Taipei’s Nangang Exhibition Center hosted another Energy Taiwan event this week, combined with Net-Zero Taiwan, focusing on reducing the emissions of the island’s many industries. The show comprised 350 exhibitors and more than 24,000 attendees over three days, which the organizers say amounts to 28% growth over last year. Simon Wang, President of the Taiwan External Trade Development Council, also noted that around 20% of attendees were at the event for the first time, denoting a growing importance for companies looking at net-zero strategies and ways to implement renewable energy.

Energy storage

Energy storage was front and center throughout the event, with companies from various background exhibiting batteries. Many of these are focused on commercial solutions for large, energy hungry industries to maximize their renewable energy uptake. And these often came with sophisticated energy management solutions –  illustrating Taiwan’s position as a leader in software development.

The show also saw plenty of talk about large-scale storage, and hopes that changes to legislation might soon drive bigger demand for residential energy storage as well. Battery suppliers were also keen to demonstrate their latest fire safety innovations, including cell level monitoring, automated water and chemical fire suppression systems and the somewhat simpler approach of encasing the whole battery system in concrete, which supplier TCC says would be able to contain fire at temperatures above one thousand degrees, and also bring other advantages in system longevity.

Taiwan will still be reliant on imports for its energy storage plans, with many players sourcing fully made batteries from abroad, or only assembling cells into packs locally. One company, Formosa Smart Energy, is looking to bring battery cell manufacturing to Taiwan. President Hui-Chi Liu told pv magazine that the company is working to bring 2.1 GWh of battery cell capacity online by the middle of 2024, with plans to later expand this to 5 GWh. At its booth in the exhibition, the company also had innovative approaches on show to battery recycling and solid-state batteries based on a mixed ceramic/polymer electrolyte.

Solar manufacturing

Taiwan’s solar manufacturing industry has seen little growth lately, faced with heavy competition from producers in mainland China. The cell and module makers at the show, however, shared a positive outlook, with expectation of more orders from domestic projects, as well as strong exports to the United States – where prices have remained high enough for Taiwan’s manufacturers to be competitive.

One manufacturer stated that it is also examining the opportunity of bringing manufacturing capacity online in the US, but sees some signs that the Inflation Reduction Act, which has brought with it a flood of factory announcements across the US, may have passed its peak. Their calculations show that the US could have 60 GW of module manufacturing capacity up and running by 2026, without much more than 40 GW of annual domestic demand to serve.

On the technology side, these manufacturers report that reliability, rather than the latest technology is the name of the game for now. All of the manufacturers pv magazine spoke with at the event are in the process of switching passivated emitter rear contact (PERC) manufacturing to the latest high efficiency tunnel oxide passivated contact (TOPCon) technology, by the middle of next year.

Cutting silicon cells in half, and making them able to generate electricity from sunlight hitting both sides, are two innovations that brought the possibility of increased energy yield at little extra production cost. Consequently, both of these have grown rapidly over the past few years, and now represent the mainstream in solar cell and module manufacturing.

New research, which was among the winners of a poster award at the EU PVSEC conference held in Lisbon last month, has demonstrated that the combination of half-cut and bifacial cell designs may contribute to hotspot formation and performance issues, under certain conditions. And current testing standards, the study’s authors warned, may not be equipped to spot modules vulnerable to this type of degradation.

The researchers, led by Spain-based technical consultancy Enertis Applus, covered parts of a PV module to observe its behavior under partial shading. “We forced shadowing to take a deep dive into the behavior of monofacial and bifacial half-cell modules, focusing on hot spot formation and the temperatures these spots reach,” explained Sergio Suárez, global technical manager at Enertis Applus. “Interestingly, we identified mirrored hot spots that emerge in the opposite position with respect to normal hot spots without apparent reasons, like shadowing or breakages.”

Faster degradation

The study indicated that the voltage design of half-cell modules may cause hotspots to spread beyond the shaded/damaged area. “The half-cell modules presented an intriguing scenario,” continued Suárez. “When a hotspot emerges, the module's inherent voltage parallel design pushes other unaffected areas to develop hotspots as well. This behavior could hint at potentially faster degradation in half-cell modules due to the appearance of these multiplied hotspots.”

The effect was also shown to be especially strong in bifacial modules, which reached hotspot temperatures up to 10 C higher than the single-sided modules in the study. The modules were tested over a 30-day period under high irradiance conditions, with both cloudy and clear skies. The study is soon set to be published in full, as part of the proceedings of the 2023 EU PVSEC event.

According to the researchers, these results reveal a route to performance loss that is not well covered by module testing standards.

“A singular hotspot on the lower part of the module might instigate multiple upper hotspots, which, if not addressed, could accelerate the module's overall degradation through increased temperature,” said Suárez. He further noted that this could place additional importance on maintenance activities such as module cleaning, as well as system layout and wind cooling. But spotting the problem early on would be preferable to this, and require new steps in testing and quality assurance at the manufacturing stage.

“Our findings spotlight a need and an opportunity to re-evaluate and possibly update standards for half-cell and bifacial technologies,” said Suárez. “It's essential to factor in thermography, introduce specific thermal patterns for half-cells and adjust the normalisation of thermal gradients to Standard Test Conditions (STC) for bifacial modules.”

The mood of “cautious optimism” that kicked off the week in Lisbon continues. Speakers and exhibitors appear more confident than ever that solar cell and module performance will continue to improve, and that reliability and system lifetimes will increase.

The practical matters of rolling out these technology improvements at scale and integrating them into landscapes and electricity grids around the world are emerging as a new set of key concerns for solar experts in every specialty, and topics related to these take a prominent position at this year’s conference.

Topping the agenda since day one has been the geopolitics of manufacturing. The risk of continuing to rely on a single region for supply is becoming an essential component in energy systems. And there is a clear consensus that the solar industry wants to see action from the European Union and member state governments to support the establishment of a domestic supply chain for solar energy products via incentives.

Grid and landscape

Beyond that headline, several sessions have delved into the grid constraints that threaten to slow down solar installations in some otherwise leading markets – a topic that SolarPower Europe CEO Walburga Hemetsberger called for researchers to address in the opening panel discussion on Monday. Solutions to these constraints are grid upgrades, energy storage and increased interconnection. Here as well, regulation seems to be a major hold up, and consensus is that allowing more private investment in grid infrastructure would be an effective way to speed up the required changes to energy infrastructure.

Integrating solar into landscapes and built environments has also been a key topic, as land constraints begin to be felt. Tuesday afternoon saw a session dedicated to ensuring the reliability of PV systems in tough climates such as deserts and water surfaces, and introduced the possibility of accelerated testing specifically designed to simulate these environments – a presentation by Bengt Jäckel of the Fraunhofer Institute for Silicon Photovoltaics introduced the idea of “mission profiles” to test PV equipment under the combined stresses of different environmental conditions. And the extra capacity that could be opened up by improvements in building-integrated PV products, agrivoltaics and also by simple efficiency improvements getting more energy out of the same amount of space.

Sustainability

Impressive progress in PV module recycling is also on show at this year’s conference, with high technology approaches to shred modules using light pulses or high pressure water jets on show, and new processes focused on extracting the most valuable materials for reuse. And it’s clear from those presenting and in the audience during this session that an industry is forming around these processes, with both new startup companies and those already established in glass recycling all looking at setting up factories able to handle several thousand tons of module waste per year.

Wednesday morning’s session covering the latest in silicon PV technologies also illustrated the industry’s growing focus on sustainability – with a presentation from Longi Solar’s Chunxui Li detailing potential problems with the supply of indium for heterojunction modules, and a neat way to get around this, achieving better than 26% cell efficiency.

New technologies

This session later moved on to the high efficiency cell technologies now making their way from laboratories toward manufacturing.

