From pv magazine Global

From pv magazine global

For the energy transition, the electrification of transport, and dozens of other technological areas, the relatively short lifetime of today’s battery technologies is a persistent roadblock.

Cracks forming in the electrodes of batteries are one cause of performance loss over time, and an issue that many manufacturers are looking to engineer out of the batteries using new materials more resistant to cracking. Research published this week, however, suggests that getting rid of cracks in the cathode may have an unwanted side effect.

“Many companies are interested in making ‘million-mile’ batteries using particles that do not crack,” explained Yiyang Li, assistant professor of materials science and engineering at the University of Michigan. “Unfortunately, if the cracks are removed, the battery particles won’t be able to charge quickly without the extra surface area from those cracks.”

Conventional wisdom states that the charging speed for batteries should be improved by using cathodes made from smaller particles, since these have a higher surface area to volume ratio, shortening the distance lithium-ions have to travel.

Li and colleagues put this assumption to the test using sophisticated techniques to track the behavior of individual particles as the battery is charged. “Back when I was in graduate school, a colleague studying neuroscience showed me these arrays that they used to study individual neurons. I wondered if we can also use them to study battery particles, which are similar in size to neurons,” said Li.

The setup involved a 2x2cm chip containing 100 microelectrodes, onto which the group scattered nickel-manganese-cobalt cathode (NMC) particles. Using a needle which they say is “around 70 times thinner than a human hair,” the scientists could move the individual particles onto an electrode, allowing them to charge and discharge the particles individually. The group worked with NMC “532” material, containing 50% nickel, 30% manganese and 20% cobalt, and say they would expect similar results for any type of NMC cathode.

The experiment is described in full in the paper “Direct measurements of size-independent lithium diffusion and reaction times in individual polycrystalline battery particles,” published in Energy & Environmental Science. The results showed that the charging speed was not affected by particle size.

Li and Jinhong Min, who carried out the experiments, theorize that this could be down to the larger particles behaving more like a collection of small particles when the cathode cracks, Or that lithium-ions are able to move more quickly at the grain boundary. “Our results overturn the dominant picture of lithium transport in the most widely-used cathode material,” the two stated. “If this electrolyte cracking model is accurate, then our results show that intergranular cracking, long believed to be strongly detrimental to cycle life, is in fact essential for the ability of polycrystalline particles to (dis)charge at reasonable cycling rates.”

From pv magazine global

Soiling – where PV modules become coated with dust, dirt, sand or snow and thus receive less sunlight – is still an underestimated problem for solar power systems. Specialized solutions are now available in the form of anti-soiling glass coatings, automated and manual cleaning products, and models to predict the ways to use them most economically. But our understanding of the issue is still evolving, particularly as PV systems move into new regions with different environmental conditions, and the technology itself continues to change and improve.

A new report by IEA-PVPS Task 13 seeks to push understanding of soiling a step further, taking a detailed look at the mechanisms causing soiling right down to the size and shape of the individual particles that build up on module’s surface, and the surrounding conditions that lessen or worsen its impacts.

The report estimates that in 2018, soiling caused at least a 3% to 4% loss to global annual energy production from PV – amounting to lost revenue of over $3 billion. And this is expected to increase to around 4% to 5% this year, thanks to an increase in PV installations in regions highly prone to soiling, economic pressures, and the fact that more efficient PV modules will suffer larger losses to their output due to soiling.

The report shows that soiling is a highly site-specific issue, and that even different areas within a single site can see quite different conditions. This leads the authors to place emphasis on accurate monitoring of these as a key part of the solution.

“An ideal solution should be installable with as little maintenance as possible and be able to detect heterogeneous soiling at both module and site level with high accuracy,” the scientists said.

Meanwhile, additional work is needed to develop accurate models to predict soiling rates at a given site, with current efforts either limited to a very small area, or based only on satellite data that is too generalized to give an accurate portrayal of site conditions.

From pv magazine global

Hopefuls from 40 different countries submitted entries to the <b>pv magazine</b> Awards in 2022, with more regions represented than ever before. This reflects the industry’s increasing global relevance and the importance all regions are placing on local innovation and production.

Encouraging trends in technology are on show across all seven of our Award categories, with high efficiency n-type technology becoming more established in module manufacturing; a comeback on the cards for central inverters; new battery chemistries promising a jump in product performance and longevity; ever-more sophisticated AI applications guiding plant operation and maintenance; and companies demonstrating resilience and ingenuity in weathering the storms that the past three years have brought to the renewable energy sector, along with many other industries.

The near-200 entries received from around the globe were pored over by six juries made up of independent experts in each field. These professionals brought a wealth of experience and industry knowledge to the process and the pv magazine editorial team would like to thank each of them kindly for their time and for sharing their expertise.

And the winners are…

Modules

Winner: Huasun Himalaya G12 Series

Challenger manufacturers such as China’s Anhui Huasun Energy Co are setting the pace in HJT development. In August 2021, Huasun announced 25.26% efficiency on an M6 (166 mm) wafer device – equaling the world record. Expanding to a G12 (210 mm) wafer, the Himalaya G12 (full name: HS-210-B132DS700) peaks at 22.5% module efficiency and a 700 W output in a 66-cell format. The Himalaya offers typical HJT benefits including a lower temperature coefficient of -0.26% and up to 93% bifaciality. The real innovation, gained with cell equipment partner Maxwell, is in the cell processes used to deposit the amorphous silicon and transparent conductive oxide (TCO) layers –  reducing light absorption and boosting efficiency.

Huasun wants 20 GW of production capacity by 2025, manufacturing more-than-25.5% efficient cells by that point.

Inverters

Winner: Gamesa Electric Proteus PV

This up-to-4,700 kVA central inverter showed a careful evolution of Gamesa’s PV central devices, bringing commendable efficiency and features to match a range of demands from solar developers. The comparatively higher efficiencies and power densities from the Proteus, plus Gamesa’s well-tried liquid cooling solution, also allows for less de-rating at high temperatures. Features coming as standard include Q@Night functionality,  and operation at altitude, to be compelling, overall, as part of the efficacy of the solution.

BOS

Winner: EKO Instruments MS-80SH Pyranometer

EKO Instruments’ Class A pyranometer is packed with features that make it stand out in the market for these sensor products that provide the crucial yet often overlooked service of measuring solar irradiance at a site. The MS-80SH features an integrated dome heating system to keep the sensor free of dew and frost that can impact measurement accuracy and can cause dust and dirt to stick to the outside of the dome that houses the sensors.

The company says its pyranometer has the lowest energy consumption on the market and the heating system can be switched on or off remotely, allowing further energy savings. The product is designed for easy compatibility with data loggers and SCADA systems, and internal diagnostics systems enable users to monitor internal temperature, humidity, tilt, and roll angle without having to visit the site and carry out a physical check.

BESS

Winner: Villara Energy Systems: VillaGrid 

VillaGrid is a residential, lithium titanate (LTO) battery offering twice the continuous power of conventional lithium-ion batteries at 10 kW; four times the peak power at 30 kW; double the lifespan, via a 20-year warranty; and improved safety, as a non-flammable chemistry. Its US manufacturer says even the smallest, 5.75 kWh VillaGrid battery can back a home during a power outage.

The LTO device doesn’t require a heating or cooling system and works well in temperatures between -30 C and 55 C, outperforming other lithium-based chemistries. It can be installed at up to 10,000 feet (3,048 meters). VillaGrid is engineered to last 25 years, far outstripping the industry average of 10 years. Guaranteed end-of-warranty capacity is 70%. “Your solar panels last 25 years and so should your batteries,” Villara says.

Manufacturing

Winner: ROSI, High value module recycling

France-based ROSI offers solutions to recover silicon lost as kerf during wafer slicing, and full end-of-life treatment for solar modules. “Our goal is to realize a truly circular economy for the PV industry and beyond,” the company stated in its award application. “The high-value recycling technology allows the reintegration of recovered materials into several key European industries, such as PV, batteries, and semiconductors.”

The company expects to have its first industrial PV module recycling site up and running early this year, initially able to process 3,000 tons of module waste annually, with plans to increase to 10,000 tons next year. Unlike most PV recycling operations to date, it will focus on the recovery of high value materials locked up within the modules as well as the glass that makes up the bulk of the panel’s weight. ROSI promises to produce silver and high-purity silicon at its recycling plant, and to recover 95% of the economic value of module materials, compared to its estimate current industry practices reclaim only 35%.

Sustainability

Winner: Brighten Haiti, Solar4Schools

A presidential assassination, gang violence, outbreaks of dangerous illness, and a chronic energy shortage as a result of armed street blockades have wreaked havoc on Haitians. Gangs blockaded diesel supplies in the capital, Port au Prince, late last year, prompting the closure of schools, hospitals, and much else.

NGO Brighten Haiti’s Solar4Schools program has offered a glimmer of light.

Brighten Haiti supplies 6 kWp solar systems to schools, each of which it says it can deliver on the back of a $6,000 donation from a US sponsor. Some 54,500 students in 109 schools have benefited, according to Brighten Haiti.

Solar4Schools leverages the Secure Power islanding capability  offered by German company SMA Solar Technology, which can deliver up to 2 kW of power in the event of grid outages at a price 87% cheaper than solar-plus-storage. In sustainability terms, the program features “functioning used and blemished modules from the U.S.”

Publisher’s pick

Winner: Growatt

In January 2021, amid the COVID-19 pandemic, we awarded pv magazine’s Publisher’s Pick for 2020 to inverter manufacturer Growatt. Normally we would have not considered the same company just two years later but Growatt pulled off an amazing feat: it battled the pandemic, supply chain constraints, and a severe semiconductor chip shortage to top its 2020 revenue by 69%. This spectacular achievement, along with its continued innovation on the product and technology front, makes another Publisher’s Pick for 2022 more than well deserved.

Almost two-thirds of Growatt’s 2021 revenue of CNY 3.2 billion ($459 million) came from products sold in the Americas, Europe, the Middle East, and Africa. The Shenzhen manufacturer has emerged as a leading player in the energy transition and is on the cusp of emerging as a PV unicorn with an upcoming Hong Kong IPO worth an estimated $1 billion.

Award ceremony

Join us at the first pv magazine Award ceremony we’ve been able to hold live in a few years! Our winners will be honored from 7 p.m. (GST) on Jan. 17 at the Aloft Hotel in Abu Dhabi, in an event staged alongside the World Future Energy Summit. The ceremony will be hosted by pv magazine publisher Eckhart K Gouras and senior editor Emiliano Bellini and we hope to see you there!

From pv magazine global

As renewables come to represent a larger portion of the worldwide energy mix, and as targets are put in place to increase it further still, there are plenty of worries over the cost that radically changing our energy systems will entail. And the intermittent nature of wind and solar also creates concern about insufficient supply and possible blackouts.

The latest energy system models from Stanford University researcher Mark Jacobson, however, show that for 145 countries, the energy transition too 100% wind, water, solar and storage would pay for itself within six years, and ultimately cost less than continuing with the current energy systems.

“Worldwide, WWS reduces end use energy by 56.4%, private annual energy costs by 62.7% (from $17.8 to $6.6 trillion per year), and Social (private plus health plus climate) annual energy costs by 92.0% (from $83.2 to $6.6 trillion per year) at a present-value cost of $61.5 trillion,” Jacobson said in his most recent paper. “Thus, WWS requires less energy, costs less, and creates more jobs than business as usual.”

He described the model in “Low-cost solutions to global warming, air pollution, and energy insecurity for 145 countries, which was recently published in Energy & Environmental Science. It builds on Jacobson’s previous work by adding new countries, more recent energy consumption data from all regions, and calculations to deal with uncertainty in the future price of battery energy storage, the role batteries will play, and the development of newer technologies such as vehicle to grid. But despite these uncertainties, Jacobson is certain that technological barriers don’t present a major roadblock for the transition.

“(About) 95% of the technologies needed to implement the plans proposed are already commercialized,” he states.

The study also finds that, while jobs would be lost in the mining and fossil fuels segments, 28 million more jobs would be created than lost overall. Only Russia, Canada and parts of Africa are expected to see net job losses as a result, as these regions economies depend heavily on fossil fuels.

Though the study provides clear evidence that a full transition to 100% renewable energy is both technically and economically possible, Jacobson warns that plenty of uncertainty remains.

“Many additional uncertainties exist. One of the greatest is whether sufficient political will can be obtained to affect a transition at the rapid pace needed” he said. “However if political will can be obtained, then transitioning the world entirely to clean, renewable energy should substantially reduce energy needs, costs, air pollution mortality, global warming, and energy insecurity while creating jobs, compared with BAU.”

From pv magazine global

Improvements to solar cell technology and manufacturing processes mean that modules can be sold today with performance guarantees for up to 30 years. They usually promise to retain 80% to 90% of their initial performance by the end of this period.

However, there are still mechanisms and interactions at work between tiny particles within a PV module. And understanding them will be key to developing cells that can generate more electricity for an even longer period. Scientists led by the US Department of Energy’s National Renewable Energy Laboratory (NREL) looked at the role of UV light in some of these mechanisms, and found that in many of the latest cell designs, UV could be to blame for significant performance losses.

