costs and higher efficiency.

Opponents such as Hermann Scheer argue that the project is unrealistic and potentially harmful. Most critics cite the monumental initial cost and the energy penalty of long-distance power transmission, but also security of supply concerns for Europe, arising from the MENA region’s political stability. (The Desertec Industrial Initiative is a private-sector consortium proposed in 2009 by the Club of Rome with the support of the German Aerospace Center (DLR), which promotes large-scale renewable energy projects involving the European Union and Middle East and North Africa. DII is composed of powerful stakeholders and is dominated by companies such as German RWE, Munich Re or Deutsche Bank, but also Spanish Abengoa Solar, Swiss ABB or Algeria agro-food Cevital).

Huge amount of development needed

There is no aspect of CSP which doesn’t need drastic improvement in cost and performance to make these financially feasible, and research is being done on every component:

Concentrators & receivers: 1) Seek an alternative to conventional rear-silvered glass mirrors (e.g. polymer-based films); 2) Develop a tracking system to track the sun and ensure that reflection is optimized; 3) Improve the solar field set-up.
Heat Fluid Transfer & Storage: 1) Seek new heat transfer fluids and storage media (e.g. phase change material, molten salts); 2) Develop Phase Change thermal storage for all direct steam generation solar plants.
Central receivers: 1) Develop air receivers with Rankine or Brayton cycle; 2) Develop solar tower with ultra/supercritical steam cycle; 3) Develop multi-tower set up.
Develop ground and satellite modeling of solar resources: 1) Improve satellite algorithms to obtain higher spatial resolutions to map high DNI areas better; 2) Develop sensor systems, computing systems and software to optimize sun-tracking systems, adapt to the environment (such as high wind conditions), and to control engine use.

Not fossil free: Almost all existing CSP plants use a back-up fuel (usually natural gas) to substitute or complement thermal storage.

Cost

CSP is a capital-intensive technology. Initial investment, dominated by solar field equipment and labor, ranges from $2,500 to $10,200 USD per kW mainly depending on capacity factor and storage size – and accounts on average for 84% of the electricity generation costs of CSP. The remaining 16% consist mainly of fixed Operation and Maintenance (O&M) costs. Fixed O&M averages around 70 USD per kW per year, while variable maintenance is limited to around 3 USD per MWh.

Although fuel costs are low, Operation & Maintenance (O&M) costs at CSP plants are still significant, at around 30 USD/MWh, the main components are replacing mirrors & receivers due to glass breakage, cleaning the mirrors and insuring the plant.

Depending on the boundary conditions, in particular solar irradiation resource, the levelized cost of electricity (LCOE) from CSP ranges from $140 to $360 USD per MWh.

The Desertec Industrial Initiative is promoting the installation of CSP plants in the sun-rich MENA deserts, with the aim of CSP’s contribution to European electricity supply reaching up to 16% by 2050. However, this 400 USD billion energy plan has sometimes been criticized on its economics and local fall-throughs.

Parabolic Trough 6 to 8h storage: $ 7,100 – 9,800 USD/kW Capital cost, 40% to 53% capacity factor.

Solar Tower 6 to 7.5h storage: $ 6,300 – 7,500 USD/kW Capital cost, 40% to 45% capacity factor.

Solar Tower 12 to 15h storage: $ 9,000 – 10,500 USD/kW Capital cost, 65% to 80% capacity factor.

References

Abengoa Solar – Ch. Breyer and A. Gerlach (2011), “Concentrating Solar Power A Sustainable and Dispatchable Power Option”
Bloomberg New Energy Finance – BNEF (2012), online database
Centro de Investigaciones Energéticas, Medioambientales y Tecnológicas – CIEMAT (2007), “Overview on Direct Steam Generation (DSG)and Experience at the Plataforma Solar de Almería (PSA)”
Chatham House (2009), “Who owns our Low Carbon Future? Intellectual Property and Energy Technologies”
Congressional Research Service (2009), “Water Issues of Concentrating Solar Power (CSP) Electricity in the U.S. Southwest”
Deutsches Zentrum für Luft und Raumfahrt – DLR (2004), “European Concentrated Solar Thermal Road-Mapping”
Desertec Industrial Initiative – DII (2012), “Desert Power 2050: Perspectives on a Sustainable Power System for EUMENA”
European Academies Science Advisory Council – EASAC (2011), “Concentrating solar power: its potential contribution to a sustainable energy future”
European Commission Joint Research Center – EC JRC (2011), “Capacities Map 2011 – Update on the R&D Investment in Three Selected Priority Technologies within the European Strategic Energy Technology Plan: Wind, PV and CSP”
European Solar Thermal Electricity Association – ESTELA (2010), “Solar Thermal Electricity 2025 – Clean electricity on demand: attractive STE cost stabilize energy production”
Intergovernmental Panel on Climate Change –IPCC (2011), “Special report on renewable energy”
International Energy Agency – IEA (2012), “Energy Technology Perspectives 2012”
International Energy Agency – IEA (2011), “Solar Energy Perspectives”
International Energy Agency – IEA (2011), “Annual Report – Implement Agreement on Photovoltaic Power System”
International Energy Agency – IEA (2011), “Harnessing Variable Renewables – A guide to balancing challenge”
International Energy Agency – IEA (2009), “Concentrating Solar Power – Technology Roadmap”
International Renewable Energy Agency – IRENA (2012), “Cost analysis series. Concentrating Solar Power”
International Renewable Energy Agency – IRENA (2012), “Water Desalination Using Renewable Energy – Technology Brief”
Massachusetts Institute of Technology – MIT (2011), “The Future of Electric Grid
Natural Resources Defense Council – NRDC (2012) “Heating Up India’s Solar Thermal Market under the National Solar Mission”
National Renewable Energy Laboratory – NREL (2012), SolarPaces online database (http://www.nrel.gov/csp/solarpaces/by_project.cfm)
United Nations Environment Programme – UNEP (2012), “Global Trends in renewable Investment 2012”

