PV Pointers: Silicon heterojunction solar cell technology moves beyond the lab

There’s been lots of buzz about silicon heterojunction [SHJ] solar cells and rightly so. SHJ is one of the more promising solar panel technologies to come along in some time due to its proven ability to improve conversion efficiency. In addition, panels employing SHJ cells have been able to improve overall temperature coefficient power output — to as low as 0.258 percent — helping to solve a problem that has caused more than a few solar panels to sputter on especially hot days.

How we got here

PanasonicThe history of SHJ goes back to 1980 in a lab at Sanyo Electric (now Panasonic). Sanyo engineered the world’s first amorphous silicon solar cells but given their low conversion efficiency — less than 10 percent — practical applications were limited. In the late 1980s, Sanyo continued to tinker, eventually developing solar cells with laminated amorphous silicon and thin-film polysilicon. Bucking the prevailing wisdom of the day, the amorphous silicon was used only as a conductive passivation material rather than as an electricity-generating layer. The result was greatly improved junction characteristics, and the SHJ solar cell was born. Sanyo researchers presented their findings at the Fifth Photovoltaic Conference in Kyoto, an international gathering of the photovoltaic research community, and excitement quickly spread. Ensuing milestones include the attainment of 20 percent efficiency in 1994 followed by the 1997 rollout of the world’s first commercially-marketed heterojunction solar cell. Since then, SHJ has seen continued improvement with the technology underpinning current records for conversion efficiency and reduced degradation rates.

Why are SHJ cells superior?

Let’s start with base materials. SHJ solar cells are made using a combination of amorphous silicon layers and monocrystalline silicon wafers, a material less prone to degradation under prolonged, intense light exposure. This unique construction lets the solar cell produce electricity at both the front and rear of the cell. Further, the use of multiple materials allows for the insertion of wider bandgaps, which lets the cell respond to multiple light wavelengths. The net result is superior conversion and the ability to maintain near-peak efficiency at higher temperatures.

Given the proven benefits of silicon heterojunction technology, why are some manufacturers sticking with older, more conventional technologies that use amorphous silicon only? While the benefits of SHJ have become widely accepted, high production costs have remained a stumbling block. But with recent advances in the metallization process that leverages SHJ’s ability to be processed at lower temperatures than amorphous silicon cells, SHJ may finally be moving into the mainstream. While SHJ panels still demand higher upfront costs than non-SHJ counterparts, higher conversion efficiencies, guaranteed performance metrics and longer warranties — up to 25 years from some manufacturers — have shortened the payback window enough to win over consumers who see the wisdom in committing to solar energy for the long haul.

Mukesh Sethi is group manager, residential solar team, at Panasonic.

— Solar Builder magazine

Keep Watch: How the PV monitoring landscape is evolving

Cloud Computing

Monitoring systems have become an integral and ubiquitous component to any well-functioning PV project for years now. As the industry has matured, monitoring ecosystems have evolved from OEM-provided, HMI-style interfaces reminiscent of traditional Supervisory Control and Data Acquisition (SCADA) systems to modern web apps slinging the latest tech buzzwords.

However, much of the innovation in PV monitoring has been on the software side, with the data collection skeleton remaining largely unchanged. While many of the monitoring software platforms offered to the market have had numerous facelifts and new feature bundles released, the industry as a whole has not successfully utilized many of the new data collection (e.g. low-cost wireless sensors) and analysis techniques (e.g. machine learning) that have gained significant traction in other industries. This lack of true innovation has contributed to a negative perception of monitoring companies throughout the industry.


Solutions for monitoring PV systems sit on a spectrum. At one end, corresponding to low-cost and low-touch, is equipment-direct monitoring. Most inverter manufacturers and an increasing number of combiner box and meter manufacturers offer integrated monitoring platforms that consist of a web portal where equipment data is displayed. This is usually provided free of (additional) charge by the OEM, and may have basic features such as alarming, visualization and reporting.

The downside here is monitoring is not the primary goal of the manufacturer. Given the choice between spending a development budget on a better inverter or a top-tier inverter monitoring platform, the inverter manufacturer will usually work on their core technology. The burden to the end user when using these equipment-direct monitoring platforms can be significant. For example, it’s not unheard of to have multiple makes of inverters or combiner boxes at a single site, and it’s nearly impossible to find an operator who is responsible for a fleet of assets that use a single manufacturer. Having to log in to multiple platforms can quickly become unwieldy and does not scale well.


On the opposite end of the spectrum from equipment-direct monitoring is a fully custom-built SCADA system. These systems are tailored to a particular plant (a single SCADA system is rarely used to monitor and control multiple plants), and the implementation for a given system is not repeatable for another system.