“Historically, the harmful effects of UV radiation have largely been associated with the aging of module packaging materials and have led to encapsulant discoloration, delamination, and backsheet cracking,” the group said. “Solar cell performance is also adversely affected by UV radiation through the generation of surface defects.”

Within a silicon solar cell, the UV light can cause damage to the passivation layers, to the silicon beneath, and at the interface between the two. The researchers tested a range of silicon cell designs under long-term exposure to UV light, to better understand damage that they could suffer in the field.

“Understanding the damaging effects of UV radiation in emerging silicon solar cell technologies will enable the identification of the underlying mechanisms that may affect both the power output and durability of modules,” they said.

They described their findings in “UV-induced degradation of high-efficiency silicon PV modules with different cell architectures,” which was recently published in Progress in Photovoltaics. Testing p-type PERC, n-type PERT, heterojunction and interdigitated back-contact cells, the group calculated average and maximum degradation rates of 0.12% per year and 0.73% per year, respectively, based on a module containing a UV-transmitting encapsulant. They also found that with bifacial cells, the rear side was more susceptible to UV induced damage.

The group noted several different mechanisms triggered by the UV that can cause damage to cells. The problem is largely related to the breakdown of hydrogen bonds that reduced the quality of the passivation layer.

They suggested a range of strategies to reduce such damage. Additives to the module encapsulant material could block UV wavelengths from reaching the cell, and low- cost materials are available to do this. However, the group warns that this could involve some discoloration of the encapsulant, resulting in initial performance losses.

Glass coatings are another way to block UV light from reaching the cell, but they require the design of a multifunctional coating material with anti-reflective and anti-soiling properties. Coatings on the front of the cell itself could also reduce UV damage.

With an average 11% power loss after 2,000 hours of UV exposure, heterojunction cells appeared to be the most vulnerable to UV damage. But the group said that more work would be needed to draw this conclusion.

“The most durable among high-efficiency cell technologies (HJ, IBC, PERC, or PERT) remains to be proven for a wide variety of makes and models of cells,” they said.

Over time, light-elevated temperature-induced degradation (LETID) can cause significant performance losses in PV modules in the field. The problem was first recognized around 2012; the industry did not know the exact cause behind it, but it has been quick to develop mitigation strategies.

Understanding the effectiveness of these strategies, and ultimately eliminating performance losses associated with LETID, requires comprehensive testing. Such testing is increasingly a requirement for module buyers wary of the financial impacts of unexpected performance losses.

A collaborative effort between scientists and industrial players across Asia, Europe and the United States has tested a range of silicon PV modules for LETID, with the aim of developing a new, applicable protocol. Their findings and the testing procedures they used will likely be adopted into a formal standard published by the International Electrotechnical Commission later this year.

“Global researchers have published many promising strategies for reducing or eliminating LETID, and there is evidence both in this work and elsewhere that manufacturers in recent years have adopted these strategies,” said Joseph Karas, a researcher at the US National Renewable Energy Laboratory. “Some modules in this work showed essentially no LETID sensitivity. Still, LETID risk is not a fully resolved matter as new wafer types and cell architectures are being adopted which might be LETID-sensitive.”

Standardized testing

The group described the testing procedures in “Results from an international interlaboratory study on light- and elevated temperature-induced degradation in solar modules,” which was recently published in Progress in Photovoltaics. The procedures primarily involve subjecting modules to high temperatures, and either directly injecting a current, or placing them under simulated sunlight at different levels, either to cause LETID degradation or initiate a recovery mechanism in already degraded modules.

By fabricating intentionally LETID sensitive modules, they were able to calibrate the procedures to maximize LETID, and could distinguish such losses from other issues. Testing was conducted over a period of four weeks, but the researchers noted that in the soon-to-be-published standard, this will be reduced to two, with a doubling of the injected current to compensate.

“This work, the forthcoming TS, and the advancing scientific understanding of LETID will help mitigate the physical and financial effects of LETID,” the researchers said. “Manufacturers will be able to test for LETID and engineer LETID-free cells and modules, module buyers will be able to evaluate potential purchases with confidence, and financial stakeholders will benefit from the reduced risk that follows from that confidence.”

It might lead to effective mitigation or even the elimination of LETID effects, but the work will nonetheless continue, so the industry can fully understand the mechanisms behind the problem. In this project, the group found differing impacts on fill factor between modules, and significant variations in LETID between individual cells within single modules – neither of which it could immediately explain.

In the United States, a three-year project investigating causes of voltage loss in cadmium selenide telluride thin films published its discovery of a new way to measure and track the mechanisms causing voltage loss within a device.

Working both with modules produced in the lab at Colorado State University, and by Ohio headquartered manufacturer First Solar, the group measured a characteristic called external radiative efficiency, that allowed it to better understand mechanisms behind voltage loss. “We learned that the main mechanism limiting voltage is not necessarily linked to defects within the bulk of the cell nor at the interfaces between different materials comprising the cell,” says Arthur Onno, assistant research professor at Arizona State University, who led the research. “That’s usually what is assumed in the CadTel community. But instead, it’s an issue with selectivity, which is when electrons within the cell go the wrong way and cancel each other.”

The group has published an explanation of the method and its use for a full analysis of CdTe devices in Nature Energy. With a fuller understanding of what limits the voltage, they were also able to suggest doping and other approaches to achieve higher efficiencies. The group also states that its measurement approach could also be applied to other cell materials including silicon and perovskites, and that it is already working on industrial applications. “We’re also focused on getting this technology into the hands of industry,” says Zachary Holman, an associate professor of electrical engineering in the Fulton Schools. “We have already built replicates of this measurement technique for a couple of domestic solar cell and module manufacturers.”

NASA completes new spacecraft solar installation

Ahead of a planned launch in August, NASA this week announced that it has completed the construction of the solar arrays that will power its Psyche spacecraft on a 2.4 billion kilometer mission to study a metal-rich asteroid.

“Seeing the spacecraft fully assembled for the first time is a huge accomplishment; there’s a lot of pride,” said Brian Bone, who leads assembly, test, and launch operations for the mission at NASA’s Jet Propulsion Laboratory in Southern California. “This is the true fun part. You’re feeling it all come together. You feel the energy change and shift.”

After launch, the solar arrays will deploy, and provide all of the power for the spacecraft’s 3.5-year journey to the asteroid, located between Mars and Jupiter. The cross-shaped solar arrays measure 75 meters, and with them fully deployed the spacecraft is roughly the size of a tennis court. Near Earth, the full array’s capacity is around 21kW, but this will be reduced to just 2kW closer to the mission’s destination. “These arrays are designed to work in low-light conditions, far away from the Sun,” explained Peter Lord, Psyche technical director at Maxar Technologies where the panels were designed.

Lightweight, flexible III/V cells for future space applications

While NASA is preparing to launch a foldable solar array into space later this year, research continues into making these cells even more powerful, as well as lighter and flexible – to potentially allow an array to roll up into an even smaller space before deployment.

Working with high efficiency materials used in solar cells for space and satellite applications, scientists led by Germany’s Fraunhofer ISE simulated various cell designs, each based on a flexible triple junction layer approximately 10 microns thick. The cells were divided into three ‘generations’ and tested under “AM0” irradiation, to represent the light spectrum outside of Earth’s atmosphere, before and after being particle irradiation similar to what the cells would be exposed to in space. The cells and testing process are described in full in a paper published in Progress in Photovoltaics.

“The power-to-mass ratios of the presented solar cells of 3.0 W/g [before irradiation, or beginning of life] and 2.6 W/g [after irradiation, or end of life] are already three to four times higher compared with space solar cells on thin germanium substrates and can compete with best published values for thin-film solar cells,” the group says, further noting that its fabrication process is based on a reusable substrate, with potential for further cost reduction.

Ultrathin solar at 9.17% efficiency

Scientists in Spain and the UK worked with silver-bismuth-disulfide (AgBiS₂), to fabricate a device less than 1000 nanometers thick. Their devices achieved 8.85% efficiency certified by an accredited lab in the US, and themselves measured a top efficiency of 9.17%.

While silver is a rare and expensive material to work with, the group noted that other thin-film solar technologies rely on rare materials such as indium or tellurium, and their approach uses no toxic materials and does not require temperatures higher than 100 C, bringing potential for low-cost manufacturing.

The cells are described in full in a paper published in Nature Photonics. Key to fabricating a device so thin was a mild annealing process that allowed them to engineer particle distribution on the surface of the device, and optimize its light absorption properties. The group says it will now work on further optimizations to reach higher efficiency. “the devices reported in this study set a record among low-temperature and solution processed, environmentally friendly inorganic solar cells in terms of stability, form factor and performance,” said Gerasimos Konstantatos, professor at the Barcelona Institute of Science and Technology. “We are thrilled with the results and will continue to proceed in this line of study to exploit their intriguing properties in photovoltaics as well as other optoelectronic devices”.

The increasing cost pressures placed on PV module manufacturers in 2021 appear to have done little to dampen the world’s appetite for new solar installations or to slow down the adoption of new technologies that push more solar out of PV modules, and lead solar into new environments.

Trends in PV manufacturing this year have proven that large format solar modules are here to stay. Since 2019, when PV wafer manufacturers began to introduce larger formats to the market, there has been much debate over the ideal size for a cell or module. This year has seen virtually all major PV manufacturers adopt either the 182mm or 210mm formats. While the debate continues over which of these offers the biggest advantage, it is now unlikely that we will see a shift back to anything smaller in mainstream production.

The first installations featuring modules based on either of the new cell formats have been completed, test installations are underway – and the backers of both formats claim an energy yield advantage in the field. Since it requires fewer changes and therefore lower risk in system design, the 182mm format looks to have the largest share for now. Standards are emerging, which should make things easier on the system and component design side. And analysts expect to see the 210mm format become more widely accepted further into the current decade.

Aside from the format switch, n-type technologies have been the other big news on the PV manufacturing side. Tunnel oxide passivated contact (TOPCon) and heterojunction (HJT) have waited in the wings for the past few years, and will still only represent a small chunk of the market in 2021. Major commitments from the biggest PV cell and module manufacturers, however, mean that major market growth for n-type is all but assured in the next few years. And initially at least, TOPCon looks to be the more cost effective of the two main n-type technologies, particularly for those manufacturers already operating large PERC manufacturing lines – which can be adapted to TOPCon, while heterojunction will require an all-new cell production line and a considerably higher investment cost.

Installations of ground and rooftop-mounted PV modules will still be the norm for solar; however, the past year has also seen big steps in the technology carving out new niches for itself. Promising and practical developments in agrivoltaics, building-integrated PV, floating PV and many more all point to the promise of integrating solar into our existing environments, and the direction the future could take.

Reaching consensus on what building-integrated photovoltaics (BIPV) is and what makes it different from conventional rooftop PV is one of the challenges that the emerging BIPV industry has to deal with if it wants to move from niche to mainstream.

With this in mind, a group of experts from the International Energy Agency’s Photovoltaic Power Systems Programme (IEA PVPS) put together a report that seeks to bring together piecemeal developments from different regions into a clear set of standards, and clearly defined functions for different products, in terms of their roles as both construction materials and energy generators.

The report is titled Categorization of BIPV applications; and is available on the IEA PVPS website. “By taking into account the main technical subsystems of the multifunctional building skin, the main features in terms of function, performance, morphological, structural and energy-related aspects are organized into five levels from application categories to materials,” state the report’s authors.

The five categories defined in the report stem from those outlined in the IEC standard 63092-1, Photovoltaics in buildings – Part 2: Requirements for building-integrated photovoltaic systems. The IEC’s categories define different types of BIPV system, based on area of integration and accessibility from the inside of the building. IEA PVPS further breaks these down into ‘system’ – representing the entire construction unit, ‘module’ for the active elements in energy and construction, ‘component’ for the parts making up these elements, and ‘material’ for the basic material.

BIPV systems

At system level, the report notes three main types of BIPV system, classified as roof, façade and external integrated devices. They further break each of these down into subsections – ‘roof’ for example is split into discontinuous roofing, continuous roofing and atrium/skylight. The report’s module level category is then divided into three, based on the transparency of the element.

By clearly defining the different system elements in this way, the report hopes to bring together the interests of both PV system designers and architects – one of the key challenges to the development of BIPV. “We aspire that this paper will be able to provide a first milestone to encourage an integrated perspective and an interdisciplinary effort at the core of the BIPV field and that it will overcome some current obstacles that are still obstructing effective exchange of innovation and cooperation among all the stakeholders,” stated the authors.

From pv magazine Global

Though scientists have been able to rapidly reach high solar cell efficiencies using perovskite materials, the specific mechanisms allowing for these is not fully understood, and research carried out to date shows that what is going on inside the material is quite to different to crystalline silicon and other common PV cell materials.

Since perovskite films are typically made up of more individual elements, they end up with a disordered structure and a range of different defects. Different elements of this structure have been shown to both help and hinder efficiency and stability in the solar cell, and understanding why this is could allow scientists to tailor materials to have more of the “good” and less of the “bad”

Multimodal microscopy

This was the aim of scientists led by the University of Cambridge in the UK, who used a range of different imaging techniques to gain a full picture of the perovskite at the nano-scale. “What we see is that we have two forms of disorder happening in parallel,” explains PhD student Kyle Frohna, “the electronic disorder associated with the defects that reduce performance, and then the spatial chemical disorder that seems to improve it.”