 

 

 

 

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Short-circuiting a solar boom in Japan

Spain is still feeling the painful effects of the costs of overbuilt solar PV, and now Japan is finding itself in the same position.  This article does a lousy job of explaining that the grid must be in exact supply and demand balance or the grid can fail. It was designed for one-way centralized power output, which grid operators can “see”. Distributed generation is invisible and going the wrong way, potentially overloading lines and other equipment, which can damage it and bring the grid down.  See my posts in Energy / Electric Grid / Grid Instability Distributed Generation, and Renewable Integration for more background on these issues.

Soble, J. March 3, 2015. Japan’s Growth in Solar Power Falters as Utilities Balk. New York Times.

Solar use in Japan has exploded over the last 2 years as part of an ambitious national effort to promote renewable energy. But the technology’s future role is now in doubt.

Utilities say their infrastructure cannot handle the swelling army of solar entrepreneurs intent on selling their power.

Like other countries that have promoted the technology with generous state support, Japan is also struggling with the financial and technical consequences of its rapid solar growth. Solar power here is costly for consumers because of high state-mandated prices, and handling the fluctuating output of thousands of mostly small solar producers is tricky for utilities. Necessary improvements in the infrastructure have not kept pace, experts say.

Utilities need to install more hardware — transmission cables, substations and the like — and develop new kinds of expertise to avoid disruptions. To make renewables work in reality, they have to be properly connected to the power system.

Installed solar capacity roughly doubled  since 2012, when a law took effect requiring utilities to buy renewable energy from outside producers at rates far above market prices. By last summer it stood at 3.4 gigawatts, about equal to the output of three modern nuclear reactors but only when the sun was shining at full strength.

An additional 8.4 gigawatts’ worth of projects are planned, imore power than the region consumes on some low-demand days — and far too much for Kyushu Electric’s grid to handle without the risk of failures, the utility argues.  New transmission cables are being laid but progress is slowed by the expensive task of securing land rights.

Solar projects have already changed the landscape and economy in Kyushu. They have taken over reservoirs, bankrupt golf courses and idle industrial parks, as well as the more familiar locations of residential rooftops. The largest ones, like the Nanatsushima Mega-Solar Power Plant in Kagoshima, which opened in 2013, cover areas bigger than 100 football fields.

For all the frantic building, however, Japan still produces less solar power than many other countries. Nationwide, just 2.2 percent of its electricity came from any renewable source in 2014 (excluding hydropower from dams).

Catching up [to other nations] would be expensive, even if all the necessary infrastructure existed. Japan’s financial incentives for solar power and other renewables are the highest in the world — about twice the level of Germany, depending on the type of installation.

According to the government, if every solar plant now on the drawing board were actually to be built, it would cost users $23 billion, four times the premium they’re paying now.

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Tuberculosis

The fear is that a fast-spreading, anti-biotic resistant strain will spread via mutation or bioterrorism.

WHO estimates that two billion people — one third of the world’s population — are infected with Mycobacterium tuberculosis.

22 October 2014. Improved data reveals higher global burden of tuberculosis. World Health Organization. The multidrug-resistant TB (MDR-TB) crisis continues, with an estimated 480,000 new cases in 2013. Worldwide, about 3.5% of all people who developed TB in 2013 had this form of the disease, which is much harder to treat and has significantly poorer cure rates. While the estimated percentage of new TB cases that have MDR-TB globally remains unchanged, there are severe epidemics in some regions, particularly in Eastern Europe and Central Asia. In many settings around the world, the treatment success rate is alarmingly low. Furthermore, extensively drug-resistant TB (XDR-TB), which is even more expensive and difficult to treat than MDR-TB, has now been reported in 100 countries.

Wilson, C. 21 January 2015. Soviet Union fall helped drug-resistant TB to take off. NewScientist.

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Drought in the news

Keep up with the latest drought news at the U.S. Drought Monitor.

A ‘megadrought’ will grip U.S. in the coming decades, NASA researchers say. Researchers from NASA and Cornell and Columbia universities warned of an 80% chance of mega-droughts lasting up to 40 years in the southwest and central USA, with major water shortages. This dries out vegetation, which can lead to monster wildfires in like recent fires in southern Arizona and parts of California.