Offering a comprehensive update on tandem cell technologies, Helmholtz Zentrum Berlin’s Rutger Schlatmann stated that the progress made and the number of companies pursuing the technology mean that the solar industry is now committed to bringing perovskite technology to the market. This was underlined in the following presentation by Oxford PV’s Laura Miranda and has been reflected in many other presentations on the topic of perovskites – which have focused on the development of testing and characterization techniques, as well as large-scale manufacturing processes, with few presentations demonstrating new lab-made cells.

Finally, on the technology front, First Solar’s Matthew Merfert revealed some impressive results and an ambitious roadmap for the US-based thin-film giant. The company hopes to increase its efficiency to 25% over the next few years, and has also successfully demonstrated an approach to replace its metal back contacting structure with a transparent conductive oxide, potentially opening doors to bifacial cadmium-telluride modules, and the uses of this technology in a tandem or multijunction cell stack.

Now in its 40^th year, EUPVSEC kicked off in Lisbon this morning with an opening session that shows a European solar industry that appears confident of a comeback, despite recent challenges.

The event this year is already far larger than any going back as far as 2018, and has a much bigger industrial presence than previous years, which have been dominated by Europe’s PV research institutes and universities, with only a few equipment suppliers making the journey. The return of industry players was underlined from the start, with the awarding of the Becquerel Prize to longtime PV industry leader and CEO of Meyer Burger, Gunter Erfurt.

Accepting the prize earlier today, Erfurt spoke of the need for an industry-wide change in attitude on several fronts including policies to compete with lower-priced imports making their way into Europe, and the handling of intellectual property. On the imports side, he called for incentives on the buyer side for use of European made products, and stressed that globally,  the solar industry must change its attitude to intellectual property to one that values innovation and the investment that comes with it, and accepts that making or buying products that copy another’s work are not an acceptable strategy.

Nevertheless, he stated confidently that Europe can produce solar modules for the rooftop and utility-scale markets, and achieve a levelized cost of energy very close to products imported from any region.

Policy challenges

Discussions in the opening session carried on with this air of optimism, while also recognizing that solar faces big challenges both in Europe and globally. Speaking in a panel discussion, SolarPower Europe CEO Walburga Hemetsberger stated that European PV is on a good path, with continent-wide PV installations expected to reach eight terawatts by 2050. “We see growth, but we cannot be complacement” she told the audience in Lisbon.

Later, the difficult situation faced by European PV manufacturers was laid out in a presentation by the European Solar Manufacturing Council’s Johan Lindahl. He warned that average capacity utilization for factories in Europe has fallen to 35%, with some manufacturers sitting on inventories now too expensive to be sold – and the ESMC is calling for support from the EU, possibly in the form of a program to buy out these inventories and donate the modules to reconstruction efforts in Ukraine. “To be an EU manufacturer equals a major structural disadvantage,” Lindahl told the crowd in the first session after lunch today.

And the wave of new manufacturing facilities currently under construction in the United States is also being discussed as further impetus for the EU to take action in supporting a European industry: “The Inflation Reduction Act is wake up call for Europe,” said Hemetsberger. “All regions want the PV technology of the future, and Europe must get into that race.”

Efficiency and integration

Much of the talk this morning has focused on the need for a policy overhaul to support solar at EU and state level. But EUPVSEC is traditionally a place where the latest PV technologies making their way out of Europe’s top R&D labs is showcased. And this year should be no different.

Talk of new applications and increased learnings on floating PV and agrivoltaics are emerging already as key themes: Also joining this morning’s panel discussion, Solar Energy Research Institute of Singapore’s Thomas Reindl stated that both floating PV (including offshore) and agrivoltaics will be key enablers in keeping solar installations growing, as well as space for building-integrated PV, which has so far seemed more difficult to manufacture, but no less important.

The opening panel discussion also noted that European research institute’s have led the solar industry in achieving close to a 0.5% per year increase in module efficiency for more than 20 years, and maintaining, even improving on this will be a key theme for week-long conference. “Bigger leaps in technology are ahead of us,” said Reindl. “Every additional kilowatt-hour we can generate from the same space is precious.”

Perovskite solar cells (PSCs) already show strong potential for low cost, high performance solar cells. Questions over their long-term stability are one of the main things holding the technology back from commercial production.

Accelerated testing conducted in the laboratory can help researchers and manufacturers to more quickly understand what will likely happen to the cells once installed outdoors, and to address any weaknesses early on. And as PSCs move closer to commercialization, the need for a testing standard that can be universally applied is becoming clearer.

“We must understand how well perovskite solar cells will perform outdoors, under real conditions, to move this technology closer to commercialization,” said Kai Zhu, a senior scientist in the Chemistry and Nanoscience Center at the US Department of Energy's National Renewable Energy Laboratory (NREL). “That’s why we identified accelerated testing protocols that can be conducted in the laboratory to reveal how these cells would function after six months in operation outside.”

Zhu and colleagues at NREL and the University of Toledo put a batch of the latest PSCs, with an initial efficiency of up to 25.5%, through various tests and compared the results to cells that had been installed outdoors for six months. The tests are described in full in the paper “Towards linking lab and field lifetimes of perovskite solar cells,” published in nature.

Light and heat

The PSCs in this study retained more than 93% of their initial efficiency after 5,000 h of continuous illumination. The tests also included thermal cycling, where temperatures fluctuated between -40 C and 85 C. After 1,000 thermal cycles, the cells had lost around 5% of their initial performance.

The results show that tests that expose the PSCs to light at elevated temperatures gave the most accurate impression of how the cells would degrade after six months in the field. The study also showed that the interface between the active perovskite layer and the hole transport layer, consisting of a self-assembled monolayer of indium tin oxide, is also key to the cell’s reliability. When the ion-blocking properties of this layer were improved, the cell’s stability almost tripled – operating for 1000 hours at 85 C, and more than 8000 hours at 50 C with an expected 20% performance loss, which the group says is among the best results recorded to date for a high efficiency perovskite solar cell.

Silver paste supplier Solamet announced a new product this week, specifically targeting the TOPCon cell technology processed with laser carrier injection, that is well on its way to becoming the industry’s mainstream over the next couple of years.

The paste is targeted at unlocking benefits of laser carrier injection, a post process treatment for TOPCon cells. Laser carrier injection creates more micron-sized silver contact points, improving the contact with the cell surface. However, according to Solamet, current standard silver pastes used in TOPCon cell production don't deliver the efficiency benefits this treatment can bring, and specially designed formulations are needed.

The new paste, PV3NL, designed for laser carrier injection, can be adopted by cell manufacturers without significant changes to their process or machinery. According to Solamet, companies adopting can expect to see at least a 0.2% improvement in absolute efficiency, which it has demonstrated iterations of the TOPCon cell technology.

The company said its latest paste product overcomes a challenge at the interface between the paste and the surface of the cell.

“One of the most significant technical challenges of TOPCon solar cells is the loss of open-circuit voltage and efficiency caused by the recombination issue caused by silver-aluminum pastes contacting p+ surface,” explained Solamet Chief Technology Officer QJ Guo. “Based on in-depth research into the mechanism on metallization induced recombination of the TOPCon p+ surface, the newly developed PV3NL solar paste has been specifically designed.”

Thanks to reduced recombination between the paste and cell and an increased open circuit voltage, the paste can increase the efficiency of TOPCon cells by 0.2% or more, said Guo. The supplier also states that its new product will help to improve module reliability – particularly in glass-backsheet, where the industry has reported some early challenges with TOPCon cells related to corrosion caused by moisture ingress.

The company also says its new paste will be compatible with other process innovations including ultra-thin lines, low paste consumption and low surface concentration diffusion processes for emitter regions.

“We are thrilled that Solamet is once again revolutionizing the photovoltaic industry with groundbreaking technology and product in its new chapter after independent operation,” said Guo. “We remain committed to advancing high-efficiency photovoltaic cell technology through material technology innovations.”

Previously a subsidiary of DuPont, Solamet was acquired in 2021 by Jiangsu Suote Electronic Materials Co., Ltd. and now operates as an independent company.