Using different techniques that focused individually on the chemical, structural and optoelectronic properties of the perovskite, including a trip to the UK’s diamond light source synchrotron facility, they were able to paint a fuller picture of the material’s behavior. “The idea is we do something called multimodal microscopy, which is a very fancy way of saying that we look at the same area of the sample with multiple different microscopes and basically try to correlate properties that we pull out of one with the properties we pull out of another one,” continued Frohna. “These experiments are time-consuming and resource-intensive, but the rewards you get in terms of the information you can pull out are excellent.”

Their findings are available in the paper Nanoscale chemical heterogeneity dominates the optoelectronic response of alloyed perovskite solar cells, published in Nature Nanotechnology. The results show that gradients in the structure push the charge into areas of the cell with fewer electronic disorders, and away from ‘traps’ that would reduce performance. “What we’ve found is that the chemical disorder – the ‘good’ disorder in this case – mitigates the ‘bad’ disorder from the defects by funneling the charge carriers away from these traps that they might otherwise get caught in,” said Frohna.

With this understanding, the group will be able to start working on ways to further mitigate the effects of one without also losing the positive effects. “Through these visualizations, we now much better understand the nanoscale landscape in these fascinating semiconductors – the good, the bad and the ugly,” said Cambridge University Assistant Professor in Energy Sam Stranks. “These results explain how the empirical optimization of these materials by the field has driven these mixed composition perovskites to such high performances. But it has also revealed blueprints for design of new semiconductors that may have similar attributes – where disorder can be exploited to tailor performance.”

From pv magazine Global

Shingled modules – where silicon solar cells are cut into five or six strips and interconnected using an electrically conductive adhesive – have been around for a while, and though never a mainstream solution they have kept the industry’s attention thanks to potential for flexibility in the size and shape of modules, better aesthetic appearance and improved tolerance to shading.

Recent interest in building integrated and other applications for PV beyond standard rooftop or ground-mounted modules, as well as concerns over the use of lead and improvements in electrically conductive adhesives, have led to renewed interest in the approach lately.

In October, Germany’s Fraunhofer Insititute for Solar Energy Systems (ISE) introduced a new layout for shingled cells, developed in collaboration with interconnection equipment supplier M10, which it calls Matrix Shingle Technology. The approach sees cell strips laid out in staggered rows, similar to how bricks are placed in a wall. Fraunhofer ISE claims that this leads to higher module efficiencies and even better shading tolerance, and is now setting about evaluating the technology’s performance in various installation scenarios.

The institute’s latest work, published in Progress in Photovoltaics, demonstrates that Matrix shingled modules offer a significant advantage in certain shading conditions. The institute conducted lab experiments for various shading scenarios by partially covering modules with black sheeting and then testing them in a solar simulator.

Where shade moves diagonally across a module, and in conditions with random shading, the Matrix modules were shown to perform significantly better. Under diagonal shading, the group recorded up to 73.8% power increase, and under random shading as much as 96.5% more power, compared to a state-of-the-art shingled module using the standard stringing approach.

Current extraction

The group explained that its approach allows more electric current to flow out of the module, without being blocked by shaded areas. “This is caused by currents bypassing the shaded area via the busbar metallization crosswise to the normal current flow. “Besides higher power outputs, this leads to significantly less MPPs where reverse biasing of parts of the module increases the risk of hotspot occurrence.”

While shingled modules are already known to be less susceptible to hotspots thanks to better heat dissipation through the touching cells, the group also found a 40% reduction in the chance of parts of the module being bypassed, leading to an even lower chance of hotspots forming.

The ISE scientists further note that they expect the increased current extraction to improve energy yields for modules in power plant applications that would not have to deal with shading, although they would have to do further work to demonstrate this.

Fraunhofer ISE previously stated that it has a prototype production line for Matrix shingled cells up and running in Freiburg, and now adds that it sees the technology as particularly interesting for building or vehicle integrated PV, and other applications where frequent shading would be inevitable. “Huge potentials for solar power generation meet a huge variety of irregular shading conditions, making shading tolerance a very important aspect,” they conclude. “Above this, matrix modules fulfill other requirements like a highly aesthetic appearance without losing power due to, for example, coloring or printing patterns on the front sheet.”

From pv magazine Global

Module manufacturer Trina Solar said the China Photovoltaic Industry Association (CPIA) is set to announce a set of standard dimensions for large format modules relying on the 210mm wafer launched by Zhonghuan Semiconductor in 2019.

The standard, according to Trina, will be set for different cell layouts as in the table below. Having a standard set of dimensions should make thing simpler, and therefore cheaper, for project developers and component suppliers. All of them have to deal with uncertainty over module sizes and electrical characteristics since the switch to larger wafer formats began to play out.

Toward standardization

The process began in May, when the CPIA brought together industry experts and representatives from across the supply chain to agree on a set of standards for products incorporating the 210mm wafer. Cell and module manufacturers including Trina Solar, Risen Energy, Canadian Solar, and Tongwei – all of which have opted to work with the 210mm wafer rather than the smaller 182mm product being promoted by Longi and others – took part in the CPIA event. They agreed to standardize various technical details of the modules including module dimensions, size and positioning of mounting system attachment holes, and cell spacing, among other details.

Modules will also be designed to meet the latest international standards including IEC 61730, published by the Switzerland-based International Electrotechnical Commission.

“This means 210mm module manufacturers, end users and system solution providers have achieved uniformity in technical issues,” said Trina Solar in a statement.

Trina said it expects the move for standardization to directly result in cost reductions for balance of systems components, and a more efficient supply chain. It said it also expects the manufacturing industry to be able to innovate and bring new processes to scale more quickly, and to bring down manufacturing costs.

From pv magazine Global

Reliance New Energy Solar (RNES) is acquiring Norway-based module manufacturer REC Group from China National Bluestar Group for $771 million and will move forward with plans to develop a 1 GW module facility in the U.S.

RNES is an arm of Indian multinational company Reliance Industries Ltd. Earlier this year, it announced plans to invest close to $10 billion to establish a “fully integrated, end-to-end renewable energy ecosystem.” The company also announced it acquired a 40% stake in engineering, procurement, and construction supplier Sterling and Wilson.

Expansion plans

RNES plans to integrate REC’s production technology in its plans for a vertically integrated, silicon-to-module manufacturing site in Jamnagar, India. REC Group additionally stated that its new owner’s financial strength will help it to realize plans to expand its current base of around 2 GW PV cell and module production capacity located in Singapore to 5 GW over the next two to three years, add  new 2 GW cells and module facility in France, as well as the planned 1 GW module facility in the U.S.

Currently, REC has three manufacturing facilities – two in Norway for making solar-grade polysilicon and one in Singapore for producing PV cells and modules, and a global workforce of over 1,300.

Reliance Industries is led by Mukesh Ambani, currently ranked by Bloomberg as the 11^th richest person in the world. The group reported net profits of $7.4 billion for the year ending March 31, primarily from activities in the fossil fuel segment. In June, Ambani announced plans to invest up to $10 billion in a new venture across the renewable energy sector, including plans to span the entire solar supply chain, as well as make investments in energy storage and hydrogen.

From pv magazine Global

Following multiple high-profile cases of PV installations damaged by strong winds, hail, and other extreme weather conditions, ensuring the ability to withstand everything the climate at a site will throw at a PV project in its 20-year-plus lifetime is high on the list of priorities for project stakeholders.

And the solar industry is rapidly evolving here. Testing standards are emerging to better simulate the effects of extreme weather, and assessments required by insurance providers and other project stakeholders are becoming more sophisticated. But there is still plenty that we don’t know about climate conditions and their potential effects on solar generation.

A research project led by the US Department of Energy’s Sandia National Laboratories aims to fill this gap in knowledge by collecting and analyzing field data from operating PV plants, and referencing this with weather data to observe the impact of various weather events. Their latest paper, Evaluation of extreme weather impacts on utility-scale photovoltaic plant performance in the United States, has been published in Applied Energy.

The group analyzed data from more than 800 solar installations located in 24 U.S. states. They used various machine learning methods, details of which are publicly available for other research, to draw conclusions about the most damaging weather conditions.

Snow and hurricanes

Analysis of words used in maintenance found that “hurricane” was the most frequently mentioned weather event, followed by snow, storm, lightning and wind. “Some hurricanes damage racking — the structure that holds up the panels — due to the high winds,” said Sandia researcher Nicole Jackson. “The other major issue we’ve seen from the maintenance records and talking with our industry partners is flooding blocking access to the site, which delays the process of turning the plant back on.”

Deeper analysis that also incorporated weather data from project sites found that snowstorms have the highest impact on PV production, a difference in output of 54.5% between “event” and “non-event” days. This also found that older solar projects are more vulnerable to extreme weather, potentially due to already being weakened by wear and tear.

Expansion plans

While it offers valuable insight into PV in extreme weather, the group notes that events causing major damage – such as hailstorms – may not be listed in maintenance records, as they would go straight to an insurance claim to document the damage.

The group now plans to extend the scope of its study to include wildfires and prolonged extreme heat, and also to look at impacts on the entire electricity grid, rather than PV installations alone. “This analysis improves our understanding of compound, extreme weather event impacts on photovoltaic systems,” Jackson and co-author Thushara Gunda conclude. “These insights can inform planning activities, especially as renewable energy continues to expand into new geographic and climatic regions around the world.”

From pv magazine Global

Although lithium-ion batteries are already powering various devices that we rely on every day and their presence in vehicles and on electricity grids is rapidly increasing, the technology still has a few shortfalls when it comes to performance and longevity.

Much of the research that’s underway into improving today’s battery technologies is focused on working with new materials, also keeping in supply chain and environmental concerns related to several commonly investigated materials. But whatever material is used, sophisticated new techniques allowing scientists to observe mechanisms at work within the battery in minute detail will be essential to understanding where the issues that hold back performance are occurring, and how to get around them.

Two separate studies have used such techniques to examine the role of oxygen in lithium-ion battery performance.

It was already known that as the battery charges and discharges, tiny amounts of oxygen are released. But the tiny scale of this process makes it difficult to observe, and the wider effects of oxygen loss are not well understood.

“The total amount of oxygen leakage, over 500 cycles of battery charging and discharging, is 6%,” said Peter Csernica, a scientist at Stanford University who worked on one of the studies. “That’s not such a small number, but if you try to measure the amount of oxygen that comes out during each cycle, it’s about one one-hundredth of a percent.”

In the study led by Stanford University, the group sliced open battery electrodes after cycling and scanned samples using an x-ray microscope; and combined this with computational imaging to observe the structure at the nanoscale. They also shot x-rays through whole electrodes, to confirm that their observations at the nanoscale could be applied to the full component. Results of this analysis have been published in Nature Energy. The group found that oxygen is initially released in a “burst” from the surface, and then a slower “trickle” from deeper inside the cathode.

And, they found that the release of oxygen fundamentally alters the structure of the cathode. When oxygen leaves, surrounding manganese, nickel and cobalt atoms migrate as all of the atoms dance out of their ideal positions. “This rearrangement of metal ions, along with chemical changes caused by the missing oxygen, degrades the voltage and efficiency of the battery over time,” said Stanford associate professor William Chueh. “People have known aspects of this phenomenon for a long time, but the mechanism was unclear.”

Balanced charge

In a separate study, published in Advanced Energy Materials, scientists led by Japan’s Tohoku University found that, in a cathode based on equal amounts of nickel, cobalt, and manganese, the oxygen release facilitates several unwanted reactions that deteriorate the battery structure. They also found that the presence of highly valent nickel in the cathode led to higher levels of oxygen release, and that the process overall reduces the battery’s ability to hold a balanced charge. (Valence is a measure of an element’s capacity to combine with other atoms).

The findings are expected to led to the further development of high energy-density and robust next-generation batteries composed of transition metal oxides, said Tohoku University researcher Takashi Nakamura.

By highlighting the role played by oxygen in battery degradation and confirming that it may be a more important piece of the puzzle than previously thought, both studies may provide the basis for future work that aims to limit the loss of oxygen during cycling and the damaging effects this has on a battery.

From pv magazine Global

Battery materials startup Group 14 Technologies brought its first commercial-scale factory online in the northwest United States. The factory can produce up to 120 tons per year of the company’s lithium silicon-carbon material SCC55, designed as a replacement for graphite in lithium-ion batteries.

Since it has around 10 times the energy density of graphite, silicon has attracted plenty of attention from researchers as a potential anode material for lithium-ion batteries. Challenges with the material’s tendency to expand when used in battery, however, have largely held back commercial applications until now.

Group 14 said that by focusing on large-scale solutions from the start it has been able to design a material that can both be produced at large-scale and serve as a “drop in” solution for battery manufacturers already working with graphite.

“We leveraged our team’s deep commercial manufacturing experience to prioritize process development and designing for cost from the beginning,” said CTO Rick Costantino. “The process to manufacture SCC55 was designed from the start to be scaled quickly and efficiently, an approach that has kept us on track to bring our technology online to help power consumer electronics, electric vehicles and more.”

