By Antonio Ruffini, Editor, ESI Africa magazine

Concentrated Solar Power (CSP) at about or over R2.50/kWh cannot compete with other renewables on price today, and it is focusing on other aspects of value addition to make its case in South Africa.

South Africa has two CSP projects under construction and a third recently achieved financial closure. In addition, Eskom has committed to building a 100 MW CSP tower project. The two projects under construction are Abengoa’s KaXu 100 MW parabolic trough plant some 40 km northwest of Pofadder and its Khi 50 MW tower project about 20 km south of Upington. These two projects came in at an averaged out tariff bid price of R2.69/kWh and will require a capital expenditure of some R11.4 billion.

CSP pic1

Aerial view of Abengoa’s Solnova 1
and 3 parabolic trough plants in Spain.

Abengoa is one of the world’s most experienced developers of CSP projects, having been in this field for 20 years, and South Africa benefits from its projects forming part of a larger portfolio. Abengoa has 743 MW of CSP facilities in commercial operation and 910 MW under construction. These cover all the major CSP technologies including troughs, towers and thermal storage.

Louis van Heerden, general manager of Abengoa South Africa, says it opted for different technologies for its two projects in South Africa because in each case the technology is suited to the site. “If you take a step back and compare solar towers versus parabolic troughs, for trough systems you need economies of scale. One won’t easily look at trough plants below 50 MW, and the entry level probably should be 100 MW today, ideally touching 300 MW, which is where this technology really comes into its own.

“With towers the temperature and pressure are higher, which gives them inherently higher efficiency than parabolic trough technology. However, there comes a distance from the tower where putting down heliostats will no longer provide sufficient benefits of focusing energy onto the tower. Then one has to look at multiple towers, and there are issues with that. Troughs provide direct steam generation, and with tower technology we are also looking at directly heating the air (air receiver) and putting this into the turbine. Overall the technological advantages of towers versus troughs are not clear-cut.”

In areas where there is more cloud, and the sunlight is more transient, a tower provides easier control. The trough technology is like base load. Once up, it likes to run, with the oil system flowing. “A lot of people think the tower is the future for CSP, but I believe both have their place,” van Heerden says.

Abengoa built the first commercial tower projects, and to date the world’s largest, its PS10 (10 MW) and PS20 (20 MW). This means that Khi represents a scaling up in tower technology for the group.

CSP pic2

View of a parabolic trough collector loop.

Abengoa followed up on its first small tower, PS10, progressing to PS20, and developed its pilot Eureka tower that took the steam system up to superheated levels of 550OC and became the blueprint for the PS50 design which is the plant in Upington. Van Heerden says that in spite of the new size precedent there is no significant technology risk involved in the project. “Had we not gone through the research process, there would have been some scale-up risk. We are doing nothing significantly new, by having a 200 m tower versus a 140 m tower. The receivers are the same as those of the PS20 and Eureka, though the tower will be a solid tower unlike PS20. We were able to convince the lenders that there is very little scale-up risk.”

Abengoa has numerous parabolic trough plants in operation, the Solnova 1, 3 and 4 plants of 50 MW each, as well as eight others rated at 50 MW. Those are the Helioenergy 1 & 2, the Solacor 1 & 2, the Helios 1 & 2 and the Solaben 2 & 3 plants. All these plants are based in Europe where the company also has a further two 50 MW trough plants under construction.

In the USA Abengoa has been constructing two 280 MW CSP projects, Solana a parabolic trough facility with six hours of storage, and the Mojave facility. In Algeria Abengoa has the 150 MW hybrid gas and CSP Hassi R’mel plant in operation and it has just finished building the 100 MW Shams 1 parabolic trough plant in Abu Dhabi.

Khi is located on a brownfields site in that the land is already disturbed by old diggings, which makes the environmental implications of such a project less severe, and 600 hectares is permitted for the facility. Khi is located four kilometres from an Eskom transmission line which lies to the south of the site. This and the KaXu project are owned 51% by Abengoa, 20% by community trusts and 29% by the Industrial Development Corporation (IDC). The construction period for Khi is 24 months and with early works having begun in November 2012 it is expected to be complete by November 2014.