This article was amended on 01/09 to add additional information on the laser carrier injection treatment.

A new study published by Greenpeace found widespread use of misleading numbers and strategies in reporting on emissions and climate impacts among 12 of the largest oil companies with headquarters in Europe.

The study, titled Dirty Dozen: The climate greenwashing of 12 European Oil Companies, looks into financial statements published by six of the world’s largest oil companies – Shell, TotalEnergies, BP, Equinor, Eni, Repsol, and another six smaller players that still play a major role in the energy supply of their respective European markets – OMV, PKN Orlen, MOL Group, Wintershall Dea, Petrol Group, Ina Croatia.

These companies have enjoyed huge revenues over the past year, with their 2022 profits increasing by an average of 75% over the previous year. Despite this, new investments made by the companies increased on average by just over half that amount – 37%. And 92.7% of these investments were made in the continued extraction of fossil oil and gas.

This comes in spite of the common claim among large fossil fuel companies that higher profits are necessary to provide the means to finance a transition to renewable energy, which Greenpeace describes as “like eating more to have the energy for the diet.”

All 12 of the companies in the studies produced at least 98% of their energy in 2022 from fossil fuels, with an average of just 0.3% from renewable sources. And those which are making any investment in “low carbon” technologies are focused on offsetting and carbon capture – two strategies whose effectiveness in reducing emissions is in serious doubt.

No net zero

The study also finds that while most of the companies involved have made a public commitment to reach net zero emissions by 2050, none has anything resembling a coherent strategy in place to achieve this.

“…no major oil company can show a comprehensible plan for a “net zero” in 2050. There is, if at all, a slow start in the 2020s, which is then miraculously supposed to lead to a rapid transformation after 2030. In other words, the solution to the climate problem is postponed to the future or to the next CEO,” the report stated.

The report also noted a range of strategies used by some of the 12 companies that seem designed to mislead the public over their commitment to emissions reduction. From creative definitions of what constitutes “low carbon” for investment, to simply misleading visual layouts – such as Shell placing “conventional fuels” in fourth place on a list of its energy portfolio, despite these accounting for more than 90% of its energy production.

Comprehensive strategy

Greenpeace calls for various measures to be put in place to change this situation, placing efforts to reduce demand for fossil fuels at the center of its proposal. “Similar to the coal sector, the focus should therefore be on a rapid economic and political downsizing of the oil and gas sector, on skimming profits, avoiding stranded assets and, above all, on a rapid reduction of oil and gas demand,” they state.

The report calls for a comprehensive demand reduction strategy to be put in place at EU level, including a ban on short distance flights and promotion of zero-carbon fuels in long distance aviation, noting that “The benefits of these new fuels must be independently confirmed in a life-cycle approach in order to exclude, for example, the use of biofuels, which can cause high climate damage along their production chain.”

Other industries earmarked for action include marine shipping – which also requires support for alternative clean fuels, and the petrochemical industry which should see restrictions on per capita consumption of plastic materials.

Greenpeace also states that, in combination with demand reduction, these measures can be accompanied supply side measures such as windfall tax on profits, a ranking of the most environmentally damaging fossil fuel supply chains, and a stop on exploration of new oil projects across EU territories and the North Sea.

Further, the report calls for increased regulations on international oil companies, including a general ban on advertising and much tighter reporting definitions to address greenwashing in public statements.

Computer simulations play a valuable role in helping scientists identify materials with characteristics that make worth a closer look. An investigation carried out at the US Department of Energy's Oak Ridge National Laboratory (ORNL) used research into solar cell materials provides an example of this, as well as illustrating how quantum computing techniques could be used to simulate even more complex interactions.

Singlet fission is a process where one photon is able to excite two electrons – potentially greatly increasing solar cell efficiency. It has been observed to occur in various materials, but understanding its mechanics and getting it to happen in a uniform way have so far proved difficult.

“Conventional solar cells have a theoretical maximum efficiency of about 33%, but it has been postulated that materials that exhibit singlet fission can break that limit and can be more efficient,” said Daniel Claudino, a research scientist at ORNL’s Quantum Computational Science group. “The downside is that to understand fundamentally whether a certain material exhibits singlet fission is very hard. There is a specific energetic requirement, and it's difficult to find materials that fulfill it.”

Using Quantinuum H1-1 – a commercially available quantum computer located in Colorado, the group was able to develop an effective simulation to identify molecules that demonstrate singlet fission, and showed that a “linear H₄” molecule consisting of four hydrogen atoms has the necessary energetic level for the singlet fission process – which the group says could be useful knowledge in the development of more efficient solar cell materials.

The simulation is described in full in the paper Modeling Singlet Fission on a Quantum Computer, published in The Journal of Physical Chemistry Letters.

Quantum computing

More valuable than the actual findings in this study is the demonstration of a useful application for quantum computing – a technology still in its early stages. Quantum computers are able to go beyond the binary ones and zeros used in conventional computers, and also use both positions simultaneously – making them potentially much more powerful in solving certain types of problems.

Claudino says that singlet fission provides an excellent solution to a problem for quantum computers to tackle. “The energetics of singlet fission revolve around double electronic excitations — two electrons move up to higher energy levels simultaneously, which is quite difficult to pin down with algorithms for conventional computers,” Claudino said. “But the underlying way that a quantum computer works, it can naturally treat the quantum correlations that give rise to this singlet-fission phenomenon.”

The group came up with multiple ways to simplify and optimize its algorithms for use in the quantum computer “The idea is that you want to envision a way to tap into the quantum computer but only for specific tasks that we know they can perform better than conventional computers,” Claudino said. “Yet, even then, you’re still limited by the current state of the art that only allows us to either go up to a certain size or perform tasks that only take so long. That’s the major bottleneck when turning to quantum computers.”

The group says that its optimizations reduced the processing time from several months to a few weeks, demonstrating the viability of quantum computing, and introducing a set of best practices for use of current systems.

Claudino and colleagues now plan to move on from singlet fission and investigate other applications for the quantum computing techniques it developed, including looking into “the interaction of matter and light.”

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.”

Virtually all modules on the market today feature cells that have been cut into two or more pieces. Using cut cells results in a lower current, reducing power loss at the module level. Half-cell modules typically produce 3-5% more power than full-cell equivalents.

But the cutting process itself can result in the loss of some of this power – typically when damage at the cell’s cut edge causes cracks to form and spread when the module is put under various forms of pressure in the field.

Optimized cutting processes have been developed to greatly reduce damage at the cell edges, and additional processes to repair the break in cell layers caused by cutting are also being brought to the market this year. Many manufacturers though continue to rely on lower cost ‘scribe and break’ processes that typically leave some damage at the edge of a cell.

A group of scientists led by Korea University looked at ways to minimize performance loss in modules using laser scribing and mechanical cleaving (LSMC) and break-cut cells. Both changes to the parameters of the laser process and additions to the module design were investigated as part of the study.

Bending cells

The group tested five different sets of laser parameters, varying the power, frequency and pulse length. The strength of the cut cells was then tested via four-point bending. Setting the laser to low power (30 W), short pulse duration (10 nanoseconds), and high frequency (600 kilohertz), produced the best result.

Cells cut under different parameters were also observed under a microscope to spot cracks forming, and processed into modules for further testing. After mechanical load testing, the same set of laser parameters was shown to produce the best performing module – which lost 5% of its performance compared to 6.63% for cells cut under reference conditions.

Further module testing also demonstrated that working with a thicker encapsulant, or adding a support rail to the rear of the module, could further reduce the propagation of cracks in the cells and associated power loss – though the study did not cover the implications of these on cost or other aspects of the module.

The experiments are described in full in the paper “Reliability study on the half-cutting PERC solar cell and module,” published in Energy Reports. “This study can contribute to improving the reliability, such as energy yield on the large size wafers product such as M10 or M12 because those wafers have more length to cut than M2 size in this study.” The group says it now plans further studies on the larger format cells in use today.