The combination of equipment required for a SCADA system is unique to a given plant, and the configuration and software to interface with the equipment is custom developed for each implementation. This often results in high costs due to the non-repeatability of the solution. Support for these systems can be limited as the business model is based on one-time integration and setup fees. But many SCADA integrators have years of proven success, and, while not unheard of, it’s rare that significant bugs exist in the delivered solution. The commissioning of a SCADA system is usually robust and thorough, which will catch any configuration errors in the process.

Depending on the size and locality of the PV project, SCADA may be required to allow a third-party (the local utility or reigning RTO, for instance) control over the equipment on site. There may be regulatory requirements to allow these third parties to send commands to the site, ordering inverters to lower their output, increase reactive power, or turn off should the grid require additional stability.

How to optimize performance and profit through O&M monitoring

Cloud-based Remote Monitoring

The space between a low-cost, low-touch, manufacturer-based monitoring system and a high-cost, high-touch SCADA system is inhabited by third-party remote monitoring systems. These are generally software-as-a-service products usually hosted in the cloud. Cloud-based remote monitoring has quite a few advantages over equipment-direct monitoring.

For one, it allows a single operator to monitor and respond to many projects concurrently. Another advantage is that providing monitoring solutions is the primary objective of these companies. If a monitoring company provides a subpar product, there’s little chance for success or repeat business.

There are advantages over traditional SCADA systems as well. Since the cost of development is spread across many customers, they are usually lower cost than SCADA, and many modern systems are now able to offer the same level of control that a SCADA system would.

Cloud-remote monitoring systems are also more flexible, updated more often, and are scalable across fleets of projects. There are concerns about security, however, which in many applications is of paramount importance. Few offtakers are comfortable with cloud-based control systems due to the perceived vulnerability from hackers. Many utilities have a mindset that is distrustful of unproven innovation, and are less likely to accept a solution that has not been proven for years or even decades.

Traditional Monitoring Challenges

In addition to the challenges each technology faces, there is a physical consideration as well. The majority of traditional solutions require hardwired connections to collect and transport data to either the point of consumption or a data backhaul. This adds additional cost to purchase the wires over which the data will be transmitted and adds in an additional possible breakpoint. The main barrier to adopting wireless communication networks has been reliability and security.

Another weakness of these traditional monitoring and management systems is the methods by which data is transferred. Most traditional monitoring systems use communications protocols that were intended for humans to communicate to one another via devices. Extraneous metadata is often included in these

data transfers, which inflates the size of the messages and thus the bandwidth requirements per datapoint sent. By moving to a machine-to-machine protocol, better efficiency can be achieved in data transfer, which helps to reduce operational costs of data collection. It can also assist in reducing latency of data and commands, which leads to a more responsive and safer site.

Modern Monitoring

All of those concerns have been major drivers of the adoption of Internet of Things (IoT) technologies across other industries. These lessons can be translated to the PV industry. Optimizing data transfer for PV plants is not a simple task though. Bandwidth requirements vary from project to project. If string data is being captured at a particular site, the amount of data being transferred can be orders of magnitude larger than a site where only inverters and meters are being monitored; if panel-level data is available (from microinverters, DC optimizers or other MLPEs), the amount of data can be orders of magnitude larger yet. To ameliorate these issues, many IoT platform providers utilize modern machine-to-machine communications protocols like MQTT that help to reduce the size of data packets allowing for more data to be sent over the same bandwidth.

Further complicating data transfer is both the location and the topology of the project. Many large-scale PV projects are located in remote areas, which may not have readily accessible ISP coverage or cell service. Local communications interference can also be a problem, whether this interference stems from electrical sources, such as the feedback coming from the inverters, or physical sources, such as being blocked by panels.

These concerns can be alleviated by using a combination of technologies within a single plant’s network topology. Such technologies can include WiFi, cellular 2G/3G/4G, Zigbee mesh networks, and even low power WAN technology such as LoRa. However, this concept contrasts with traditional monitoring providers, who generally only use a single communications technology across all of their customers regardless of plant topology and location; since these solutions are nontrivial to implement, it’s often only cost effective for these providers to choose the most applicable communications technique and stick to it.

IoT-based Solutions

Applying IoT concepts to PV monitoring can help alleviate some of the challenges that stem from traditional monitoring applications. Most IoT platforms give users the ability to deploy logic to edge devices — the inverters, meters and other equipment located on site. Granted, this isn’t a new development as many monitoring and SCADA providers are already deploying intelligence to the devices in the field, but in an IoT environment, rather than utilizing expensive dataloggers or industrial computers, edge intelligence can be provided via an inexpensive Raspberry Pi, Arduino, or similar small computing device.