The material consists of a carbon “scaffold,” inside which is a 3-5 nanometer particle of amorphous silicon. Void space inside the scaffold gives the silicon some room to expand, while the carbon surface creates a stable interface with the electrolyte.

Batteries using only SCC55 as the anode have shown stability over more than 500 cycles. It can also be combined with graphite in various ratios for stability over 1,000-2,000 cycles, with customers able to find the optimal balance.

“We have a lot of customers looking at the blending approach, and others also working only with our material to get a 50% plus boost to their battery capacity,” Group 14 CEO Rick Luebbe told pv magazine.

Group 14 did not share information on the cost of its material, although it said it will be competitive with graphite when the improved performance is taken into account.

From pv magazine Global

Quantum dots, crystal structures measuring just a few nanometers, are widely investigated for their potential to boost solar cell efficiencies by acting as a “light sensitizer” capable of absorbing and transferring light to another molecule. The process is known as “light fusion” and it enables an existing solar cell to absorb parts of the light spectrum with energy lower than its bandgap.

Most of the achievements made with quantum dots to date have been in conjunction with perovskite or organic PV semiconductors. Researchers have struggled to tune quantum dots to absorb the right wavelengths of light–and infra-red light in particular–to be compatible with silicon solar cells.

New research from Australia’s Centre for Excellence in Exciton Science, reports on an algorithm that can calculate the ideal characteristics for a quantum dot to maximize cell efficiency. Researchers used the algorithm to calculate that lead-sulfide quantum dots could set a new quantum dot cell efficiency record and ensure compatibility with silicon.

Details of the work are found in the paper Optimal quantum dot size for photovoltaics with fusion, published in Nanoscale.

More than size

The researchers found that size is a vital factor in the quantum dot’s performance, and that bigger does not always mean better.

“This whole thing requires understanding of the sun, the atmosphere, the solar cell and the quantum dot,” said Monash University’s Laszlo Frazer who worked on the paper. He compares the design of optimal quantum dots for particular light and solar cell conditions to the tuning of a musical instrument to a certain pitch.

Having worked to optimize the quantum dot’s ability to capture light more effectively, the next step for the researchers will be to look at the process where the dot transfers this light energy to an emitter.

“This work tells us a lot about the capturing of light,” Laszlo said. “Releasing it again is something that needs a lot of improvement. There’s definitely a need for multidisciplinary contributions here.”

The group also hopes to start building and testing prototype solar cells complete with quantum dot technology in order to better understand the performance and application of their theory.

From pv magazine-global

IHS Markit said that it expects 158 GW of new PV to be installed worldwide next year. That would represent a 34% increase over its expected 2020 figure, and the analysts expect a “wild ride” for the PV industry in 2021.

The firm expects 2020 installations to come in at around 118 GW, a 5% decline compared with 2019. While IHS Markit reduced its forecast earlier in the year based on the expectation of disruption caused by the Covid-19 pandemic, it said that is not the primary cause of the drop in installation figures.

“As many PV markets started coming back mid-year after local lockdowns, module price hikes startled developers,” IHS Markit analyst Josefin Berg told pv magazine. “Developers and EPCs without hard deadlines in the fourth quarter, that had not secured modules and/or were unwilling to pay a premium, had to delay procurement and push project completions into 2021.”

This delay to project completions, coupled with an increased appetite for renewables around the world, is cited as the main driver for the expected increase in installations next year. Analysis from IHS Markit finds that polysilicon prices rose 60% between June and September, followed by price hikes in glass and other materials that led module manufacturers to renegotiate contracts and raise their prices.

The firm expects prices to remain high in the first half of next year, before a projected easing on supply chain conditions takes effect and allows them to fall from the middle of the year. “Once prices start to come down, buyers that have been able to wait will rush to get modules,” says Berg. “All we can say is, 2021 will be quite a ride.”

Global spread

China and the United States are still expected to dominate, with the two representing more than half of global installations. But beyond that, a wider range of countries are expected to contribute bigger numbers. “The other eight markets among the 10 largest will add up to just a quarter of the global demand, in comparison to 40% in 2019,” said Berg. He said that a parallel “consolidation and fragmentation” is at work with China and the United States consolidating their positions even as a growing number of smaller markets make up the remaining demand.

Among the top 10 regions, India is expected to retake its position as the third-largest PV market – though it could be hampered if high prices persist into the second half. Australia should overtake Japan for fourth place, and Spain is forecast to remain ahead of Germany as Europe’s largest PV market. Meanwhile, the analysts note that Colombia, Peru, Portugal, Greece, Ireland, Oman, Saudi Arabia, Zambia, Thailand, Philippines and Malaysia all should be worthy of attention next year.

“Anticipated module price declines in the second half of 2021 will create a procurement rush, but the exact supply and demand dynamics of the year are yet to be experienced,” said Berg. “But we know that the PV industry can still surprise us all.”

*This article was edited from the original for the pv magazine U.S. site by David Wagman.

From pv magazine 12/2020

It was around the beginning of 2018 that the idea of making PV wafers larger as a cost optimization began to gain ground. Up to this point, the “M2” wafer measuring 156.75 mm had been widely accepted as the industry standard, representing the vast majority of products on the market.

As is so often the case in solar, making wafers larger as a cost optimization strategy was not an entirely new idea. This time around though, it has quickly gained ground among all of the leading manufacturers, turning the market on its head. Figures from PV InfoLink forecast a complete reversal in demand for the M2 wafer, from a 97% market share in 2018, collapsing to just 3% by the end of 2021.

The size, or sizes, that will fill this gap have been the subject of much debate over the past year. The change began incrementally, with manufacturers initially moving up to 158.75 mm or taking another look at the 161.7 mm M4 wafer that had previously been used in some niche products for the rooftop market.

In June 2019, monocrystalline manufacturer Longi Solar looked to answer the question with its 166 mm M6 wafer, promising to boost energy yields and bring down wafer costs by around 4%. Then in August 2019, Zhonghuan Semiconductor introduced its 210 mm ‘G12’ wafer, with which it promised module power ratings up to 600 W from a 60-cell PERC module. For Zhonghuan, it may have been a logical progression to bring PV wafer dimensions in line with those it produces for the semiconductor industry. For the solar industry though, such a fundamental change at the top end of the supply chain created new uncertainty over the ideal dimension – and this uncertainty looks set to remain with the market for at least the next couple of years.

It quickly became apparent that while Zhonghuan’s 210 mm wafer could offer advantages in terms of power output, jumping straight from M2 to G12 dimensions came with its own set of challenges, in some cases requiring costly upgrades or outright replacement of factory equipment. And further downstream, the larger formats and quite different electrical characteristics of modules made from these wafers require redesigns to balance-of-system components and system layouts, and for investors represents essentially a new and unproven technology.

This led Longi, in June of this year, to launch the 182 mm M10 wafer. The company’s calculations show that this is the optimal size to bring down levelized cost of electricity, taking into account shipping, handling, and all other costs.

“With M10 wafer size standardization, all players through the value chain now have a common platform to develop and optimize their individual equipment and process to realize optimum performance and lower cost,” said Hongbin Fang, director of product marketing at Longi, earlier this year. “This standardization will help to deliver better value for our customers.”

Longi has estimated that its latest module based on the 182 mm wafer will save one or two cents per watt at the system level.

Camps forming

With the launch of the M10 wafer, the industry quickly divided itself into two broad camps, each backing one size over the other. And this story continues to play out – in mid-November, at a conference event held in Shanghai, Longi, JinkoSolar and JA Solar jointly stated their expectation that they expect to see 54 GW of module production capacity based on the M10 wafer online by the end of 2021. In the same week, Trina Solar announced a joint venture with cell manufacturer Tongwei that will focus on the 210 mm products.

“Trina Solar and Tongwei both have outstanding advantages in their roles for the industrial chain. They have reached a consensus on 210 series modules, and this cooperation will further strengthen our strategic partnership,” stated Wu Qun, secretary of Trina Solar’s board of directors, announcing the joint venture. “Through the joint efforts of all industry partners, the 210-product industry chain has matured, and is now more conducive for deeper integration.” Trina also said it expects to have “no less than 50 GW” of production capacity at the end of next year, the bulk of which will be devoted to 210mm modules.

“M10 wafers are the best choice to harvest the cost savings in manufacturing and deployment whilst avoiding the challenges of even larger substrates,” said Jürgen Steinberger, global product manager for Q Cells. “The module width is more practical, half-cut cells are still a good choice with only tiny disadvantages in cell-to-module compared to half-cut cells based on smaller wafers.”

With major investments already committed from both camps, it looks as though both of these new wafer sizes will gain market share. Over the next few years analysts are forecasting a wafer market split between the two, with M10 initially seeing a slight advantage and G12 beginning to catch up after 2023. This has led some to theorize that the M10 wafer could be seen as a transition product, smoothing over the changeover to the larger G12 format. Longi, however, is convinced that its product offers better electrical performance, as well as simpler handling and installation, and will be adopted as a new industry standard.

“The 182 mm modules effectively support the existing industrial specifications and electrical systems,” stated Longi Solar Senior Product Manager Li Shaotang at a conference promoting the 182 mm wafer in Shanghai in November. “Additionally, in terms of LCOE, 182 mm modules are superior to 210 mm due to lower system cost, better generation capacity, and reliability.”

As projects begin to be built with both module types, it should become clearer whether one has an overall advantage, or whether the two are each better suited to certain installation scenarios. In the meantime, however, other industry players are busy preparing for a market with significant variation in terms of module size, and plenty of confusion over the best path to take.

Overwhelming and confusing?

“Within the two cell sizes, we see about five new module designs, and the industry has never really dealt with that much choice,” said Greg Beardsworth, director of product management at Nextracker. “There’s definitely the risk of overwhelming and confusing the market.”

Part of Nextracker’s response has been to try to work closely with module suppliers to ensure compatibility with its trackers, and setting appropriate load testing requirements and other parameters. Working together in this way, said Beardsworth, is the most economic approach, ensuring, for example, that cost savings in module manufacturing don’t just translate into additional spending elsewhere.

And the company has so far found little to suggest that there are any major, fundamental design changes needed to build mounting systems and other components for use with these larger modules. “We have expanded our wind and structural analysis to cover this full range of panel sizes,” explained Beardsworth. “But we didn’t find anything like ‘once you go to this size, everything changes.’ So we can scale without having to start afresh.”

With several different formats available, module size could become just another input for project calculations. And understanding how specific site conditions could affect this decision will be key to preventing confusion among project developers. “If you have five different scenarios for the design of a 100 MW project, everybody’s head is going to explode,” said Beardsworth. “Selecting the optimal module format before detailed site design begins will help developers and EPC’s minimize churn and realize the potential benefits of higher power modules.”

Next year will see large formats begin to be installed in projects, first in China, then rolling out to other tariff-free locations. And the picture painted by performance data from these projects over their first few years in operation will help to make the advantages and disadvantages of either approach clearer. Until then, at least, it seems project developers will be spoilt for choice in terms of module size – a situation that’s sure to bring its own set of ups and downs.

From pv magazine 11/2020

For Tier-1 module manufacturers, the switch to larger formats has clear benefits in terms of cost structure – with the adaptation of equipment, they can produce a 600 W module in the same time it takes to produce a 400 W one, effectively increasing their production capacity. The move may also serve to increase market share, leaving smaller producers who lack the upfront cash to adapt equipment to process larger wafers behind, as they are unable to match the power ratings.

While these huge jumps in power rating look impressive on paper, it is often said that there is little innovation behind them – only an increase in size. There is some truth to this – without the increase in size, we’d be looking at increases in the tens of watts range, rather than hundreds. But it was the earlier innovation of half-cut cells that really made this possible. Plenty of hard work has also gone into new interconnection strategies, as well as efforts to reduce the gap between cells to further increase the active surface area.

For manufacturers that have invested in enormous production capacities for PERC cells and modules, there may be few other options open, as new ways to increase efficiency become harder to find, and new cell technologies begin to get closer to PERC in terms of cost per watt. And since this move to larger formats promises to increase energy yield and lower LCOE at project level, it can be argued that it’s as valuable as any other innovation.

Promises, concerns

The manufacturers of these modules promise that it is not only a cost optimization for them. Throughout this year, launches of new modules incorporating 182 mm or 210 mm cells have been accompanied by plenty of fanfare, and promises that the change will lower costs elsewhere in the system design, and ultimately to lead to lower levelized cost of electricity at project level.

First among these is the claim that more powerful modules will bring down costs for the tracker or racking. With the module in the right orientation, the racking system only needs to be made slightly longer in order to accommodate more modules, and more watts per pile.

Another claim common to the majority of new large-format modules is that the combination of cut cells, multibusbar interconnection and “twin” module designs reduces the voltage of the module, again allowing for system designers to fit more energy capacity in the same amount of space.

“The low open-circuit voltage and temperature coefficient of our Tiger module can increase the number of modules at string level,” explains Roberto Murgioni, Head of Technical Service for Europe at JinkoSolar. “And if the DC side capacity of the project is known, the total number of strings in the project can be reduced, which enables power densities of 214 watts per square meter.” Increasing the number of modules per string should in turn serve to reduce the amount of cabling and combiner boxes required, further bringing down BOS costs.