German PV production equipment provider RENA technologies GmbH has announced the sale of 1.8 GW of new tools for chemical etching of silicon wafers during cell production. The new tool, NIAK 4, was introduced to the market just a few weeks ago at The smarter E exhibition in Munich.

“We are thrilled to see such a positive response to the InEtchSide NIAK 4,” said Peter Schneidewind, CEO of RENA. “We have always been committed to providing our customers with the latest and most efficient technology, and the new NIAK4 platform is another great example.”

This first sale of the new tool goes to a manufacturer operating a gigawatt-scale TOPCon production line. RENA did not confirm the name of the manufacturer, other than to say it was a long-term partner of theirs based in South Asia. Given the mentioned cell technology and scale, it is likely to be a Chinese module manufacturer. RENA said that the tools are expected to be delivered and installed by early 2024, and has not disclosed any financial details of the sale.

The tool builds on RENA’s existing expertise with chemical etching processes, offering fully automated etching on just one side of the wafer, including rinsing and drying. RENA says that the customer was convinced by the high throughput of 13,800 wafers per hour.

The NIAK 4 tool presents a solution to a challenge that emerged early on in TOPCon’s commercial development – that cells require layers of different materials on each side, which need to remain isolated from each other, and fully single-sided deposition processes are more complex to run at scale. So material deposited on the rear side of the wafer during low-pressure deposition needs to be removed.

“The tool finds its application in various areas of solar cell production. It excels in rear side oxide etching for high-efficiency solar cells, as well as in the single side removal of SiO2, PSG, or BSG,” explained RENA, announcing the sale. “Moreover, the NIAK 4 is fully compatible with PERC, IBC, and TOPCon technology, offering flexibility and versatility to manufacturers.”

Most PV manufacturers are now well underway with the switch to n-type technologies, and we are beginning to see these modules, primarily based on n-type TOPCon technology, rolling out to mainstream installations.

As they made the switch, manufacturers promised more electricity and longer lifetimes from the new products. And as they make their way into more projects, we can see how these claims play out in the field under various climate conditions. Many studies have been carried out already, and the signs so far are good for n-type.

One such study confirms a 5.69% gain in normalized energy yield (energy generated per unit of capacity) over a three month period. German company TÜV Nord carried out the study at a test installation in Selangor, Malaysia.

Three module types were installed at the site: A 545 W n-type TOPCon module and a 540 W p-type PERC module, both using 182 mm half cells and both manufactured by JinkoSolar. A third module, also bifacial PERC, with 210 mm cells and a 645 W power rating and from an unnamed manufacturer, was also included in the test. The test installation comprised two modules of each type, installed on fixed tilt racking 1 meter above the ground and connected via micro inverters.

Performance of each module was carefully measured over the first three months of 2023. During the period, Jinko’s TOPCon module generated 205.32 kWh, while its PERC counterpart reached 192.42 kWh, and the PERC module based on 210mm cells generated 227.89 kWh.

Thanks to its higher power rating and larger size, the 210mm module generated the most energy during the three-month period. However, when normalized based on each module power rating, the n-type module achieved a yield 5.69% higher than the 182 mm PERC module used as a baseline, while the larger module was 0.97% behind.

Jinko’s n-type module also achieved the highest performance ratio of the three. Performance ratio compares the actual energy yield to a calculation based on the power rating and weather conditions. TÜV Nord measured a 96.03% performance ratio for the n-type module, with the other two trailing slightly behind.

Separately, TÜV Nord also compared JinkoSolar’s TOPCon module with a conventional PERC product in accelerated reliability testing: two modules were subject a series of laboratory tests, going beyond the standards outlined by the IEC. Modules were subject to thermal cycling, extended damp heat, mechanical load, humidity freeze and ultraviolet light.

Additional test stages designed to detect susceptibility to light induced degradation (LID) Light-elevated temperature induced degradation (LETID), and potential-induced degradation. In all of these test stages, the n-type module showed significantly better performance.

In LID testing the n-type module lost 0.26% of its initial performance, compared to 1.92% for the PERC module. LETID testing told a similar story, with a 0.09% loss for the n-type module, and 1.17 for PERC. And in UV testing, which has emerged as an area of concern for some TOPCon modules, JinkoSolar’s n-type product lost only 0.60% performance, compared with 2.21% for the PERC product.

Solar cells and modules are designed to be highly resistant to ‘shunts’ – which create an alternate pathway for a solar-generated charge, leading to power losses. Reduced shunt resistance is associated with multiple forms of module degradation and failure, including hotspots and potential-induced degradation.

A group of scientists led by Ireland’s University College Cork looked to further investigate the relationship between shunt resistance and other electrical characteristics of a solar cell, such as maximum power, fill-factor, open circuit voltage and short circuit current – with the aim of developing a model that can spot cell degradation before it has advanced to the point of causing major performance loss or safety issues.

The group worked with multicrystalline silicon solar cells, designing a system that allowed them to place a resistor between the p and n junction of the cell, and thus control its shunt resistance. The experimental setup is described in full in the paper “Experimentally derived models to detect onset of shunt resistance degradation in photovoltaic modules,” published in Energy Reports.

After testing five cells under various combinations of shunt resistance, illumination and other factors, the group found that maximum power, open circuit voltage, and fill factor were all directly affected by changes to the shunt resistance, while short circuit current was not affected. The work shows that once shunt resistance decreased to around 100 ohms per square centimeter, corrective action needs to be taken.

Using the figures from its experiments the group developed models to detect decreasing shunt resistance. “These models can be easily applied to detect the onset of critical PV degradation or failure caused by shunt resistance degradation and are suitable for implementation in online condition monitoring systems,” the group said.

The group also suggests that future work could move towards classifying module degradation based on the calculated shunt resistance loss.

Worldwide, many of the sites that offer the highest solar irradiation also come with the disadvantage of dry, dusty conditions on the ground that can cause various problems for PV system performance.

Dealing with the losses caused by the buildup of dust on the surface of a module is big business for the PV industry, since these losses can quickly to significant amounts of lost revenue. Cleaning modules too frequently or investing in the wrong type of cleaning equipment can also hurt the economics of a project. And so the ability to accurately predict losses from soiling on both long and short term timescales is something that PV project developers and system operators value greatly.

Various approaches exist, employing different combinations of on-site sensors, historical climate data, local weather data, satellite imaging and more. A group of scientists led by the University of Cyprus sought to compare the accuracy of a few of these, by comparing modeled forecasts of soiling loss with data from a test installation at the University of Cyprus campus in Nicosia.

Machine learning

Soiling losses at the test site were calculated by comparing a cleaned and uncleaned module set side by side. Six different models – three using a physical modeling approach and three based on machine learning – were evaluated for accuracy against the site data.

The three “physical” models are well-established methods to model soiling, while the machine learning methods are open-source programs being applied to soiling measurement for the first time. Full details of the models used and how they were evaluated can be found in the paper “Characterizing soiling losses for photovoltaic systems in dry climates: A case study in Cyprus,” published in Solar Energy.

The evaluation showed that the physical models, fed with field observed data, achieved the highest accuracy, with error rates (root mean square error) of 1.16% on daily soiling losses and 0.83% for monthly soiling losses, for the highest performing machine learning model, called CatBoost.

The machine learning approaches, however, were not far behind with 1.55% error in daily soiling losses and 1.18% for monthly. The researchers note that, given shortcomings in the availability of field-observed data covering a whole site over a sufficient period, the machine learning models, based on environmental data gathered by satellite, could also be a useful approach.

“Modelling soiling with this kind of satellite-derived environmental data might help in scheduling O&M strategies and operations along the year to minimize the soiling loss; particularly, in dust and arid regions where sudden changes in the aerosols loading can happen and precipitation is much less frequent,” the researchers explained.