Moving diagnostics to the edge provides additional benefits when used in conjunction with an IoT-based monitoring application. For instance, there are a subset of faults that will always require a site to be disconnected from the grid. By moving to an IoT-based solution using lower-cost edge computer hardware, the latency between fault occurrence and shutdown can be reduced relative to that achieved with a high-cost SCADA system. When edge computing is coupled with machine-learning and cloud-based analytics, PV monitoring systems can become more autonomous, allowing not only automated investigation to the root cause and failure area of fault events, but actions such as technician dispatch or site-level disconnect.

The trend of monitoring system evolution over the past 10 years has been to bring prices down, resulting in a commoditized solution that favors innovations in flashy software features rather than a rethinking of the framework around which a monitoring system is built. By looking to emerging technologies, monitoring providers can challenge these assumptions yielding a lower-cost yet higher-functioning monitoring solution. Such an evolutionary step is now coming to the market in the form of IoT-based solutions, which will enable better efficiencies and lower operational costs in monitoring and managing a PV project.

Beau Blumberg is solution director swiftPV, infiswift.

— Solar Builder magazine

This non-traditional solar site drainage solution could save you thousands


HydroBlox transports water from high head pressure to low head pressure, creating a path of least resistance.

Installing or building the perfect site requires planning beyond the system itself. In ground-mount applications, for example, field drainage is an underrated attribute.

Drainage Explained

Typically, the energy dissipation methods on a solar site are aggregate, fabric cloth and perforated pipe. This requires excavation and removal of excess soil as well as the logistics and expense of supplying the aggregate to a remote and often difficult-to-access location. The maintenance requirements are time intensive and expensive.

These traditional drainage systems have a lifespan of one to seven years with most failures occurring in year three. These systems fail because of the migration of fines and silt — small particles that are suspended in the water. Often, you have a pipe that is surrounded by aggregate and a geotextile. As the aggregate or gravel settles and compresses over time, movement of the surrounding soil and fines increases. When the soil and fines migrate, the geotextile and pipe fill with these fines and become impacted.

A Better Way

Instead of going that traditional route, HydroBlox, a drainage and filter product made from 100 percent recycled plastic, is the first geotextile that conveys fluid.

HydroBlox has a compressive strength of 40,000 lbs per ft and an irregular patterned composition with an internal void space of 50 percent, referred to as a permavoid. The pressure in this void space is naturally lower and will remain that way due to the non-compressive nature of the HydroBlox. During natural settling, the plank of HydroBlox will not compress and therefore does not become impacted and clogged.

Also, HydroBlox transports water from high head pressure to low head pressure, creating a path of least resistance. The water then moves through the irregular void path of the HydroBlox plank, with the surrounding soil acting like a filter. This way, water will continuously pass through. In fact, this method moves water over ten times faster than sand.

“This is called the Tergazhi effect. The water movement is based on Darcy’s principle,” says Ed Grieser, owner of HydroBlox. “The working example that seems to resonate with everyone is when standing at the ocean’s edge at the beach, recall how quickly the water travels back into the sand when the wave recedes.”

Lee Supply is the exclusive distributor of HydroBlox with stock at all of their locations.


The installation method is very straightforward. Simply trench 2 in. wide and 7 in. deep. The trench should be 18-ft to 24-ft down the slope from the drip line. This will allow for 2 in. of HydroBlox to remain above grade. The downhill side is backfilled by the trenched material.

Alongside the potential O&M savings, Fancher says HydroBlox installation costs approximately one-quarter of existing methods.

“The costs associated with traditional systems are approximately $26.50 per foot,” he said. “The perforated pipe which is often compared to the price of HydroBlox is the least expensive component of the standard system. In reality, the true cost is much greater than HydroBlox because of the labor and equipment required. The installation costs for HydroBlox is approximately $1 per foot.”

Each foot of installed HydroBlox could net a savings of $19.50. On a 25-acre solar field site, the costs of installation are reduced by $780,000.

Also, heavy equipment and large vehicles are not necessary for maintenance. This allows for the solar panels to be placed closer together than would otherwise be possible. The maintenance for HydroBlox is simply keeping the rocks and debris clear on the uphill side of HydroBlox and the drainage swale that carries the water to the retention pond clear.