Launching its new Series 7 modules last month, Canadian Solar presented calculations that the new modules, based on a 210 mm wafer, allow engineers to increase the number of modules per string to more than 30. This pushes the power per string up to 20.2 kW, compared with 12.2 kW from a string of around 26 of an older generation Canadian Solar mono-PERC module.

The launch of these modules has also seen several concerns raised over the jump in size. Some have noted that while increasing the size, manufacturers have not made the front glass any thicker, making the module a bit more flimsy. Trina Solar reports, however, that it solved any issues here by strengthening the metal frame, and other manufacturers report their modules are easily able to stand up to the 5,400-pascal mechanical load test specified in the IEC standards. With lower voltage as well comes higher current, leading some to voice concerns over performance degrading hotspots. In response to this, manufacturers point to half-cell and twin-module designs, as well as the smaller gaps between cells, among their strategies to keep the current from running too high. And with smaller gaps between cells – in some module designs the cells are slightly overlapping – better heat dissipation can also help to reduce the likelihood of hotspots forming.

Some have also expressed concern that the sheer size and weight of these modules will cause problems in shipping and for installers. Manufacturers have reported that by packing modules vertically into shipping crates, and exploring other optimizations, they are able to ship high volumes without issue. And on the installation side, Tomaso Charlemont, global solar procurement leader at project developer RES Group, tells pv magazine that the largest of the new PV modules typically weighs in around the 35 kg mark. This is similar to First Solar’s Series 6 modules, which have not caused any major issues for installers since being introduced a couple of years ago.

For engineers and project developers, it’s early days working with these modules. And while many manufacturer claims appear valid, there are more factors at work that will only become clear once we see modules being used in actual projects. Tino Weiss, head of purchasing at BayWa r.e. Solar Projects, says he can see the reduction in cabling costs playing out in the field. Cost reductions on the tracker/racking system are likely as well, but there will be a limit to how much longer/wider you can go without increasing the cost of the structure, he says. And he warns that the increased current might result in a need for higher rated fuses, increasing the price for combiner boxes. “The real question is how much of these BOS savings are eaten up by the module price,” says Weiss. “Ultimately whether you can count on these BOS savings will always be dependent on your system design.”

Large, and then larger

The appearance of larger wafers, and then larger module formats, has seen the industry quickly divide itself into two main camps, promoting either the 182 mm or the 210 mm wafer. Manufacturers are certainly ensuring that new cell and module lines are able to process sizes up to and even beyond 210 mm, but this is viewed by some as hedging their bets against the possibility of having to do a second round of costly upgrades within a couple of years. In terms of actual production plans, the industry appears split between those who view the bigger jump in power output enabled by the 210 mm wafer as a goal worth pursuing immediately, and those who value the more incremental jump to 182 mm as a less risky and disruptive route to higher energy yields and lower LCOE.

In a recent pv magazine Webinar, Trina Solar presented a case study based on 100 MW fixed tilt, 1500 V system, comparing its Vertex module, utilizing 210 mm cells, to a competitor’s module utilizing 182 mm. This showed that Trina’s module allowed up to 36 modules in a string, compared to 27 for the rival, and a 35.8% increase in power per string. And this further cascades down to a reduction of 62 piles, 3.5 kg of steel and 1 kilometer of cabling per megawatt installed.

But bigger changes mean more uncertainty and higher risks. The largest and most powerful of these new solar modules is already requiring redesigns at tracker and inverter suppliers, as well as overall system layouts, for project developers and investors to reap their benefits. While the potential rewards are such that some will surely take the risk, it will take a few years at least for a track record to develop and for such changes to become accepted and understood by more investors.

Meanwhile, modules based on 182 mm wafers still reach power outputs well in excess of 500 W, and in comparison, require only minor optimizations to existing components and plant layouts. “The 182 mm module is the most mature and bankable product,” argues JinkoSolar’s Murgioni. “And it offers guaranteed yield and production capacity for the existing cell and module manufacturing process in the industry.”

In the short term, at least, those working on full systems favor the less disruptive route. Baywa r.e. says that modules deploying 182 mm cells in a half-cut layout appear to be the optimal solution.

Tomaso Charlemont of RES Group also says that without a track record, 210 mm technology would be too disruptive for the company to look at today, although he will not rule it out in the future. “When they tell you that you can make strings of 30-plus modules, the entire design of the project is impacted, e.g., trackers need adjustment and inverters need different fused protection.” he explains. “It involves a completely different layout. That’s not going to happen overnight.”

Charlemont goes on to explain, however, that working with 182 mm modules, RES has already been able to take an existing project originally planned with M6 (166 mm) modules, and recalculate for the larger 182 mm format. And the new calculations have shown capex savings of around $0.01/W.

“You still remain within limits that you can evaluate quickly with the manufacturers of inverters and mounting structures using current solutions. We can take the 182 mm module to an investor and tell them ‘here is a validated number, approved by an independent engineer.’ It is a different module but it is a straightforward implementation,” Charlemont explains. “You can understand why manufacturers are so confident, because they know what we have done is work that is both easy and bankable.”

The move up to 210 mm wafers and modules rated at 600 W and higher, however, is a step into new territory, and some track record of performance will be needed for investors to view systems designed with these modules as bankable. But the industry has already taken notice, and some larger players will likely be willing to take the risk on a new iteration of existing and well understood technologies such as this. Tracker and inverter suppliers as well are working quickly to optimize their offerings to fit the largest of modules, and manufacturers are already reporting sales of both 182mm and 210mm modules, and seem very much convinced that the move will be a success.

For now, whether 182 mm or 210 mm, it appears the larger wafer and module formats are here to stay. Analysts including Wood Mackenzie (see chart on p.34) and PV InfoLink forecast these two sizes to represent around 90% of the market by 2025, with 210mm beginning to gain an advantage in the later years – reflecting the time needed for the new move to establish itself and achieve bankability.

From pv magazine global

Scientists led by the Dalian Institute of Chemical Physics (DICP) in China have begun a large-scale project demonstrating PV-powered production of hydrogen, which is then used to convert carbon dioxide into methanol. The demonstration project was certified by China’s Petroleum and Chemical Industry Federation and is expected to run for 10 months, with plans for expansion further down the line.

The “Liquid Solar Fuel Production demonstration Project” combines a 10 MW PV array with an electrolyzer and equipment for CO₂ hydrogenation. The electrolyzers utilize an undisclosed catalyst developed at DICP, which it describes as a “low-cost and long-lifetime electrocatalyst for alkaline water electrolysis.” According to the institute, the facility currently has capacity to produce 1,000 cubic meters of hydrogen per hour and requires less than 4.3 kWh of electricity per cubic meter.

Hydrogen is then used to convert CO₂ into methanol, driven by another catalyst, this time a mixed metal oxide. DICP reports that the demonstration facility currently has capacity to produce 1,000 tons of methanol per year, reaching 99.5% purity.

Expansion plans

“Our overall goal is to eliminate CO₂ emissions by utilizing CO₂ as a carbon source alongside renewable energy,” DICP Professor Can Li told pv magazine. “The next plan is to expand the scale from 1,000 ton-methanol/year to 10,000 ton-methanol per year, or even to 100,000 ton-methanol per year.”

Methanol produced at the plant can be supplied to the chemical industry, or stored and used to produce hydrogen again. And despite the major expansion plans, Li points out that the project is ultimately a technology demonstration, and does not come with a detailed business model at this stage.

Large-scale, PV powered hydrogen production is gaining ground commercially, with projects announced recently in the Middle East and Australia, but still struggles with high costs and lack of infrastructure to make good use of the hydrogen. Using the hydrogen in CO₂ conversion to methanol meanwhile, has shown promise but remains largely in the research stage.

From pv magazine global

In the field, PV modules have been observed to degrade and lose performance in a variety of ways. And the fast-moving nature of the technology often means new problems are being discovered as fast as the old ones are being solved.

Detailed standards exist to set a minimum standard for industry entry, however, it is widely acknowledged fall short in some areas, particularly when it comes to spotting new or little-understood degradation mechanisms. “Standards are not intended to serve as a guarantee of quality or reliability,” state scientists from the U.S. Department of Energy’s National Renewable Energy Laboratory (NREL) in a newly published paper. “…the industry has been forced to design standards around known failures, as opposed to developing a more comprehensive testing regime that could detect unexpected failure modes more frequently.”

The group led by NREL set out to create such a comprehensive testing regime, focused on mimicking the overall natural environment modules are installed in, rather than pushing the limits of one particular failure mode. “Of great value to the industry would be a test that would provide more comprehensive identification of failure modes in new module designs and materials prior to field deployments,” the group states.

Key to the development of a testing protocol is the ability to simultaneously apply different stress factors to the modules. With this in mind, the group combined a climate chamber with xenon lamp solar simulators, hydraulic actuators for mechanical loading and power sources to apply voltage stress to the modules. The set up is described in the paper Advanced reliability assessments of photovoltaic modules and materials using combined-accelerated stress testing, published in Progress in Photovoltaics.

Backsheet cracking

To demonstrate the effectiveness of its protocol, the group compared it’s combined-accelerated stress testing (C-AST) results with the Module Accelerated Sequential Testing (MAST) protocol developed by DuPont to test the reliability of polymer backsheets, noting that backsheet is a common failure mode not well covered by current testing standards.

C-AST was shown to produce similar results to MAST in terms of backsheet cracking, while also producing reliable results for light induced degradation, cell cracking, soldering failures, corrosion and other issues. And the group is confident that its testing could be adopted as an industry standard in the future. “With the single C-AST protocol, we have the ability to screen for both known and unknown degradation modes, providing the possibility to minimize the many tests in the design qualification standard when used in conjunction with a single test protocol,” they conclude. “Potentially reducing the cost of certification testing and accelerating time to market.”

A study led by the University of Sussex (UoS), in the U.K., has found renewables up to seven times more effective at reducing carbon emissions than nuclear power. The paper concluded nuclear could no longer be considered an effective low carbon energy technology, and suggests that countries aiming to rapidly and cost-effectively reduce their energy emissions should prioritize renewables.

The study, published today in Nature Energy, considers three hypotheses: Firstly, that emissions decline the more a country adopts nuclear; secondly, that emissions decline the more a country adopts renewables; and thirdly, that nuclear and renewables are ‘mutually exclusive’ options that tend to crowd each other out at an energy system level. The hypotheses were tested against 25 years’ worth of electricity-production and emissions data from 123 countries.

The UoS study found little correlation between relative nuclear electricity production and CO₂ emissions per capita but did observe a linkage with the per-capita GDP of the nations studied. Countries with high per-capita GDP saw some emissions reduction with increased use of nuclear power, said the researchers, but regions with lower GDP saw CO₂ emissions rise with the use of nuclear.

Renewables

For renewables, however, the data revealed a decrease in CO₂ emissions associated with the technology “in all timeframes and country samples” and with no significant linkage to per-capita GDP.

National policy commitments tend to favor one or other option, noted the UoS group, meaning a nuclear focus reduced renewables deployment and vice versa.

“This paper exposes the irrationality of arguing for nuclear investment based on a ‘do everything’ argument,” said Andy Stirling, a professor of science and technology policy at UoS. “Our findings show not only that nuclear investments around the world tend, on balance, to be less effective than renewable[s] investments at carbon emissions mitigation, but that tensions between these two strategies can further erode the effectiveness of averting climate disruption.”

The authors of the study acknowledged their report considered only carbon emissions and said future work should also consider factors such as economic cost; integrated resource planning; reliability; life cycle impacts; risk profiles; waste management; and ecological, political and security impacts.

“While our study can be viewed as a starting point for robust research on the topic of nuclear power, renewables and [the policy] lock-in [of one at the expense of the other], it is not meant to be a finishing point,” the authors stated. “It is an anomaly that the strong claims in favor of particular technologies with which this paper began, have for so long remained so under-evidenced. We encourage others also to address this gap in their future research.”

Recommendation

Even without considering other factors, though, the report’s authors said the emissions data alone was strong enough to recommend nations hoping to trim their energy emissions should focus on renewables rather than nuclear.

“The evidence clearly points to nuclear being the least effective of the two broad carbon emissions abatement strategies and, coupled with its tendency not to co-exist well with its renewable alternative, this raises serious doubts about the wisdom of prioritizing investment in nuclear over renewable energy,” said Benjamin K Sovacool, professor of energy policy at UoS. “Countries planning large scale investments in new nuclear power are risking suppression of greater climate benefits from alternative renewable energy investments.”

From the pv magazine global site

With proven ability to increase energy yield, anti-reflective coatings (ARCs) have firmly established themselves in PV manufacturing. The vast majority of module manufacturers now employ an ARC on the frontside glass of their products, and demand is developing for ‘aftermarket’ coatings to be applied on modules already in the field.

Beyond allowing more light through the glass and onto the active cell though, front glass coatings with the right properties can also help to reduce soiling – both increasing performance and reducing maintenance costs.