From pv magazine 06/23

Since their beginnings in 2016, the Terawatt Workshops – organized jointly by Germany’s Fraunhofer Institute for Solar Energy Systems (ISE), the US National Renewable Energy Laboratory (NREL), and Japan’s National Institute of Advanced Industrial Science and Technology – have invited figures from the PV sector and research communities around the world to discuss the industry’s future and role within the wider energy system.

The workshops were originally convened to discuss the route to PV reaching 1 TW of installed capacity worldwide – a goal which was achieved in 2022. The group’s scope then widened to examine solar’s role in future energy systems. It arrived at a target estimate, for global annual PV installations, to reach 75 TW by 2050. Participants in the third workshop, held last year, realized that solar is one of the limited number of options to both meet future energy needs and cut greenhouse gas (GHG) emissions. Attendees also agreed that targets and an accurate picture of the role solar needs to play are vital in leading the industry to larger scale.

“A major global risk would be to make poor assumptions or mistakes in modeling and promoting the required PV deployment and industry growth and then realize, by 2035, that we were profoundly wrong on the low side and need to ramp up manufacturing and deployment to unrealistic or unsustainable levels,” explains Nancy Haegel, director of the NREL’s National Center for Photovoltaics.

Haegel and around 50 other industry leaders jointly authored a paper that examines the challenges and requirements for PV to reach 75 TW. The paper, “Photovoltaics at multi-terawatt scale: Waiting is not an option,” was published in “Science.” The authors examined other works on future energy systems, looking for those that best take into account growing trends such as sector coupling and increasing energy consumption in the Global South.

“In most cases, the models are based on photovoltaics generating 60% of the world’s electricity and on wider electrification of the transport and heating sectors,” said Fraunhofer ISE Director Andreas Bett. “Solar is by no means the only source of energy in these scenarios but it is a key one. And this will require a major scaling up of the whole industry.”

Bett said that the next 10 years to 15 years will be critical, as the solar industry enters its terawatt era and sets the foundations for an industry able to supply such a large part of the world’s energy.

“There is some uncertainty of course but this figure of 75 TW is the product of extensive discussions, and we believe it is realistic” says Bett. “An assumption like this enables us to really talk about what is needed in terms of growth rates for efficiency and manufacturing capacity. That is a very important message for the industry and if we were to wait until we know exactly what the number is, it will become even more challenging to reach.”

While the paper outlines the need for a major scale up of solar in the coming years, and conveys this message with some urgency, it also makes it clear that the goals are entirely achievable and that the industry is already on the right track. The past five years to 10 years have seen solar installations and manufacturing capacity grow at a rate of around 25% per year and, if this rate can be maintained, then the goal of 75 TW by 2050 can be reached. “Of course, people say it will be challenging,” says Haegel. “But many don’t realize that solar has already been growing at the required rate. So we tried to lay out this next step: what’s new and challenging about it, but also why it is absolutely achievable.”

Materials and manufacturing

The paper notes PV manufacturing’s rapid adoption of new technology as evidence of its ability to overcome new challenges. Listed achievements include diamond wire sawing, hydrogenation for defect control, and the move to larger wafers. Notably, all were quickly implemented and well managed across the supply chain.

“Since 2010, the PV industry has gone from a somewhat slow-moving and conservative industry, focused on the cost of individual components … to a very dynamic industry that is more focused on levelized cost of electricity,” wrote the authors of the paper. The researchers observe that, most recently, TOPCon [tunnel oxide passivated contact] technology moved from initial industrially-relevant lab designs to mass production in only five years. “Recent analysis shows that it now takes about three years for the average cell efficiency in mass production to reach the efficiency of the champion cell fabricated in the industrial laboratory,” stated the paper.

The researchers conclude that PV’s use of silver is now the main material sustainability issue and the current consumption level of around 15 mg/W needs to be reduced by a factor of three or eliminated entirely. They advise that, as new materials are adopted, care should be taken to avoid similar situations with other scarce materials. “Techniques to address the use of scarce materials should be approached from an ecodesign perspective and analyzed by life-cycle assessment to confirm resulting impacts, evaluating metrics such as resource depletion and GHG emissions,” stated the “Science” paper.

The need for sustainability to be considered throughout the scale-up of solar manufacturing is also a key consideration. “R&D for ecodesign and recycling must be ramped up now to support rapid and sustainable scaling of PV,” wrote the authors. “The PV industry must continuously innovate to improve material sustainability and reduce the embedded carbon and energy required to manufacture and deploy PV.”

Despite the challenge posed by current silver consumption levels, the research has a positive message regarding future material consumption. The scale and efficiency required of the PV industry is achievable with resources available today.

“An important message for policymakers is that there is, in principle, no limitation on the materials side, the resources we need to reach 75 TW are available,” says Haegel. “It is very important that we have no fear. The message here is that yes, we can do it.”

Batteries, other tech

Another message prominent in the work is that solar is not alone and accompanying innovations will be needed in many other industries to achieve the goal of a fully renewable energy system. This means, first of all, comparable scaling in the energy storage, green hydrogen/e-fuels, and wind power industries.

Several industries will also have to update their practices. This includes increasing the acceptance of building-integrated PV; adoption of electrified heating and cooling in the building sector; widespread adoption of electric vehicles – with models to incentivize their charging during times of high PV generation – and closer links with the farming industry, via agrivoltaics. All of these developments are mentioned as strategies that can help solar remain on its path to becoming the world’s primary source of energy.

The paper concludes with the message that the next step is a focus on developing more globalized supply chains at all levels. This, along with other measures, will require support from policymakers around the world to ensure that solar is the first choice for energy expansion and that electricity networks are able to effectively make use of PV-generated electricity.

The paper concluded: “Recent history and the current trajectory suggest that sustained global growth in PV of 25% per year over the next decade, toward 75 TW of installed PV by 2050, can be achieved. Waiting is not an option.”

The PV manufacturing industry’s shift to n-type tunnel oxide passivated contact (TOPCon) cells is well underway, with the previous generation of p-type PERC now expected to disappear from the market over the next few years.

And as more of these n-type productions make their way into commercial PV installations around the world, the industry is keen to see how well they live up to the claims of higher efficiency, better performance, and lower degradation rates that have driven the rapid switch on the manufacturing side.

The National Photovoltaic Quality Inspection Center in China is the latest to publish results illustrating n-type module performance in the field. The center took 20 PV modules – 10 n-type TOPCon and 10 p-type PERC – from Chinese manufacturer JinkoSolar and conducted a test to compare their performance under identical installation conditions.

The modules, all bifacial models consisting of 144 half cells, were first measured in the lab, and then installed on fixed-tilt mounting structures at a 40-degree angle, at a site in Yinchuan, north-western China.

The energy generation of the modules was monitored with a DC meter at 1-minute intervals from September 2022 up until March 2023. Using data from both the lab and outdoor measurements, the group calculated the energy yield per watt for each technology by dividing their cumulative power generation by the average test power times module quantity.

After seven months installed, the results showed that the n-type modules (Group 1 in the chart above) achieved a 3.69% gain in energy yield compared to the PERC products. The modules were also monitored for degradation, going through laboratory characterization tests before and after the seven-month installation period.

These calculations, based on dividing the initial power minus the post-installation power by the initial test power, showed an average annual degradation rate of 0.51% for the TOPCon products, compared with 1.38% for the PERC products.

As solar comes to play a larger role in energy systems the world over, the technology has to learn to cope with harsher terrains and climates, and to operate for longer lifetimes with minimal performance loss as well.

There is a wealth of research into the many different mechanisms that can start to affect the individual components in a solar module when installed outdoors for a long period of time, and the industry has shown that it can rapidly adapt when unexpected problems are discovered.

A group of scientists led by the Eindhoven University of Technology in the Netherlands has conducted an exhaustive review of literature on PV cell and module degradation published over the last 30 years. Their work seeks to provide a detailed guide to the main stress factors faced by PV modules in the field, and a component-by-component guide to the common degradation and failure modes faced by each.