Van Heerden expects that Khi will produce more than 180 GWh/year. The central receiver plant will comprise three receiver cavities and there will be three solar field segments, which in total comprise 4,120 heliostats. Each heliostat is about 140 m2 and each of the three solar field segments has its own role. The eastern field will focus on a cavity receiver housing a saturated steam evaporator, as will the western field, while the southern field will focus on a cavity receiver housing the superheater. The control system will allow some of the heliostats located within the specific segments to refocus to other receivers at certain times during the day to optimise power production.

A steam/water receiver cooling system will be used. The thermal energy storage system at Khi is direct water/steam storage with multiple tanks and 19 accumulators. An electrical boiler will provide the pre-heating function, and act as the auxiliary power supply. The condenser will be a draft air cooled system.

Water will flow to the evaporators which produce the saturated steam sent to the horizontal tube superheater. The superheater will have a nameplate rating of 63 MWth. Excess steam will be supplied to the storage system. The maximum thermal power rating of the evaporators will be 90 MWth each. The turbine maximum inlet pressure is 120 bar.

Van Heerden says that once the sun goes down the plant can put in two to three hours of further generation. Alternatively it can keep the turbine hot, keep the seal up and run from 06:00. “We have got different operational regimes figured out.”

The KaXu project, which is located just off the R358 Onseepkans road in the Northern Cape, covers a permitted area of 1,100 hectares. The Eskom Paulputs transmission substation lies on the Abengoa property. This 100 MW parabolic trough project is expected to generate about 330 GWh/year. It makes use of Abengoa’s E2 collector and comprises 300 loops. There are four collectors per loop which takes the number of collectors to 1,200. There are 10 modules per collector and the distance between collector rows is 18 metres. The total collector surface will be greater than 800,000 m2.

CSP pic3a

The 280 MW Mojave CSP project in
California.

KaXu incorporates a two tank molten salt thermal storage system with a salt volume of greater than 10,000 m3. The condenser is air cooled. The receiver cooling fluid will be synthetic oil such as Dowtherm A or something similar. The turbine live steam temperature design is for greater than or equal to 375OC and the pressure is about or greater than 100 bar.

The construction time for the KaXu project is 27 months, and as it began at the same time as Khi, November 2012, the completion date should be around February 2015. The engineering procurement construction (EPC) contractor is Abeinsa and the operations and maintenance will be done by Abengoa Solar.

Both of the plants under construction will use dry cooling, with the annual consumption of water at the 50 MW Khi power station projected to be 200,000 to 300,000 m3, and that at the 100 MW KaXu station to be 400,000 to 600,000 m3. “If wet cooled, the water consumption would be about two to three times these levels,” Van Heerden says. He argues that CSP plants are not particularly water intensive. “In comparison with a vineyard on the Orange River which would look for an allocation of 15,000 m3/ha per year, the annual usage for CSP is between 700 m3 and 1,000 m3/ha.” At Khi the water usage is anticipated to be 52% for mirror cleaning, 47% for balance of plant and 1% for potable water. At KaXu it is 41% for mirror cleaning, 58% for balance of plant and 1% for potable water.

The dry cooling has resulted in higher capital costs, but the advantages are the reduced water usage and water cost savings, as well as reduced capital costs associated with water supply lines and pumping. The water for KaXu will be pumped from the Gariep River about 29 km distant.

While Abengoa comes from a background of projects in the world’s two leading CSP markets to date, Spain and the USA, ACWA Power, the developer of the renewable energy independent power producer programme (REIPPP) window two Bokpoort 50 MW project, hails from the country that could dominate the future of CSP. The Bokpoort project offered a bid price of R2.51 per kWh and will require a capital expenditure of R4.5 billion.

ACWA is an emerging market utility company that develops owns and operates power and water assets. It was formed in Saudi Arabia which has committed to building 41 GW of renewables capacity by 2030, of which 25 GW will be CSP (another 21 GW will be photovoltaic (PV) and the remainder will be made up of wind). That would place Saudi Arabia among the leaders of the emerging CSP sector, though ACWA is not focused only on CSP or only on renewables.

ACWA has its headquarters in Riyadh and its international offices in Dubai. Its clients are investment grade sovereign linked off-takers, and the company is aiming to triple its current 13 GW of existing pre-construction and under construction capacity to 40 GW by 2018. About half of its 13,000 MW is already in commercial operation, and the Bokpoort project counts as one of those in pre-construction. ACWA also won a 160 MW CSP project in Morocco.