Coatings combining both properties have been introduced to market in the past couple of years, however challenges remain for producers to keep up with rapidly falling costs elsewhere in the PV module supply chain, and also to engineer coatings that can match the increasing lifetime guarantees manufacturers now need to offer. As the first line of defense between a module’s inner workings and the ambient environment, such coatings must offer excellent durability, including standing up to harsh cleaning solutions, for 30 years or even more in the field.

New solutions

Testing a total of seven different configurations over a one-year period, the group found that porous methyl-silylated silica, prepared using a sintering process at 550 degrees Celsius offered the best overall performance. They also found that the use of an inner dense layer could improve the coating’s long-term performance.

Their work, published in the paper Mechanical properties and field performance of hydrophobic antireflective sol-gel coatings on the cover glass of photovoltaic modules, in the journal Solar Energy Materials and Solar Cells, also finds that with one year of testing modules with an ARC showed 2% increased energy yield compared to identical modules without the coating.

First identified in 2012, light-elevated temperature-induced degradation (LeTID) is known to potentially cause performance losses as high as 10% over a period of years for modules in the field, and has been observed in most p-type silicon PV technologies. This makes it a significant headache for plant owners and module manufacturers alike.

However, the mechanisms behind this degradation are complex, and scientists have thus far not been able to isolate the exact cause. In new research into the effects of LeTID, scientists led by the Chinese Academy of Sciences examined LeTID effects on the surface of a solar cell, and at the interfaces between silicon and the passivation layers.

The group used deep level transient spectroscopy, a specialized method for observing active defects in semiconductor materials, to view degradation behavior of the surface passivation in a range of differently treated multicrystalline silicon samples, including both aluminum oxide and mixed aluminum oxide/silicon nitride passivation layers.

They described their work in “Surface related degradation phenomena in P-type multi-crystalline silicon at elevated temperature and illumination,” which was recently published in Solar Energy.

Bulk to surface

The experiments showed a decrease in carrier lifetime for the samples after light soaking at 80 C and 0.46 kilowatt hours per square centimeter. The number of interface states – defects in the material that can reduce performance – increased after the light soaking. According to the researchers, this suggests that decreased passivation quality caused by the increase in interface states could be a contributing factor in LeTID.

The cause of this increase, however, is more likely in the bulk of the material rather than its surface, and the paper suggests that the increase in interface states might be down to diffusion of impurities in the bulk to the surface during the LeTID mechanism. “It might be concluded that the increase of interface states is one cause of [the] LeTID phenomenon, but the main cause may be the defects in bulk,” the researchers stated.

In spite of this, the group concluded that further work focusing on the surface and interface degradation will be valuable in better understanding LeTID. “The cause of the LeTID phenomenon is extremely complex,” they said. “And more intensive research on surface-related degradation should be carried out.”

From pv magazine 06/2020

Estimating the impact of product piracy in the solar industry is not easy to do. Since the price of a PV module is typically based on its measured output, it may appear that there is no immediate advantage for a ‘pirate’ producer in fraudulently slapping the logo of a more reputable manufacturer onto its own inferior products.

German company Viamon, which provides security services to the PV industry, says that it sees on average one to two cases per year involving counterfeit modules. China-based Quality Assurance provider Sinovoltaics, meanwhile, states that its experience related to counterfeiting is more along the lines of falsified power ratings or quality certifications, and even electroluminescence images being edited to hide cell cracking and other defects.

Several PV module manufacturers, however, have confirmed to pv magazine that they do see fake versions of their products available for purchase in various locations, and that they see solutions to prevent this as a worthwhile investment – even in times where profit margins in module production are stretched thin. “Unfortunately, it is almost impossible to determine an exact number of copycats, but year by year this problem is increasing, and we think that the dark figure is even higher,” explains Waldemar Hartmann, sales director at German module producer AE Solar. “We see it quite frequently by ourselves, and our partners see it around the world.”

What to do with a fake

When counterfeit modules are detected, AE Solar says it works both with the customer who purchased them and with legal advisers to track down the producer and prevent further counterfeiting. But it notes that with the network of intermediaries between production lines and end customers, it can be difficult to establish who makes such modules.

Norway-headquartered manufacturer REC Group also states that it occasionally sees counterfeits of its modules being sold via online platforms. “Although these are only a few small cases per year, we take these seriously,” says Cemil Seber, vice president of product management at REC Group.

Hartmann goes on to explain that fake branded AE Solar modules are frequently found for sale on online e-commerce platforms such as Alibaba. They also have cases where an end customer has contacted them to complain of a product’s poor performance, only to find that what they purchased was not in fact produced or certified by AE Solar at all. But one case in particular, says Hartmann, led the company to take further action. “A huge manufacturer placed an OEM order with us, saying due to high demand they did not have the capacity to produce their client’s full order,” he explains. “Once we finished the order, and started to unpack the stickers for the panels, we saw that it was AE Solar’s old logo – we already had an upgraded new design. So it appeared that we had made copies of our own brand for another factory.”

Multiple solutions

AE Solar is now introducing an NFC chip for all of its modules, which allows the company to track its panels. The chips also allow customers to reliably authenticate products before buying, simply by scanning them with a smartphone. The chips link with an app that can identify the module with a unique web link, while also allowing customers to directly communicate with the AE Solar team. The chips are laminated under the module glass, so they are difficult to remove without severely damaging the modules themselves. Hartmann notes that while the chips and accompanying mobile app took some years and significant investment to manufacture, AE Solar has not increased its prices as a result of integrating them.

REC Group uses an app-based solution to assist its certified solar installers, which also serves to help prevent counterfeiting, relying on module serial numbers rather than a chip. This is likely less secure, however, REC states that the app allows it to immediately identify any fake serial numbers. Installers are encouraged to use the app to register all installations with REC Group modules, and the company offers extended warranty terms to all registered solar installations.

Another approach to combating counterfeits, taking things down to the cell level, can be seen with Korean manufacturer Hanwha Q Cells. The company deploys its patented Tra.Q process, where individual wafers are marked using a laser, and the marks can be read by a scanner. According to the company, such approaches have value beyond protection against counterfeiting. “Tra.Q gives each cell a unique fingerprint, which enables us to completely trace the entire manufacturing process for each individual solar cell – this includes the serial number, the date and location of production and even which material charge was used to make the cell,” says a Q Cells spokesperson. “We can thus better analyze errors and even make improvements as they arise.”

For Viamon, this fits in with a wider industry move toward quality assurance and establishing accountability across the supply chain, including in transit and installation. “Chip inside the shipment is an interesting new topic. That not only means counterfeiting but also controlling shipping routes, on-time deliveries, and the correct content of containers,” says Viamon general manager Oliver Strecke. “Often, the customer is so cost-sensitive that copy-protected chips are not easy to establish in every module. I believe that using random samples of a whole shipment could be a worthy solution.”

Researchers led by the University of Princeton have found that, alongside renewable energy’s well-known carbon emission reduction benefits, solar and wind power also keep more water in the ground than hydroelectric facilities. The result is less pressure on the water supply, freeing up more of the resource for food production.

“Traditionally, the social value of solar and wind energy has mostly been focused on air pollution mitigation and carbon emission reductions,” said Xiaogang He, lead author of the study at Princeton and soon-to-be assistant professor in the Department of Civil and Environmental Engineering at the National University of Singapore. “However, if we look at the problem from a different angle – like the water-food-energy nexus – then our paper identifies some unrecognized and under-appreciated affects that have been overlooked in past studies.”

Recent reports have noted the potential of PV powered desalination to alleviate water shortage but few have highlighted the technology’s potential to contribute to that aim simply by not using water. Most other forms of power generation rely on water or steam to spin turbines.

The pay-off

In their paper, published in Nature Communications, the researchers create a ‘trade-off frontier framework’ – an analytical tool often used in policy development – to quantify the benefits of increased solar and wind generation capacity for groundwater sustainability, and to identify the optimal way to maximize hydroelectric generation and agriculture while minimizing groundwater depletion.

The paper takes California as a case study thanks to its status as an agricultural hub for the United States and as a leader in the deployment of solar and wind generation. The state suffered drought from 2012-217, leading to widespread reliance on unsustainable groundwater stores. While the results focus on California, He says the framework developed by his team could be used by policymakers elsewhere.

The researchers noted, 54% of the world’s hydropower plants compete with agriculture for water use. The two sectors rarely collaborate on water management schemes and have quite different needs – hydropower stores water in reservoirs to maintain a head for power generation while farms need water released for irrigation downstream.

Aquifers threatened

He and his team argue further deployment of solar and wind, as well as integrated management of water resources can, even in drought conditions, reduce the use of groundwater drawn from aquifers that can take years to refill. The authors note the importance of integrated modelling, taking into account the intertwined issues of water, food and energy. The researchers say in California, action to deploy more solar and wind and to strictly regulate the use of groundwater should be taken sooner rather than later.

“Our results also suggest that policymakers need to take the long-term outlook of groundwater depletion into consideration when planning further deployment of solar and wind energy,” said He. “If groundwater aquifers keep getting depleted in the future, then the added value of penetrating solar and wind energy will largely decrease.”

“This proof-of-concept work represents a new paradigm for electrochemical energy storage,” reads a paper published this week in Nature Materials and led by scientists at Massachusetts Institute of Technology (MIT).

The paper’s authors developed a new class of liquid electrolyte which they say could greatly improve the performance of lithium-ion batteries and supercapacitors – used in some cases to improve performance and extend the lifetime of batteries.

The electrolyte is based on a class of materials known as ionic liquids, which MIT described as “essentially, liquid salts”. The scientists added a compound they said was similar to a surfactant that would be used to disperse an oil spill to the liquid, and found it brought about “new and strange properties” in the liquid which could have several applications for energy storage and other industries.

Enhanced performance

The researchers found the material’s energy density exceeded that of many other electrolytes and it remained highly viscous even at high temperatures, contributing to better safety and stability. T. Alan Hatton, professor of chemical engineering at MIT, explained that was thanks to the way the molecules assembled themselves in a highly ordered structure as they came into contact with another material, such as an electrode.

The ordered structure, according to MIT, helped prevent an issue known as overscreening, where a more scattered distribution of ions at the electrode surface, or a thicker ion multilayer, negatively affects energy storage efficiency.

Likely applications for the technology include high-temperature energy storage, with the researchers pointing out their electrolyte performed even better at high temperatures and was safer and less flammable than others used in lithium batteries as well as in supercapacitors. The researchers speculated their electrolyte could increase energy density four or five times, potentially even allowing it to replace batteries in electric vehicles, stationary storage and consumer electronics.

More to come

The team will now work on other compounds that fit into the new class of materials, which they are calling surface active ionic liquids – SAILs.

“The possibilities are almost unlimited,” said MIT postdoc Xianwen Mao, the paper’s lead author. “It might take a few months or years,” he said, “but working on a new class of materials is very exciting to do. There are many possibilities for further optimization.”

Autonomous Energy Grids (AEG) is the name of a multifaceted project that the U.S. National Renewable Energy Laboratory (NREL) has created to envision the electricity grid of the future, where output from many decentralized energy sources is managed simultaneously to ensure a secure and consistent energy supply.

The concept is focused on smart technology and autonomous communication, based on a series of interconnected microgrids, which communicate with each other and make use of algorithms to continually find the best operating condition in response to constantly shifting energy demand, availability and pricing.

“The future grid will be much more distributed too complex to control with today’s techniques and technologies,” said Benjamin Kroposki, director of NREL’s Power Systems Engineering Center. “We need a path to get there—to reach the potential of all these new technologies integrating into the power system.”

Refining the theory

Researchers say the project is currently mostly theoretical, with applications likely more than 10 years away. The project began with a group of scientists looking to develop real time optimization and control methods for individual power systems, and grew into the idea of having these individual power systems, or “cells”, communicate with each other to form a system that would cover the entire grid.

“What’s novel in our solution is that we address a two-part problem,” explained Kroposki. “First, because of the large number of devices, we cannot use central control, but must instead distribute the optimization problem. The other problem is that we have time-varying conditions, therefore the optimization is changing every second and must be solved in real time.”

The researchers are currently simulating AEGs consisting of hundreds of different cells operating in unison, but note that this would need to be dramatically scaled up to represent a unified grid solution – California’s Bay Area alone, for example, already has more than 20 million control points. “Algorithm solve times are needed every one second, explains NREL researcher Jennifer King. “Trying to decide the fate of a million things on a second-by-second basis is where the challenge comes in.”

Real world application

The next challenge is found in applying these algorithms to real-world conditions, where things don’t always run smoothly and delays and damage often need to be accounted for. Arranging the infrastructure and ensuring its security will represent another major challenge.

The researchers have published multiple papers addressing different areas as part of the push for AEGs, and NREL notes that AEG has also seen participation from Siemens and battery company Eaton in its work, and that an energy cooperative in Colorado is currently deploying control techniques based on the group’s work.

“There are many people out there working on tiny aspects of this … we see this as a broad vision,” states Kroposki. “You’ll probably see AEG appear from the bottom up; starting with hospitals, campuses, and communities.”

A team of scientists at the University of Kansas has found combining organic semiconductor zinc phthalocyanine with a single layer of molybdenum disulfide atoms can greatly improve the material’s performance as a solar cell.