Their guide, Review of degradation and failure phenomena in photovoltaics, is published in full in Renewable and Sustainable Energy Reviews. Among the key findings they take from looking into the existing research this way is that the next step for improving module reliability is to understand the combined effect of multiple stresses over different time periods and develop tests that can take this into account.

“Quality and reliability testing has come to a stage where the durability of each component under a single stress can be predicted well, but accurate reliability estimations for a combination of materials under a combination of time-varying stresses remain challenging,” the group explains. “Building on this knowledge, strategies to improve the operational lifetime of PV systems and thus, to reduce the electricity cost and improve the sustainability can be devised and lifetimes of PV modules can be extended.”

They note efforts by DuPont with its module accelerated sequential testing, the US National Renewable Energy Laboratory’s combined accelerated module testing, and Europe's Solliance’s in-situ degradation method as leading the progress in this area.

“All three combine multiple stress factors such as light, humidity, temperature, rain, mechanical load and voltage stress,” the group states. “It is worth reminding that stress factors and stress levels in the outdoors are uncontrolled and time-varying, while conventional accelerated life testing approaches have a more monotonous character.”

The paper also praises the PV industry and research communities’ quick reactions in developing tests to give advance warning of weakness to degradation mechanisms as they are discovered – such as with potential-induced degradation. And the scientists warn that the full combination of factors must be considered with any new material solar producers plan to take up.

“New materials must work within the whole module package and in concert with the other materials present,” the scientists add. “Agnostic combined stress tests need to be used, so that also unknown, new failure modes related specific designs or BOMS may be triggered during the development phase. Standardization of such agnostic stress tests will be instrumental in the further development of long-lifetime modules and the necessary market acceptance and appreciation of long-lifetime claims.”

Lamination and encapsulant materials play a key role in protecting PV modules’ inner workings from heat, cold, dust, damp and, somewhat ironically, from the light they are built to absorb. Ultraviolet light is a factor in several types of degradation and performance loss observed in the field, and is likely still a problem with the latest cell technologies.

For the encapsulant material itself, yellowing over long periods of exposure to light is a common problem that can cause performance loss by itself, and also reduce the level of protection against other degradation. And this was the focus of a group of scientists led by France's National Solar Energy Institute (INES), a division of the French Alternative Energies and Atomic Energy Commission (CEA), who conducted accelerated testing on modules built with a range of different encapsulation materials.

The group fabricated single-cell modules, using heterojunction solar cells laminated at 160 degrees with five different commercially available PV encapsulant materials – two based on ethylene vinyl acetate (EVA) and three based on polyolefins (POE). These modules were illuminated for 4,200 h, and samples were also tested for up to 1,300 h under ultraviolet radiation and an elevated temperature, to test the effects of UV light alone.

The experiments are described in full in the paper “Solar cell UV-induced degradation or module discolouration: Between the devil and the deep yellow,” published in Progress in Photovoltaics. After testing, the modules were inspected visually and measured for fluorescence and current/voltage performance.

Results showed that the EVA encapsulant was most affected, and two of the POE samples also exhibited minor yellowing. Notably, the three samples that did have yellowing were those that contained additives designed to absorb UV light. After 4,200 h of testing, the EVA module was shown to have lost 4.2% of its initial performance.

The study concludes that UV-absorbing additives tend to degrade, affecting PV module performance over time. However, the researchers note that the protection they provide against other degradation mechanisms would likely still justify their use – as long as the solar cells they are protecting remain vulnerable to UV-induced degradation. “The destruction of UV absorbers is an issue affecting the integrity of the whole PV module and can lead to accelerated delamination, among other critical types of damage,” the researchers explain. “There is then a challenge to find new ways to bolster the photoprotection of the device, especially for the most stringent environments, such as those located in deserts.”

As for solutions to this challenge, they suggest trialing mineral-based rather than organic UV absorber materials, and also note that quantum dots may eventually become an alternate solution, though this is still in earlier stages of research. Finally, they suggest investigating UV-absorbing glass, replacing the need for encapsulant additives.

Making components that can withstand being installed outdoors for years and even decades, in any type of climate, while maintaining at least the vast majority of their initial performance, is a key goal for the solar industry.

There has been plenty of progress, with both technological improvements and competition between manufacturers driving longer product and performance warranties, and therefore longer contracts for the sale of electricity from a solar project. Most manufacturers now offer 30-year warranties guaranteeing at least 80% of the modules’ initial performance, and one has even extended this to 40 years.

But for solar installations many regions are targeting, for 2050 and beyond, even longer lifetimes are needed, especially for installations located in harsh climate regions whether due to heat, cold, moisture, dust or other conditions. And this will mean understanding exactly how PV modules tend to degrade under these conditions.

Scientists led by the University of Agder in Norway decided to focus on degradation caused by moisture – this being a main characteristic of the climate in Grimstad where the university is based.

The group took modules from a decommissioned PV array installed in the town in 2000  and used a range of techniques, both non-destructive and destructive, to examine the inner workings of the modules, and how various components had fared over years in the field.

Their results are described in full in the paper “Moisture induced degradation in field-aged multicrystalline silicon photovoltaic modules,” published in Solar Energy Materials and Solar Cells. The study found moisture ingress had driven degradation of the encapsulant, producing acetic acid and various substances that drive corrosion and other forms of degradation to the silicon cells. Moisture was also found to have a major role in corrosion at solder joints – causing lead to corrosion rather than “sacrificial” tin included in the solder.

The scientists behind the work accepted that PV materials and manufacturing processes have moved on greatly since the modules in this study were manufactured more than 20 years ago. However, while accelerated testing is useful, they say that studying field-aged modules is still necessary, and that many mechanisms revealed in this study are still relevant to modules rolling off production lines today.

“Though solar PV module materials and technology have evolved over the years, MID mechanisms in solar PV modules appear to follow a similar trend,” they state in the paper. “Hence, insights from this work can guide decision making at the present and in the future as regards understanding the performance reliability of solar PV plants.”

Dust, bird droppings and other materials accumulating on the surface of PV modules in the field already amount to billions of dollars each year in lost energy output and added cleaning costs. So understanding how different site and installation conditions affect the build up of dust and droppings on a module surface is valuable knowledge for the PV industry.

A group of scientists led by the Vellore Institute of Technology in Tamil Nadu, India, had this in mind when they came up with a simple yet effective way to study the effects of different types of soiling on PV modules. The scientists gathered samples of five different types of soil (black soil, desert soil, red soil, alluvial soil, laterite soil) as well as coal dust and bird droppings, from various locations in India. The samples, in different amounts ranging from 10g to 50g, were then shaken and brushed onto the surface of PV modules, and the modules were tested using a sun simulator.

The results showed that at all tilt angles, bird droppings had the largest impact on module performance, with the 50g sample taking away more than 80% of the modules’ efficiency – a considerably larger loss than any of the dust or soil samples caused.

The study also found that the physical properties of the soiling material play a larger role than the angle of the modules in deciding the soiling rate. The results are discussed in full in the paper Experimental analysis on the impacts of soil deposition and bird droppings on the thermal performance of photovoltaic panels, published in Case Studies in Thermal Engineering.

The group says that its study will help contribute to a better overall understanding of the effects of soiling on PV modules. This knowledge could help project developers better assess site conditions and avoid locating a project in regions where soiling will be particularly heavy, or ensuring that appropriate mitigation measures can be included from the start.

They note, however, that the results of this study can only be applied to regions with a hot, dry climate similar to Vellore in India on which the simulation conditions were based – Further, climate-specific studies are needed to draw similar conclusions for other climate types.

Scientists have developed an additive and treatment for perovskite solar cells, which alters their chemical structure and reduces the effects of defects and degradation mechanisms. Cells that underwent the treatment achieved initial efficiencies around 24% and maintained 98% of this after 1,000 hours of ‘1 sun’ illumination. Reference cells produced without the treatment had lost 35% of their initial performance after just 200 hours under the same illumination.