Product to Watch: NRG Systems’ Soiling Measurement Kit

NRG Systems’ Soiling Measurement Kit Photovoltaic modules often collect more than sunlight after they are installed. Depending on the siting location, particles ranging from dust to snow can accumulate on a PV module’s surface, reducing its performance and ultimately leading to significant power losses. This buildup — commonly referred to as soiling — can be compounded by such weather parameters as wind speed, relative humidity and ambient temperature, as well as localized activities near or around the PV plant.

To address and ideally avoid power losses caused by soiling, the new IEC 61724-1:2017 standard for PV system performance monitoring suggests that operators of utility-scale and large PV projects measure soiling ratio, which is defined as the ratio of the actual power/current output of a PV array under given soiling conditions to the power/current that would be expected if the PV array were clean and free of soiling. By measuring soiling ratio, operators are armed with the vital information needed to make practical decisions, like scheduling solar panel cleanings, that can better optimize the performance of their PV plant.

NRG Systems recently introduced a Soiling Measurement Kit specially designed to help PV developers and operators obtain the information needed to quantify the site-specific impacts of soiling on prospective and current PV projects. The turnkey solution is offered as an accessory to the company’s Solar Resource Assessment System and comes with three PV modules (one for data logger power, one clean panel and one dirty panel), pre-installed back-of-module temperature sensors, flexible mounting hardware and an integrated soiling interface module.

The Soiling Measurement Kit connects with NRG Systems’ SymphoniePRO Data Logger and provides a wealth of raw soiling measurement data that can be used to determine soiling ratio.

Specifically, the kit measures short circuit current and back-of-module temperature with the user’s choice of statistical interval as well as optional 1 Hz sample data collection, providing flexible analysis options to meet data demands. Generally, solar module performance decreases with increasing temperature, so back-of-module temperature measurements provide the critical information needed to accurately predict a PV plant’s power output.

— Solar Builder magazine

Eye in the Sky: How Momentum Solar doubled its business with aerial imaging software

Eye IllustrationWith the help of emerging technologies, the installation and maintenance of solar power sources is both easier and more cost effective than ever before. As a result, more and more homes and businesses will be looking to reap the benefits of this renewable resource, which makes high-resolution, aerial imagery a solar professional’s best friend.

Prospect Remotely

Sending technicians onto the roof to measure for estimates can be costly and time consuming, from safety and insurance to lost opportunity. On-site evaluations can cost a company up to $300 per assessment. That specialty solar technician can assess up to five roofs per day, so it’s easy to see how costs add up while those operating remotely with precise aerial imagery can complete a virtual site assessment in mere minutes. Solar professionals prospecting for new business with high-resolution aerial imagery also save significant time and money on travel and labor costs.

Momentum Solar of Metuchen, N.J., used Nearmap aerial imagery to qualify properties without having to leave the office, which changed the trajectory of the company.

“We are growing at such a rapid rate,” said James Kennedy, Momentum’s program manager for sales proposal development. “High-resolution imagery is the perfect solution to accommodate that growth. We have increased our weekly qualifications from 2,000 up to 3,000 to 5,000 on average. We’ve also reduced the turnaround time on qualifications by nearly two weeks.”

Momentum can now pre-design a newly constructed home’s array instead of needing to do a site assessment before proposing the project. This technology allows Momentum the opportunity to earn the business before they would have previously even quoted the project.

Design with Precision

Laying out a design for a solar array is a precise and delicate science. Technicians need to know exact measurements, dimensions and optimum placement to ensure an accurate, yet efficient, amount of power is created.

High-resolution imagery takes all the guesswork out of solar installation with 2.8-in. clarity and highly accurate virtual measuring tools. With many applications integrated with this imagery, solar installers can place virtual solar panels atop customer rooftops, mitigating unnecessary risk and reducing travel time and labor costs.
For Momentum Solar, using high-resolution imagery reduces rework/resubmissions on proposals, lowers cancellation rates and ensures the best possible customer experience. In addition, installers can measure expected energy output and shaded areas without actually being there.

“Because we can accurately assess properties pre-sale, we go into the proposal with definite solutions and more confidence. Clients enjoy seeing what the end product will look like through panels virtually placed on the aerial images,” Kennedy said.

arial view of residential solar

Cut Software Overhead

It’s important to have your plans and information on the fly these days. Whether you’re working on a project remotely or are out in the field with the technicians, having digitized, up-to-the-minute schematics on any given project is a must. Add in the speed and simplicity of cloud delivery and you get instantaneous access without the complexity.

“Before using high-resolution imagery, the qualification and assessment process required toggling between three different satellite imagery programs and then a fourth program for panel layout,” Kennedy said. “Now, all the necessary information is in one easy-to-use program. We can decide if the property is suitable for solar within two to three minutes. The high-resolution images reveal roof space, shading and any obstructions so we can make accurate, timely assessments.”