There’s a 50% chance Lake Mead will dry up by 2050 and a 10% chance it will dry up by 2021.

 

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Syrian conflict due to climate change drought

Fountain, H. March 2, 2015. Researchers Link Syrian Conflict to a Drought Made Worse by Climate Change. New York Times.

Drawing one of the strongest links yet between global warming and human conflict, researchers said Monday that an extreme drought in Syria between 2006 and 2009 was most likely due to climate change, and that the drought was a factor in the violent uprising that began there in 2011.

Researchers said the drought “had a catalytic effect.” They cited studies that showed that the extreme dryness, combined with other factors, including misguided agricultural and water-use policies of the Syrian government, caused crop failures that led to the migration of as many as 1.5 million people from rural to urban areas. This in turn added to social stresses that eventually resulted in the uprising against President Bashar al-Assad in March 2011.

What began as civil war has since escalated into a multifaceted conflict, with at least 200,000 deaths. The United Nations estimates that half of the country’s 22 million people have been affected, with more than six million having been internally displaced.

The drought was the worst in the country in modern times, and in a study published Monday in Proceedings of the National Academy of Sciences, the scientists laid the blame for it on a century-long trend toward warmer and drier conditions in the Eastern Mediterranean, rather than on natural climate variability.

The researchers said this trend matched computer simulations of how the region responds to increases in greenhouse-gas emissions, and appeared to be due to two factors: a weakening of winds that bring moisture-laden air from the Mediterranean and hotter temperatures that cause more evaporation.

Colin P. Kelley, the lead author of the study, said he and his colleagues found that while Syria and the rest of the region known as the Fertile Crescent were normally subject to periodic dry periods, “a drought this severe was two to three times more likely” because of the increasing aridity in the region.

Dr. Kelley, who did the research while at Lamont-Doherty Earth Observatory and is now at the University of California at Santa Barbara, said there was no apparent natural cause for the warming and drying trend, which developed over the last 100 years, when humans’ effect on climate has been greatest.

The researchers said that there were many factors that contributed to the chaos, including the influx of 1.5 million refugees from Iraq, and that it was impossible to quantify the effect of any one event like a drought.

A working group of the Intergovernmental Panel on Climate Change wrote in 2014 that there was “justifiable common concern” that climate change increased the risk of armed conflict in certain circumstances.

The United States military has described climate change as a “threat multiplier” that may lead to greater instability in parts of the world.

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My comment: Scientists believe that the southwest and central regions of the United States have an 85 percent chance of a mega-drought lasting 35 years or more between 2050 and 2100.  

Lake Mead could dry up by 2021 (50% chance), and Lake Powell is in trouble too, along with the 8 million plus people who depend on them. While we were in Nevada in February 2015, we heard that the courts had prevented Las Vegas from claiming water elsewhere in the state.

Mass migrations are coming to your neighborhood soon….though communities in California out of potable drinking water haven’t moved because they can’t afford to. 

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Charles A. S. Hall Conventional oil peak was 2005

The global production of conventional oil began to decline in 2005, and has followed a path over the last 11 years very close to our scenarios assuming low estimates of extractable ultimate resource (1.9 Gbbl)

John L. Hallock Jr., Wei Wub, Charles A.S. Hall, et al. Forecasting the limits to the availability and diversity of global conventional oil supply: Validation? Energy. Volume 64, 1 January 2014, Pages 130–153

Abstract:  Oil and related products continue to be prime enablers of the maintenance and growth of nearly all of the world’s economies. The dramatic increase in the price of oil through mid-2008, along with the coincident (and possibly resultant) global recession, highlight our continued vulnerability to future limitations in the supply of cheap oil. The very large differences between the various estimates of the original volume of extractable conventional oil present on earth (EUR) have, at best, fostered uncertainty of the risk of future supply limitations among planners and policy makers, and at worse lulled the world into a false sense of security. In 2002 we modeled future oil production in 46 nation-units and the world by using a three-phase, Hubbert-based approach that produced trajectories dependent on settings for EUR (extractable ultimate resource), demand growth, percent of oil resource extracted at decline, and maximum allowable rates of production growth. We analyzed the sensitivity of the date of onset of decline for oil production to changes in each of these input parameters. In this current effort, we compare the last eleven years of empirical oil production data to our earlier forecast scenarios to evaluate which settings of EUR and other input parameters had created the most accurate projections. When combined with proper input settings, our model consistently generated trajectories for oil production that closely approximated the empirical data at both the national and the global level. In general, the lowest EUR scenarios were the most consistent with the empirical data at the global level and for most countries, while scenarios based on the mid and high EUR estimates overestimated production rates by wide margins globally. The global production of conventional oil began to decline in 2005, and has followed a path over the last 11 years very close to our scenarios assuming low estimates of EUR (1.9 Gbbl). Production in most nations is declining, with historical profiles generally consistent with Hubbert’s premises. While new conventional oil discoveries and production starts are expected in the near term, the magnitudes necessary to increase our simulated production trajectories by even 1.0% per year over the next 10 years would represent a large departure from current trends. Our now well-validated simulations are at significant variance from many recent “predictions” of extensive future availability of conventional oil.

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