The cells also fared well under high temperature testing, retaining 97.6% of initial efficiency after more than 500 h exposed at 60 C. In this test the reference cells lost 27% of initial performance in the same conditions. The treatment and testing of the cells is described in full in the paper “Covalent bonding strategy to enable non-volatile organic cation perovskite for highly stable and efficient solar cells,” published in Joule.

The scientists used various imaging techniques to understand how their treatment worked, concluding that bis diazirine, a polymer material present in the additive, formed covalent bonds with the organic element of the perovskite material. “…the covalent bonding strategy facilitates the ions’ immobilization, inhibits the escape of organic components, and eliminates the metallic Pb. Hence, it reveals enhanced thermal, illumination-resisting, and electrical bias-resisting properties of perovskites.”

Closer inspection

With further characterization, simulations, and comparison to devices built without the treatment, the group was able to observe the covalent bonding strategy in action and confirm its role in reducing various undesirable effects that lead to performance loss in perovskite solar cells, as well as contributing to their initial performance by reducing the appearance of defects. “This work suggests a novel and effective strategy to confine the loss of organic components from perovskites to realize highly efficient and ultra-stable perovskite solar cells.”

The cells in the study were produced using spin-coating – a process commonly used in laboratories, but not suitable for large-scale production. However, a company spun out of Victoria University in Canada, Xlynx Materials, has begun marketing the treatment under the name BondLynx, and is inviting companies working to commercialize perovskite solar cells to collaborate on further projects or to purchase the materials for use in their own trials.

This week sees the publication of the annual ITRPV report, compiled by German engineering association VDMA. Now in its 14^th edition, the report takes an in-depth at technology trends across the supply chain for silicon PV products. VDMA calculates PV module shipments in 2022 at 295 GW, with 258 GW installed and the remainder still in transit or warehoused.

The ITRPV finds that, at the end of 2022, the weighted average spot price for silicon PV modules fell by 7% compared to the previous year, reaching $0.228/W. The report also notes a growing market share for n-type technologies, and that the price premium for these is now marginal – just two tenths of a cent above the average at $0.230/W.

In terms of manufacturing capacity, VDMA finds that around 600 GW was online at the end of last year, with crystalline silicon technologies representing 95% of the market. New factories coming online today usually have at least 2 GW of capacity, and this is expected to increase to 5 GW in the longer term.

Technology trends

Large wafer formats (182mm and 210mm) now represent more than 60% of the market, with formats 166mm and smaller expected to disappear from the market entirely by 2027. VDMA also expects formats larger than 210mm to appear after 2025, representing only a small market share over the next decade. The split between these two large formats is still not clear, but all new production lines will be able to process both.

Monocrystalline silicon now accounts for 97% of production, and the report expects older multicrystalline technologies to disappear entirely in the near future. Gallium doping has also now become mainstream, with the boron doping it replaces also expected to disappear by the end of this year.

PERC (passivated emitter rear contact) remains the leading cell technology for now, amounting to around 70% of the market, but VDMA notes that its replacement with TOPCon (tunnel oxide passivated contact) is now well underway. TOPCon is expected to reach a market share of 60%, heterojunction of 19% and back contact technologies of 5% in 2033, according to the report.

Silver

VDMA’s research found that efforts to reduce silver consumption have proceeded faster than predicted in the 2022 ITRPV, and have now reached an average of 10mg/W. This should fall to 6.5mg over the next decade, despite the growth of n-type technologies that require more silver than PERC. “TOPCon in mass production by Tier 1 manufacturers in China is reported to be, end of 2022, on lower consumption levels 2 to 5 years ahead of our prediction,” states VDMA.

The ITRPV remains conservative about replacing silver entirely, however. It expects copper plating to be introduced in mass production during the next decade, but says this will represent only 7.5% of the market in 2033. “Technical issues related to reliability and adhesion must be resolved before alternative metallization techniques can be introduced,” VDMA states. “Appropriate equipment and processes also need to be made ready for mass production. Silver is expected to remain the most widely used front metallization material for crystalline silicon cells in the years to come.”

From pv magazine Global 05/23

As 2030 and its targets for decarbonization loom, Japan is looking for ways to raise its commitment to renewable energy. For solar, already constrained by a shortage of suitable land to develop new projects, rooftops offer the best opportunity to rapidly build new generation capacity. And now both the central government and regional authorities in Japan are unveiling policies to support the installation of solar on the rooftops of homes and businesses throughout the country.

Japan is targeting a 46% reduction in greenhouse gas emissions by 2030, using 2013 emissions as a baseline. As part of that goal, the country has also set itself the target of having at least 36% to 38% renewables in its energy mix by the same deadline.

Speaking at a conference held during World Smart Energy Week in Tokyo, in March, Kazuya Inoue, director of climate change policy at Japan’s Ministry of Environment, noted that solar – with the shortest lead time of any renewable energy technology – will have the largest role to play in meeting the renewables target. “The Ministry of Environment is committed to solar,” he told the audience in Tokyo, adding that he sees benefits beyond decarbonization, with plans for new solar installations to create jobs and revitalize local economies across Japan.

There is, however, a long way to go to realize all of this. Inoue also noted in his speech that under current plans, meeting the 2030 targets will require a near-doubling of Japan’s total installed PV capacity, which stood just below 70 GW at the end of 2022. The policy director closed his speech by citing a study that showed Japan’s renewable energy potential amounts to 1.8 times expected demand up to 2050, and stated that “much, still, is not being done to exploit this potential.”

Land limitations

With a high feed-in-tariff (FIT) rate, Japan emerged, in the early 2000s, as a leader in solar energy and has since maintained installations of around 5 GW per year.

Today, though, land for these projects is scarce and solar is beginning to come into conflict with agriculture and other industries. In the longer term, combining solar and farmland into agrivoltaics projects should unlock some new sites but these applications are in the early stages, both in technical and regulatory terms, and unlikely to make a major market contribution before 2030. BIPV, tapped by many as a key technology to reduce renewable energy’s land use, is in a similar situation: Products are limited and Japan’s strict building codes and earthquake-safety requirements mean getting any PV product additionally approved for use as a building material will be a lengthy process. Floating PV has also seen some development but regulatory issues, as well as a few high-profile cases of systems being severely damaged by storms, mean this segment also faces teething problems.

That leaves rooftop PV among the most attractive options for further development of renewables in Japan and the government is responding with a series of new subsidies at central and regional level to further incentivize household solar. Central government, through the Ministry of Economy, Trade and Industry (METI), has set an increased FIT rate for rooftop PV installations larger than 10 kW, rising from JPY 10 ($0.075) to JPY 12 from October. Large rooftop installations (with at least 250 kW of generation capacity) have been exempted from the national tendering scheme. “Since appropriate locations for installing PV modules are now on the decline, METI set the offtake prices of commercial rooftop PV systems 20 to 30% higher than those of ground mounted PV systems and aims to enhance companies’ willingness to install commercial rooftop PV systems,” explains Izumi Kaizuka, director of research at Tokyo-based consultancy RTS Corp.

Japan solar feed-in tariffs by system type (JPY)

Further legislation, introduced at the beginning of April, should serve to drive even more commercial PV installations. Revisions to Japan’s Energy Conservation Act now require companies with high energy consumption to regularly report their status and their medium and long-term plans for conversion to non-fossil fuel energy, and places 2030 targets on particular industries requiring reduction of fossil fuel consumption (see table below).

Industry targets for non-fossil fuel energy conversion

Solar mandates

Incentives for new solar installation are also appearing at regional level and are primarily focused on rooftop PV. Since 2020, the city of Kyoto has had requirements in place for new and renovated buildings with a floor space of larger than 2,000 m² to install solar panels. In December 2022, Tokyo took this a step further by extending the requirement to single-family homes and other smaller buildings as well. Also speaking at World Smart Energy Week, Kazumi Arai, system coordination manager for Tokyo Metropolitan Government (TMG) noted that while an estimated 70% of greenhouse gas emissions in Tokyo come from buildings, just 4.24% of the city’s rooftops currently have solar installed. “It’s time to act on climate and energy crises,” he told the audience.