Tony Agresta is the VP of marketing for Nearmap.

— Solar Builder magazine

How one PV module manufacturer wants to meet the needs of homeowners

Solaria uses a direct contact between cells

Solaria uses a direct contact between cells to reduce power loss as well as achieve an all-black look.

For all of the intrinsic value of solar, selling it on a wide-scale to homeowners might depend more on stuff like emotional appeal and aesthetics. This is driving the influx of black PV panels coming onto the market. LG’s NeON series comes in black. Panasonic just released all-black versions of its popular HIT panels (as we noted last issue). And so on.

A new entrant into this space is Solaria, a technology company that has been developing its technology over the last decade to commercialize a breakthrough product for the industry. As Chinese panels continued to drive down prices in utility-scale projects, that market became less of a focus.

Looking at the market, Solaria CEO Suvi Sharma thinks residential installs are the next big opportunity for high-efficiency, aesthetically pleasing panels that have residential applications in mind from the start.
“If you look at the Chinese model of panels where you basically make two different sizes that you stuff into different channels, that worked when the market was small, but now the market deserves its own product and focus.”

Solaria took its core technology – solar cell cutting, handling assembly and automation and configured a module and design to do two things:

“Produce significantly more power than a standard solar panel using the same bill of materials and, just as importantly, provide a much better looking panel,” he says. “With the industry maturing, those attributes will become more important. We want to break through from the early adopters in the mass market.”

Right now, Solaria’s residential solar capacity is still on the smaller side. Between its line in Fremont, Calif., and its line in South Korea, Solaria is working on adding additional capacity to meet growing demand.

Inside the Design

Conveniently, Solaria’s strategy for designing an efficient panel naturally created a sleek-looking product. The Solaria formula in a nutshell is to cut solar cells (mono PERC) into five strips and then overlap each of them instead of interconnecting them with traditional ribbon wire. The cell architecture of a traditional module leaves dead space between each cell, whereas this overlapping structure creates a uniform, continuous string of strips as well as the aesthetic bonus of covering up the typically visible busbars.

“All of the active areas of a cell are exposed. Busbars on a typical module shade about 3 to 4 percent of the module and cell, so we eliminate that through the overlap mechanism,” he says. “By creating a direct contact between one cell and another, we get better electrical performance because we don’t have the traditional losses associated with ribbon wires.”

Why high-efficiency modules are the best value for installers, homeowners

Part of the value from increasing system efficiency within the module architecture itself — and wiring in a combination of parallel and series — is also reducing the need for efficiency-boosting or shade-mitigating MLPEs. You may still want to incorporate optimizers in certain applications, but the need is reduced.

Add all of that up, Sharma says a Solaria panel (60-cell, 330 Wp) should be expected to produce 15 to 20 percent higher power than conventional panels using the same cells and materials to pair with that all-black appearance. The price point for Solaria is higher than a conventional Chinese panel, but priced below a high-efficiency SunPower back-contact panel.

Looking Ahead

Beyond improved aesthetics, simplicity is another big factor in the residential market. For that reason, Sharma wants to put Solaria on the path toward smart AC modules.

“How does solar become truly mainstream? The installation of the system needs to be simplified more and more. Plus, it’s a complex sell. The broader we can make the installer base, where more electricians get into it, the bigger it’s going to grow. We want to simplify the installation and that’s where we see the opportunity for integrated AC modules.”

Be on the lookout for more news on that front from Solaria as it tests out concepts with various microinverter manufacturers until it feels comfortable enough to offer an integrated product and stand behind the warranty.

Why Mono PERC?

Key to Solaria’s solution is the mono PERC cell. CEO Suvi Sharma explains his reasoning behind that choice.

“You typically get about 1 percent absolute improved power today from a standard mono cell, but the roadmap to improve that power is better with mono PERC,” Suvi says. “There are more dials to play with in terms of efficiency. Not only does mono PERC have higher power than a traditional mono cell, but the difference is going to grow over time. Could become 2 percent absolute over the next 18 months.”

“One issue with PERC is its light-induced degradation [LID]. The PERC manufacturers have worked on that a lot over the last 18 months. The LID is similar to mono cells now. Sometimes in multi PERC there tends to be more LID.”

“Mono PERC is growing in market share because it’s an add-on. If you already have an investment in a mono cell line, you can leverage it for mono PERC as opposed to new cell contents like heterojunction and bifacial, which require a fundamentally new investment in equipment. We believe that within three years probably, all mono cell capacity is going to be converted to mono PERC.”

— Solar Builder magazine