The Bokpoort plant is to be a wet cooled 50 MW parabolic trough facility with nine hours of storage. While ACWA is the key sponsor, the project developer is Solafrica. The facility will have 180 loops and about 1,300 MWh of thermal storage. The turbine is a single case condensing type.

The two window one projects provide an estimated 20% of local content, while the window two project escalates local content to about 35% – 40% and if any CSP projects are allocated in window three, this will remain roughly the same. The local content in the Bokpoort project is to come in areas such as civil works, provision of valves, actuators, pressure vessels, storage tanks, piping, and cabling. Specialised items such as the parabolic mirrors, collector structure and precision tracking systems will be imported.

The consensus among developers of CSP projects is that 100 MW a year is not enough to encourage manufacturers to set up plant in South Africa for further local construction. “Likely, it would require at least 200 MW of annual installations for at least 10 years to attract suppliers to come and invest in manufacturing infrastructure in the country,” Christoph Ehlers, ACWA business director for South Africa, says. “Otherwise the localisation percentage will remain at about 40%.”

CSP pic4

Solar field of mirrors at the ISCC plant in Morocco.

South Africa has planned for 1,200 MW of CSP up until 2030 based on its current integrated resource plan (IRP), and this is unlikely to be sufficient to provide the critical mass and economics of scale to encourage further local manufacture. In addition to the 200 MW committed to thus far in windows one and two, a further 400 MW of CSP was allocated in the recent determination for independent power producers (IPPs), though there is not yet clarity on how much of this will be made available in renewables bidding window three.

Callie Fabricius, general manager of energy planning and market development at Eskom, who is doing IRP planning on behalf of South Africa’s department of energy, says that this work takes into account not only the generation mix, but what the system operator needs. Ideally it needs up to nine hours of CSP dispatchability. “With PV and wind we have no choice and the system must take it up when it is available.” But for dispatchability, “We must incentivise IPPs to get what we want from them and flexibility has a value for the system operator.” The implication is that CSP does justify a premium to other renewables.

Abengoa says in one of its presentations comparing the case of CSP versus PV is that the latter is suited to isolated generation, small and medium scale players, and has limited technological complexity. CSP on the other hand is suited to large utilities as it requires complex installations, with a limited number of players operating in this space and these being well capitalised companies.

The Southern Africa Solar Thermal and Electricity Association (Sastela), which is lobbying government on behalf of the CSP sector, says that apart from CSP the remaining 17,000 MW of renewable energy to be allocated according to South Africa’s IRP will be generated by technologies that are intermittent by nature. These have lower capacity factors that diminish their role when viewed in terms of energy supplied versus capacity installed.

CSP pic5

Rendering of the PS50 tower
technology upon which the
Khi project is based.

Pancho Ndebele, Sastela president, says that CSP should not be just seen as competing with other renewables, but with baseload. With new allocations having been made for baseload in South Africa, including 2,500 MW for coal IPPs, 2,600 MW for hydro including imported hydro, as well as 3,100 MW for open cycle and closed cycle gas turbines, “CSP will have to compete with new coal, and then there are the diesel peaking power stations.”

The ability of CSP to compete with diesel peaking plants is raised by Ndebele. “In its multi-year price determination (MYPD3) tariff application Eskom requested R12 billion to pay for fuel for its own peaking plant with a further R13 billion earmarked for department of energy peakers. This amounts to R25 billion for open cycle turbines running with diesel. Are there alternatives that can follow the national demand curve, can be peakers and also produce electricity at other times?”

He says there is an argument that CSP plants can hedge against gas turbine peaking stations – as the last round of bidding has essentially set a price level above which future CSP plants cannot realistically go. “Thus for the future we are looking at R2.50/kWh as the baseline with economics of scale yet to kick in versus the cost of fuelling open cycle gas turbines.”

Considering the cost of fuel for the peaking stations means that if one installs enough CSP, it could displace some of the peaking power at a lower tariff. It must be taken into account however that the diesel peaking stations are really intended to be emergency power generation rather than even peaking stations. They are not intended to run for more than 5% of the time, as while they are low cost in terms of their capital expenditure, the breakeven point for such power stations entails a maximum of 5% of availability for usage due to the high fuel costs.

That CSP is looking for ways to begin to compete with other power generation forms is a sign of intent for an option which still has to find the cost efficiencies of more mature technologies.

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