Using photoemission spectroscopy equipment the team was able to observe the behavior of electrons in the material. That led to several discoveries about the interface between the two materials which the researchers say could enable them to determine new directions for research into organic solar cells and two-dimensional semiconductors.

“One of the prevailing assumptions is free electrons can be generated from the interface as long as electrons can be transferred from one material to another in a relatively short period of time – less than one-trillionth of a second,” said Wai-Lun Chan, associate professor of physics and astronomy at the University of Kansas. “However, my graduate students and I have found the presence of the ultrafast electron transfer in itself is not sufficient to guarantee the generation of free electrons from the light absorption. That’s because the ‘holes’ can prevent the electrons from moving away from the interface. Whether the electron can be free from this binding force depends on the local energy landscape near the interface.”

Tracking electron journeys

The experiments are described in the paper Effect of the Interfacial Energy Landscape on Photoinduced Charge Generation at the ZnPc/MoS₂ Interface, published in the Journal of the American Chemical Society. The team used a laser pulse lasting 10^-14 (ten quadrillionths) of a second to set electrons into motion and then a second pulse to kick electrons out of the sample.

That enabled the scientists to calculate the journey taken by the electrons after the first laser pulse and their position relative to the interface.

The researchers say that their findings will enable further research to develop principles for the design of hybrid organic PV cells. “These detailed measurements enabled us to reconstruct the trajectory of the electron and determine conditions that enable the effective generation of free electrons,” said Hui Zhao, professor of physics and astronomy at the University of Kansas and a co-author of the paper.

Meyer Burger has signed a ‘framework contract’ with an unnamed cell manufacturer which it expects will be worth $101 million.

According to the Swiss company, the order is for its heterojunction core equipment and has been placed by a cell manufacturing startup in North America founded by solar industry veterans. The announcement noted, however, the contract volume is subject to the purchaser closing a financing round.

Meyer Burger said it expects to receive a contractual down payment in the fourth quarter, when it will recognize the order intake.

The equipment manufacturer published its preliminary results for the first half, in which it saw an EBITDA (earnings before interest, tax, depreciation and amortization) loss of $14 million. Despite performance falling short of expectations, Meyer Burger said it expects to achieve break-even for the six-month period thanks to extraordinary income from the sale of its wafering business.

Disappointment

“I am disappointed with our half-year results,” said Meyer Burger CEO Hans Brändle before adding, with reference to another equipment supply order: “We have, however, achieved a decisive breakthrough with the delivery of our heterojunction and SmartWire cell connection technologies to REC. The first production line will soon be fully ramped up and the modules are already enjoying strong demand in the high-end segment. This success opens up new strategic opportunities for us.”

The full first-half results will be published on August 15, when Meyer Burger expects to report orders worth $96 million and net sales of $124 million. The company noted it is facing difficult conditions in its PERC [passivated emitter rear contact] cell equipment business thanks to falling prices for that type of manufacturing equipment, and it was “in advanced discussion” regarding its heterojunction and SmartWire cell connection platforms, though new orders have been delayed.

The company is undergoing a review of its business model, the results of which will be published “in due course”, Meyer Burger added, and could signal a major change in strategy.

“Business development in the first half of 2019 underlines the need to challenge our business model and corporate strategy,” said chairman Remo Lütolf. “We will evaluate all strategic options for the future. This includes discussions with industrial partners to develop new business models that create sustainable value for our company and our shareholders.”

REC Silicon ASA will lay off another 100 workers at its Moses Lake facility in the state of Washington, almost exactly one year after the last round of job cuts at the struggling polysilicon production plant. In a company issued statement, REC Silicon called on the federal government to restore “…open, fair, and unrestricted access for sales of U.S. polysilicon in the Chinese market.”

After operating at low utilization rates for more than a year, the plant is now heading into long-term shutdown. REC Silicon originally planned to suspend production at Moses Lake back in March, but has repeatedly extended this deadline, most recently in anticipation of a meeting between U.S. President Trump and Chinese Leader Xi Jinping at the recent G20 Summit in Japan, in the hope of a resolution to the U.S-China trade dispute that would restore its access to the Chinese market.

Though it still appears hopeful that trade negotiations will lead to the removal of tariffs on polysilicon imports from the United States into China, REC Silicon acknowledged that neither government has imposed a deadline for such a resolution or provided anything approaching certainty on when one might appear.

And now it appears time has run out for the beleaguered manufacturing facility, which heads into long term shutdown with the loss of another 100 jobs. REC Silicon states that an unspecified number of employees will remain at the site to allow the facility to restart on short notice, and that it will rehire its skilled employees should its access to the Chinese polysilicon market be restored in the near term.

The company noted that its second U.S. facility located in Butte, Montana, which produces polysilicon for the semiconductor industry, will not be affected by the Moses Lake shutdown. It also confirmed that restructuring costs associated with the shutdown and workforce reduction will be unchanged from the previously reported $3.7 million.

How to harness the excess heat solar panels generate alongside electricity is an increasingly important question for the industry.

In most PV installations that heat is not put to any purpose and reduces power output and long term performance stability – although researchers in Saudi Arabia this week revealed a device that can use it to power water distillation without hindering generation levels.

Waste heat is also a major problem in consumer appliances, with a University of Utah team which believes it has found a way to reduce limits on thermoelectric generation citing estimates as much as two thirds of energy consumed annually in the U.S. is wasted as heat.

Different strategies exist for dealing with such waste heat, most still at the research stage. One possibility is thermoelectric generation, which can produce electricity from differences in temperature. A theoretical limit for the process – the blackbody limit proposed by Max Planck more than a century ago – was believed to limit its usefulness. Several studies in recent years, though, have found ways around the blackbody limit to achieve higher rates of thermal energy transfer.

Breakthrough

The latest such research comes from the University of Utah. In the paper A near-field radiative heat transfer device, published in Nature Nanotechnology, the scientists describe a chip measuring 5x5mm comprising two silicon wafers less than 100 nanometers apart. With the chip held in a vacuum, one of the surfaces is heated and the other cooled, generating electricity from the heat flux.

Finding a way to place the silicon surfaces closer than one thousandth the thickness of human hair apart without touching was key to development of the device. “No body can emit more radiation than the blackbody limit,” said Mathieu Francouer, a mechanical engineering associate professor at the University of Utah. “But when we go to the nanoscale, you can.”

According to Francouer, such a device could channel the electricity generated into an appliance, increasing battery life for a laptop or similar device by much as 50%. In solar installations, the chip could boost system output by converting heat from sunlight into electricity and keep the system’s operating temperature lower, preventing degradation.

“You put the heat back into the system as electricity,” said the associate professor. “Right now, we’re just dumping it into the atmosphere. It’s heating up your room, for example, and then you use your AC to cool your room, which wastes more energy.”

A paper published last week in the journal Nature detailed how scientists at MIT demonstrated how an effect known as singlet exciton fission could be applied to silicon solar cells and could lead to cell efficiencies as high as 35%.

Singlet exciton fission is an effect seen in certain materials whereby a single photon (particle of light) can generate two electron-hole pairs as it is absorbed into a solar cell rather than the usual one. The effect has been observed by scientists as far back as the 1970s and though it has become an important area of research for some of the world’s leading institutes over the past decade; translating the effect into a viable solar cell has proved complex.

In the paper Sensitization of silicon by singlet exciton fission in tetracene, the scientists claimed to be the first group to transfer the effect from one of the ‘excitonic’ materials known to exhibit it, in this case tetracene – a hydrocarbon organic semiconductor, into crystalline silicon. They achieved the feat by placing an additional layer just a few atoms thick of hafnium oxynitride between the silicon solar cell and the excitonic tetracene layer.

“It turns out this tiny, tiny strip of material at the interface between these two systems ended up defining everything,” explained lead author Markus Einziger, a graduate student at MIT’s Center for Excitonics. “It’s why other researchers couldn’t get this process to work and why we finally did.”

Bridge effect

The hafnium oxynitride layer acts as a “nice bridge”, making it possible for high energy photons generated in the tetracene layer to trigger the release of two electrons in the silicon cell. The scientists reported the discovery saw a doubling of energy output from the green and blue parts of the light spectrum.

However, while they speculate the development could boost silicon solar cell efficiency to a maximum of around 35% – beyond the theoretical limit for single junction silicon solar – they did not include the efficiencies actually achieved in their experiments.

The researchers stated, while their newly published work provides the “crucial step” of coupling the two materials efficiently, there is still work to be done. “We still need to optimize the silicon cells for this process,” said MIT professor of electrical engineering and computer science Marc Baldo. “Overall, commercial applications are probably still a few years off.”

Efficiency could be even higher

The MIT researchers were keen to add their work, which they described as “turbocharging” silicon solar cells, differs from the most common approaches to increasing solar cell efficiencies, which these days are focused more on tandem cell concepts. “We’re adding more current into the silicon as opposed to making two cells,” said Baldo.

The team will continue its work with the materials, which could have the potential to achieve efficiencies for single junction silicon beyond even the 35% theorized. “We know that hafnium oxynitride generates additional charge at the interface which reduces losses by a process called electric field passivation,” said Einziger. “If we can establish better control over this phenomenon, efficiencies may climb even higher.”

The potential for solid state batteries to provide a safer and smaller alternative to today’s lithium-ion technologies is well known and research groups worldwide are working to overcome issues that hold the technology back from commercial adoption.

A discovery made by scientists at the Georgia Institute of Technology could help move such research in the right direction. The team built a solid-state battery with a solid ceramic layer as electrolyte between two layers of lithium. They then used x-ray computed tomography – a technique similar to the CT scans used in medicine – to observe its behavior and degradation during charging and discharging.

“Figuring out how to make these solid pieces fit together and behave well over long periods of time is the challenge,” said Matthew McDowell, assistant professor in the George W. Woodruff School of Mechanical Engineering and the School of Materials Science and Engineering. “We’re working on how to engineer these interfaces between these solid pieces to make them last as long as possible.”

Cracks appeared

The results, published in the paper Visualizing Chemomechanical Degradation of a Solid-State Battery Electrolyte, in the journal ACS Energy Letters, illustrated how cracks began to form in the electrolyte layer over a few days, causing increased resistance to ion flow.

Previously, said McDowell, it was thought chemical reactions at the interface between the lithium metal and electrolyte were the cause of degradation in the battery, rather than cracking in the cells.

“What we learned by doing this imaging is that in this particular material it’s not the chemical reactions themselves that are bad – they don’t affect the performance of the battery,” he added. “What’s bad is that the cell fractures and that destroys the performance of the cell.”

The researchers say their discovery is likely to also apply to alternative solid-state battery chemistries and could help influence further research into the creation of durable concepts for the promising technology.

“In normal lithium-ion batteries the materials we use define how much energy we can store,” McDowell said. “Pure lithium can hold the most but it doesn’t work well with liquid electrolyte. But if you could use solid lithium with a solid electrolyte that would be the holy grail of energy density.”

The solar industry and research community has already put a huge amount of work into one or two perovskite materials that have shown potential for highly efficient solar power generation.

The term perovskite, however, refers to a class of materials with a particular crystalline structure and encompasses an enormous number – “virtually limitless” according to the Massachusetts Institute of Technology (MIT) – of possible material combinations.

Searching through them to identify materials with strong solar cell potential is, therefore, a slow process. Computer modelling can help narrow down candidates, as the University of California, San Diego’s recent work demonstrated, but for real certainty scientists must go through the painstaking process of synthesizing and analyzing materials in the lab.

Scientists at MIT say they have been able to accelerate the process by a factor of ten by developing a system that permits parallel testing of a wide variety of materials and employs machine learning to further move things along. Tonio Buonassisi, professor of mechanical engineering at MIT, said his team aims to slash development time for new energy conversion material to less than two years.

Machine learning

Buonassisi explained most of the improvements in speed come from tracking and timing the steps involved and increasing the number of materials to be tested simultaneously. “We’re now able to access a large range of different compositions using the same materials platform,” he said. “It allows us to explore a vast range of parameter space.”

Adding machine learning techniques further reduces the time taken. The team used x-ray diffraction to observe details of a material’s structure and applied machine learning to classify the results. That, said MIT, reduced the time needed from 3-5 hours to a little over five minutes while maintaining 90% accuracy.

In the paper Accelerated Development of Perovsite Inspired-Materials via High Throughput Synthesis and Machine Learning Diagnosis – published in the journal Joule – the team described applying the process to 75 formulations, leading to the discovery of two new lead-free perovskites worthy of further investigation as potential solar cell materials.

Now, the researchers plan to make further use of automation to continue increasing the processing speed for classifying new materials. Buonassisi says another of his team’s goals is to bring about economically sustainable solar power prices of below $0.02/kWh. “All you have to do is make one material,” he says. “We’re putting all the experimental pieces in place so we can explore faster.”

Scientists at California’s Stanford University have demonstrated a new setup for water electrolysis, which can produce hydrogen using saltwater.

While splitting water using electricity to produce hydrogen is a well-established technology, commercial applications for which are beginning to emerge in various markets, most electrolyzers require purified water to operate, and system components degrade quickly in the presence of salt.