In Tokyo, the new rule will place an obligation on large house builders – those with projects covering more than 20,000 m² per year – to add solar to new houses and other buildings with less than 2,000 m² floor space. These companies (RTS Corp. estimates around 50 businesses will be subject to the rule) will receive a quota based on the number of buildings and the sunshine conditions in each region. New large buildings, in addition, will face an obligation for the building owner to cover at least 5% of the building area with panels.

Having been passed by the Tokyo city government, the law is scheduled to come into force from April 2025, following a “period of support” for homebuilders and other stakeholders. TMG has also recently announced plans to spend JPY 740 billion on a “strong and sustainable Tokyo,” including JPY 150 billion to “promote the installation of renewable energy facilities on new buildings.” Other regions in Japan are widely expected to follow the capital’s lead with similar mandates for rooftop solar over the coming years.

Rooftop market

With these FITs and other subsidies available, as well as rising electricity prices and an attractive power-purchase-agreement business model, new rooftop PV is expected to drive higher installation numbers across Japan. In its “business as usual” scenario, RTS Corp. expects the country’s annual PV installations to reach 8 GW in 2030, while an accelerated scenario could see them go as high as 14 GW.

The companies that supply Japan’s market are preparing for rising rooftop demand, with many offering packaged solutions that include modules, inverter, racking, and often a battery, to simplify the supply process. Michael Zhang, director for Japan at Sungrow, a Chinese inverter and energy storage supplier, says he expects to see a lot of companies taking up PV in the next few years. “Commercial PV is very attractive in Japan at the moment,” he tells pv magazine. “Subsidies are available and it’s easy to get approval for PV and storage as well.”

On the energy storage side, subsidies are available for residential and commercial batteries. RTS Corp says prices will need to fall further for uptake to grow, however. Discussing efforts to subsidize storage to the extent solar reaches cost parity with grid electricity, research director Kaizuka says the Ministry of Environment “and other municipalities, including Tokyo, provide a great amount of subsidy to attain storage parity but the impact is limited so far. It will take a few more years for energy storage to reach parity, since batteries are still expensive and the compatibility needs to be improved further.”

With its latest release, DAH is introducing a module with built in microinverter – which markets are you targeting with this product?

With our full-screen PV module we target rooftop and balcony projects in the residential and commercial segments. And the key regions are Europe and Latin America. We also have sales in China. In terms of sales, we are split roughly 40% Europe, 40% Latin America and 20% China.

Our modules leave the factory already integrated with microinverters, which makes them a very good fit for smaller projects, such as balcony modules that we see more of, particularly in Europe. With no need for an additional inverter, we offer a ‘plug and play’ device, that users can connect very simply to their home circuits and generate power for their own consumption.

The system we supply features one microinverter for every two or three modules. This setup offers advantages in low-light performance and also makes a good fit for larger rooftops, allowing for modules to be installed across multiple pitches and orientations without limiting each other’s performance. This means systems can achieve better rooftop coverage and generation throughout the day.

What other advantages do you see with this AC module design?

Our module and microinverter are designed for each other and supplied preassembled as a single unit, while other AC module systems require assembly, and rely on modules and microinverters from different brands that may not be ideally suited to each other. Our solar unit achieves 97.55% maximum system efficiency, a leading figure in the industry.

It is also a very safe system, with an energy control unit that allows for module-level monitoring and rapid shutdown. Overall, our integrated system achieves a higher return on investment: the system can generate more electricity, and labor and installation costs are significantly reduced.

The full-screen module design also promises to cut down on cleaning costs – what can you tell us about this?

Our unique front frame design, with no raised edge, allows water to freely run off the module. So there is no water left on the module surface and no build up of dust around the edge of the frame. Dust accumulated on the module surface is easily washed away as soon it rains. We have data from installations in the field that shows an energy yield increase of 6-15% thanks to this feature, and it also helps reduce costs associated with cleaning the modules every so often.

The frame design adds around CNY 0.03-0.05 ($0.0043-0.0072) to the module cost per watt, so very well worth it for this level of energy yield increase.

What type of cell does this module use?

Previously we have worked with PERC cells, and now we are completing the upgrade of our 5.5 GW production capacity to work with TOPCon.

We cut the cells into three pieces, this keeps the current low. And this also works well with the microinverter to keep currents low in the whole system, minimizing the temperature increase and related power loss.

How does the cost compare with a traditional module + inverter system?

It’s a little bit more expensive, but much of that can be offset by easier and quicker installation time. For systems up to five kilowatts, the cost is about the same. As systems get larger, the added cost for the microinverter starts to show. However, the accompanying increase in energy yield means we can still be competitive with some larger, commercial-sized installations. And this is why we target the rooftop markets, because we can offer a clear advantage to customers here.

Risen Energy has achieved some very impressive efficiency results with the Hyper-ion series – when will we see these modules on the market?

Right now we are in the pilot phase of production, with a test line up and running. And we expect to begin full-scale commercial production at our base in Jiangsu province in the first half of the year. By the end of the year, we will be producing heterojunction modules at a similar cost to PERC and TOPCon. In production, the highest cell efficiency is above 25.6% and average efficiency is 22.5% for modules.

The first lines in operation will be 5 GW for cells and 10 GW for modules. The second phase will add another 4 GW of cell production and 6 GW for modules, so in total our current plans for heterojunction technology are for 9 GW of cell capacity and 16 GW of module.

Are you committed fully to heterojunction for the future, is Risen evaluating any other cell technologies?

For cell technology, our policy is heterojunction first. This is our first choice and our main focus. However, we will also work with TOPCon.

We see TOPCon as more of a “PERC plus” technology. If you have PERC capacity, you need to upgrade it to TOPCon, otherwise your production lines will soon be useless. We will follow up on TOPCon technology and look to upgrade our PERC lines and keep them operational for a while longer.

Last year we announced an investment in 10 GW of new capacity that will also be TOPCon, and this is more about bringing our capacity for cell production closer to what we have for modules.

As you get to these big production numbers for HJT, the silver content becomes a bit of a problem. Is that something that's on your roadmap to address?

Silver-coated copper is the technology we are working on right now, and we think that will soon become an industry standard used by most companies producing heterojunction cells.

At Risen Energy, we have reduced silver consumption to 9-10 milligrams per watt, when a few of our competitors are still at around 12, and the industry average is 14. So we are already leading in this area, and once we start working with copper-coated silver, we can reduce this again by around 50%.

Heterojunction is also known as one of the simplest technologies to integrate with perovskite and form a tandem cell – is Risen also working on this?

We have established a research and development team focused on this, which is focused on building more knowledge and ability at both the cell and module level for tandem technology. This is still in the research phase, and we are hoping to have some achievements to announce later this year.

But for our R&D team overall, the priority is to reduce the cost of heterojunction production. That will really be our focus for the rest of this year and next. After this, we can look at adding more technology and capabilities, but for now there is still work to do on HJT.

Risen is also active in the energy storage business, how is this developing?

That’s right, we are mostly doing engineering, procurement and construction work for large, utility-scale battery projects. In the United States, I think we are already among the top three suppliers in large-scale energy storage. We are also active in Europe, and starting out in Australia as well. Worldwide, we are around the ninth or tenth largest player in large-scale energy storage projects.

A lot of these are batteries co-located with solar, we try to provide a one-stop shop for developers – PV and storage.

And have you also looked at the manufacturing side of energy storage?

Yes, and we do have a 300 MWh battery factory, this is producing a different technology though, which we usually only sell in Japan.

For us it is more the business of combining battery cells together, and shipping them, to the US for example. Similar to the PV module business.