Were the technology to be scaled up to represent a significant part of our energy mix, this could put a heavy strain on water resources. According to Stanford researchers, the amount of hydrogen required in scenarios where it is used to fuel vehicles and power cities could not be produced using purified water, but this problem could be solved if all the water in the sea were available. “Seawater is the most abundant aqueous electrolyte feedstock on Earth,” reads the research paper’s abstract. “But its implementation in the water-splitting process presents many challenges, especially for the anodic reaction.”

Key to the system demonstrated by Stanford is a new type of anode, which is protected against salt corrosion by a negatively charged layer. The researchers explain that the anode consists of a nickel foam core, which transports electricity from the power source, and nickel-iron hydroxide layered on top of nickel sulfide–nickel iron hydroxide sparks the electrolysis process, while the nickel sulfide becomes negatively charged during the process, protecting the core materials from chlorides in the saltwater. The researchers explain the concept as similar to how the negative ends of two magnets repel each other.

One experiment conducted by the group, described in the paper Solar-driven, highly sustained splitting of seawater into hydrogen and oxygen fuels, published in the journal Proceedings of the National Academy of Sciences of the United States of America, used a solar-powered demonstration machine to produce hydrogen and oxygen from seawater collected from San Francisco Bay. The electrolyzer operated at a current density of 400 mA/cm² under a voltage of 2.12 continuously for more than 1,000 h without obvious decay.

The researchers note that without the coating, the anode usually falls apart after less than 12 hours of operation … the whole electrode falls apart into a crumble, but with this layer, it is able to go more than a thousand hours,” explained co-lead author on the paper Michael Kenney. “The impressive thing about this study was that we were able to operate at electrical currents that are the same as what is used in industry today.”

Scaling up

Stanford Chemistry Professor Hongjie Dai pointed out that his lab had shown proof of concept for the technology with this demonstration, but that scaling and mass production would be left to industrial players.

He went on to point out, however, that anodes incorporating the protective layer could be incorporated into existing electrolyzers, greatly easing the adoption of the technology. “It’s not like starting from zero,” Dai explains. “It’s more like starting from 80 or 90%.”

REC Silicon plans to suspend operations at its Moses Lake polysilicon production facility in Washington State from March 1, “unless trade negotiations between China and the United States yield tangible indications that REC Silicon’s access to markets in China will be restored, or other significant positive developments occur in the marketplace”.

The facility, which makes polysilicon for solar markets, operated at less than half its 18,000 metric ton (MT) capacity last year. REC Silicon was forced to lay off around 100 employees in July, and in September local members of the U.S. Congress wrote to President Trump warning of the plant’s impending closure, and urging the White House to “find an immediate resolution to the trade dispute over Chinese solar panels and American polysilicon”.

China imposed tariffs on polysilicon imports from the U.S. in 2014, effectively cutting off REC Silicon and other producers in the country from the world’s largest market.

REC says, without temporarily curtailing operations at Moses Lake it will not be able to meet cashflow requirements for its semiconductor materials operations. Moses Lake could remain shuttered, said the company, “until market conditions improve and/or the facility can be operated at increased production and higher capacity utilization”.

Losses in the quarter

The plan to close the facility was announced in the company’s financial filing for the fourth quarter of 2018. The figures showed, despite improved revenues compared with the previous three-month period, REC’s solar materials business contributed a loss of $9.1 million, to drag the business to an overall EBITDA loss of $3.8 million.

Quarterly revenue for the solar materials unit came in at $9.9 million, an improvement on the previous quarter’s $6.2 million. The company warned, however, demand remained soft after China’s 31/5 announcement to rein in public PV subsidies, and that overcapacity placed pressure on prices. REC Silicon realized a 16.6% price decline for prime grade polysilicon during the quarter.

The outlook for the company’s operations in China – a joint venture with Shaanxi Non-Ferrous Tian Hong New Energy Co. Ltd, in which REC Silicon currently holds a 15% stake – appears more positive. The joint venture produced 5,400 MT of polysilicon last year – including 1,850 MT in the final quarter – and utilization rates at the facility continued to rise. Siemens reactors at the facility were commissioned and demonstrated production of Czochralski (monocrystalline) grade polysilicon.

From pv magazine global

While yet to achieve the kind of efficiency levels to become commercially attractive, organic photovoltaics have sustained interest at a research and development level, thanks to their potential to be manufactured through simple, low temperature processes using cheap, abundant materials.

Now, a team of scientists at Friedrich-Alexander Universität Erlangen Nürnberg (FAU), in Germany – working alongside the South China University of Technology – has demonstrated further progress with the technology, achieving a record efficiency of 12.25% for an organic, non-fullerene based single-junction PV cell. The record has been certified by China’s National Institute of Metrology.

“For certification, they have to verify the active area – in that case, by masking with a non-refractive mask with certified area of 0.9062cm² on top of the 1.0cm² device; a calibrated light source – AM1.5, w/wo EQE cross calibration; and temperature control,” said Christoph Brabec, Chair of Materials Science – Materials in Electronics and Energy Technology at FAU.

Size matters

The device, described in the paper Fine tuning of the chemical structure of photoactive materials for highly efficient organic photovoltaics, published in the journal Nature Energy, measures 1cm² and is based on an organic molecule discovered by the researchers, which they describe as very durable and able to absorb more light than fullerene-based materials. The team says the device achieved a stability level ‘relevant to production’ in further testing.

In scaling the device up from a laboratory size of just a few square millimeters, the researchers employed optimization techniques to maintain the highest efficiency possible; and noted that with the smaller device, the highest value measured was just under 13%.

“Significant losses frequently occur during scaling,” said Ning Li, of FAU’s Institute of Materials for Electronics and Energy Technology. “Our partners in China inserted and adjusted single molecular groups into the polymer structure, and each of these groups influences a special characteristic that is important for the function of solar cells.”

The next step for the group will be to further scale up the device to module size and then begin the development of practical prototypes.

This article was originally published on pv magazine’s global site.

Fraunhofer ISE, in collaboration with the EU-funded CPVMatch project, has set a new record for solar module efficiency at 41.4%.

The module measures 122 cm² and utilizes a multijunction, tandem cell set up, with multiple layers of active cell material stacked on top of each other to absorb different sections of the light spectrum. Fraunhofer did not specify the cell materials used in the record-breaking module, other than to say that they are based on III-V compound semiconductors.

The module also relies on concentrator PV (CPV) technology – whereby sunlight is concentrated onto a cell using a Fresnel lens. The team says it was able to make use of achromatic lenses in the module, further contributing to the record efficiency. Such technology has proven to enable very high efficiency levels, but has seen little commercial uptake so far, as its performance is limited to areas with high levels of direct solar irradiation.

“We are extremely please about these results that pave the way for further efficiency increases in the concentrator technology,” says Andreas Bett, institute director at Fraunhofer ISE. “Photovoltaics is booming worldwide, and we see great potential for this particularly efficient module technology. It significantly decreases the use of resources for energy conversion per unit area and thus contributes to more sustainability.”

Back in 2014, Fraunhofer ISE was part of a collaboration that reached 46% cell efficiency using combined concentrator and III-V multijunction technology. Since then it has worked with the CPVMatch project to push the technology further.

“In CPVMatch, we have addressed all production steps for concentrator modules starting from the materials, through cell fabrication and production systems, and up to the challenges facing module manufacturing,” says Gerald Siefer, project head III-V Cell and Module Characterization at Fraunhofer ISE.

While there is no doubt that Fraunhofer ISE’s achievement here is impressive, and that the researchers say they have also been able to “optimize the production of four junction solar cells,” it should be noted that, while extremely efficient, III-V materials are typically prohibitively expensive when it comes to mass-production and have so far only found use in niche applications such as satellites and drones, where high efficiency is more important than cost.

The achievement could allow CPV to better compete with concentrated solar power – which converts heat from the sun into steam to generate power – in areas with hot, dry climates and few clouds.

NantEnergy, formerly Fluidic energy, has acquired energy systems and services business of Sharp in the United States.

The acquisition includes Sharp’s SmartStorage system, a behind the meter energy management platform which reduces peak energy use for companies through smart charging. The business also has an active pipeline of more than 60 MW of solar + storage projects in the USA.

NantEnergy says that the acquisition will allow it to offer ‘energy as a service’, and to further leverage its zinc-air battery technology for longer duration storage and backup power applications. NantEnergy says it will continue to promote the SmartStorage system, along with the optional 10-year Asset Management Service Agreement. Existing SmartStorage service agreements will continue to be covered by NantEnergy. Financial details of the acquisition have not been disclosed.

“Adding Sharp’s sizable and world-class energy storage business to the NantEnergy service portfolio is an important step in our mission to accelerate the worldwide transformation to clean, reliable energy through intelligent energy storage solutions,” said Dr. Patrick Soon-Shiong, chairman of NantEnergy. “The acquisition of Sharp’s energy systems business and the SmartStorage brand immediately creates a foothold for NantEnergy in the U.S., particularly in the important California market.”

Following the extension of a subsidy scheme in September, California is set for a boom in behind the meter storage, with up to 2.5 GW expected to be installed by 2025.

REC Silicon posted revenue of $44 million for the third quarter of this year, a 26% drop on the $59 million recorded in the previous three months. The company’s EBITDA loss narrowed to $6.1 million – from $9.6 million in Q2 – thanks to cost reduction efforts including the lay off of around 100 employees at its Moses Lake production facility in Washington State.

Much of the difficulty faced by REC Silicon comes from its solar materials segment, which saw $6.2 million in revenue in the latest reporting period, for an EBITDA loss of $9.9 million. The company said its revenue decrease is primarily the result of lower sales volumes, and lower prices for solar-grade polysilicon, in the wake of the Chinese government’s announcement in May to pull back on public solar subsidies. However, REC Silicon has been struggling for years as the result

Sales volume for solar-grade polysilicon fell to 658 MT, a 62% fall compared to the previous quarter’s 1,742 MT. REC added, it saw sales prices fall by around 20% compared with the previous reporting period.

The company’s U.S. production facility in Moses Lake, Washington, continued to operate at 25% capacity, producing around 1,615 MT in the third quarter, in line with previous guidance. That means REC added another 503 MT to its inventory.

Fears surround Washington facility

The facility achieved a cash cost of $15.1/kg in the latest quarterly figures, lower than the previous forecast of $15.8/kg, but still well above global average poly prices. REC said it was able to reduce the production cost per kilogram through cost cutting measures, but the low production capacity utilization meant an increased unit cost – with REC adding it was able to achieve a cost of $11/kg earlier in the year.

However the demand slump means the company is cornered, and expects the utilization rate at the plant to remain around 25% “until the trade between China and the United States is resolved or market conditions improve”.

REC said its position is sufficient to meet operating cashflow requirements for twelve months. However, a group of Congressmen from the states of Washington and Montana wrote to President Trump in late September, warning the Moses Lake plant would be forced to close unless there are successful negotiations to restore access to Chinese polysilicon markets.

The manufacturer was more positive about its joint venture for polysilicon production in China, in which it holds a 15.06% stake with the option of raising to 49% at a later stage. The company reports the plant in Yulin, in China’s Guangxi Province, produced around 3,000 MT of polysilicon in Q3, and is set to reach full utilization in early 2019.

Scientists from the Lawrence Berkeley National Laboratory in California have discovered a particular shade of blue could boost building energy efficiency in sunny climates by keeping walls and rooftops cool, and also increase the output of certain types of solar cell, through strong infra-red emissions.

The researchers measured the temperature of surfaces coated in the color, known as Egyptian blue and derived from calcium copper silicate, and though it is already known photons absorbed by the material can be emitted in the near-infrared range, the new research demonstrated the effect could be 10 times stronger than previously thought, with the material able to emit as many photons as it absorbs.

This, Berkeley researchers theorize, could lead to applications in building integrated PV, such as solar windows tinted with the blue, and transparent cells tuned to absorb the near infrared part of the light spectrum.

The discovery, outlined in the paper High quantum yield of the Egyptian blue family of infrared phosphors (MCuSi4O10, M = Ca, Sr, Ba), and published in the Journal of Applied Physics, could add more colors to the palette of architects and building owners, who for aesthetic reasons tend to stay away from the whites and grays that offer the best cooling properties.

Painting with perovskites

Another solar discovery this week came from the U.S. National Renewable Energy Laboratory, which has developed a perovskite based ‘ink’, which can be painted on to a substrate, creating an active solar cell.

Though the cells produced using the ink at this stage are very small, and do not produce a lot of power, NREL’s David Moore says the discovery could allow manufacturers to eliminate complex deposition processes and high temperatures from solar production, greatly reducing costs.

“You can’t make silicon panels fast enough to get to that demand,” said Moore, referring to an anticipated demand for 25 TW of new power capacity in the next 30-50 years. “But if you can roll stuff out on presses, then you could. Getting to a roll-to-roll manufacturing process would solve the speed problem. The most likely way to do that would be [through using] wet ink.”

If such a process were commercialized, manufacturers would be able to apply the perovskite ink to a glass substrate, in a roll-to-roll process similar to the way newspapers are produced. NREL researchers also visualize application directly, as a paint.

“The day may come when a crew shows up to your house, sprays the metallic contact layer onto an outside wall and, when that’s dry, applies the perovskite ink,” states an NREL release publicizing the research.