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March 2nd, 2012 at 5:00 pm

 

 

 In this article we will thoroughly investigate PV module Spec Sheets or known also as “cut sheets”. Since there are literally thousands of modules available on the market it is necessary to know how to use that information most efficiently. Let’s start with most obvious features of the cut sheet, the mechanical aspects of the module.

 

Dimensions
Will be given in millimeters and inches, which also determines the surface area – it gives installers an idea how the modules should be fit on the roof, ground - or pole – mount installations. After layout is determined, the space between modules has to accommodate for mid clamps and end clamps, usually one inch apart for each clamp. The area of the module is crucial to determine weight load or to calculate wind forces acting on the modules and structure they are attached to. Thickness of the module will determine type of clamps installer is going to use. Quite often mid clamps differ only with the bolt length, whereas end clamp are shorter or longer depending on module thickness. Weight is also listed on most specification, since there is always a limit it can be added to the roof structure. Point to remember: many permitting authorities will accept PV modules to be mounted on pitched roofs without professionally engineered design, so long as there is only one layer of existing roofing material present.
There are different types of solar cells: mono-crystalline, poly-crystalline or thin film. There are variable numbers of cells per module from 36 to 108 but most common are 60 and 72 cell modules. Most PV modules cells operate near 0.5V and quite often they are connected in one string in series, yielding 36V per module so called Vmpp at max imum power output. However, other connections like 2 stirings of 36 cells will yield around Vmpp = 18V per module. Surface area of the cell will determine current output, Impp.
Most if not all solar modules have a plastic back sheet that seals the cells against environment. Its material is usually white but some modules come with black back sheet to match customer esthetic needs. It has to be handled with care since it is fragile underbelly of the module. To protect crystalline cells and simultaneously provide transparent surface modules use low-iron, high-transparency
tempered glass with an antireflection surface treatment. Low iron glass has high clarity, and tempered glass shatters into small fragments, instead of sharp shards, if broken. Modules are strenuously tested for weight loading and impact resistance, and the front glazing of a module is extremely durable. Thin-film modules may use a polymer film (plastic) as the front sheet, which is designed for arrays in high-impact environments.
 
            The module lead’s connector type is important. Often called “quick-connects,” many new products are on the market. The old standard—Multi-Contact (MC) 4—has been joined by Tyco, Radox, Amphenol, and others. The 2011 NEC mandates that these connectors be touch-safe and, for circuits greater than 30 volts, require a tool for opening. Most of these connectors are not cross-compatible, so mixing modules will require properly mating connectors.  Factory-installed module leads will be listed in the spec sheet with wire size, insulation type, and length of the leads (positive and negative leads are not always the same length). Wire diameter generally ranges from 14 AWG to 10 AWG; or they may be listed in square millimeters (mm2).
Bypass Diodes
Shading a small part of a PV module can have a disproportionally large effect on its output. Additionally, when a module is partially or completely shaded, the current flowing through the module can reverse direction and create hot spots, which can lead to deterioration of the cell, the internal connections, and the module back sheet. A bypass diode stops the reverse flow of current and also directs electrical flow around the shaded section of the module. Nearly all modules come with factory-installed bypass diodes, with the exception of some thin-film modules. A typical 72-cell module with all the cells in series will have three bypass diodes, each bridging a series of 24 cells that can be bypassed if any or all of those cells are shaded.
 
I-V Curve
Standard test conditions (STC) are the conditions under which a manufacturer tests modules: 1,000 W per m2 irradiance, 25°C (77°F) cell temperature, and 1.5 air mass index. Real-world operating cell temperature is often 20 to 40ºC above the ambient temperature. STC (bright sun and a relatively low cell temperature) are not typical for field operation of modules, but they do provide a
consistent standardized reference to compare modules. An I-V curve (current-voltage) curve is generated at STC for every cell and module manufactured. The I-V curve contains five significant data points (Pmax, Vmp, Voc, Imp, and Isc; discussed below), which are used for system design, troubleshooting, and module comparisons. I-V curves can also be diagrammed for any operating temperature and irradiance level, but the points listed on a module specification sheet and those printed on the back of the module are at STC unless otherwise stated. Peak Power (Pmax or Pmp)
The specified maximum wattage of a module, the maximum power point (Pmax), sits at the “knee” of the I-V curve, and represents the product of the maximum power voltage (Vmp) and the maximum
power current (Imp). This wattage is produced only under a very specific set of operating conditions, and real environmental conditions (changing irradiance and cell temperature)
will alter a module’s Pmax.
Vmp
At STC and tested under load, voltage at max power (Vmp) is the highest operating voltage a module will produce. Vmp, adjusted for highest operating cell temperature, is used to calculate the
minimum number of modules in series.
 
Voc
Open-circuit voltage (Voc) occurs when the module is not
connected to a load. No current can flow in an open circuit and, as a result, Voc occurs at the point on the I-V curve where current is zero, and voltage is at its highest (Note: the module produces no
power under open-circuit conditions.) Voc is used to calculate the maximum number of modules in a
series string. Because voltage rises as the temperature drops, calculations are performed for the coldest expected operating conditions. This ensures that NEC parameters and equipment
voltage limitations are not exceeded.
 
Imp
At STC, and tested under load, the maximum power current (Imp) is the highest amperage a module can produce. Imp is used in voltage drop calculations when determining wire gauge for PV circuits. This is a design consideration rather than an NEC ampacity calculation, for minimizing voltage drop and maximizing array output.
Isc
Short-circuit current (Isc) is the maximum amperage that the module can produce. There is no voltage when a module is shortcircuited, and thus no power. Isc is the measurement used to size conductors and overcurrent protection, with safety factors as required by the NEC.
 
NOCT
Frequently, nominal operating cell temperature (NOCT) specifications are also listed on a manufacturer’s sheet. These are measurements calculated at different conditions than STC, using
a lower sunlight intensity (800 W per m2); an ambient (not cell) temperature of 20ºC; and a wind speed of 1 meter per second; with the module tilted at 45°. The NOCT value itself is the cell
temperature—given in degrees Celsius—reached under these conditions, Compared to the STC 25ºC cell temperature, the NOCT value will always be higher, usually by about 20ºC. NOCT values are used to mathematically calculate other test condition data points without resorting to further laboratory tests. NOCT conditions tend to more closely resemble the field conditions PV arrays generally operate in, and so give a perspective on “realworld” module operation.
 
Power Tolerance
Power tolerance is the range within which a module manufacturer is stating the module can deviate from its STC-rated Pmax, and thus what the manufacturer warranty covers. Common values are +/-
5%, -0%/+5, and up to +/-10%. A 200-watt module with a +/-5% power tolerance could produce a measured output of 190 to 210W. Finding modules with a -0% power tolerance can ensure the
best value per dollar spent, and keep arrays operating at closer to predicted output. Module Efficiency & Cell Efficiency Efficiency is the measure of electrical power output divided by solar input. At STC, power in is equal to 1,000 W per m2 and power out is the rated Pmax point. Assuming a module sized at exactly 1 square meter, and rated at 150 W Pmax, module efficiency would be 150 W per m2 ÷ 1,000 W per m2, which equals 15%. The typical crystalline efficiency range spans 12% to 15%, but there are high-efficiency modules over 19%, and amorphous silicon modules on the low end with efficiencies around 6% or 7%. Cell efficiencies will be slightly higher than module efficiencies because there is usually a small amount of empty space between cells. When deciding what module to purchase, if W per square
meter (known as power density) is the driving factor, then a module with high efficiency should be chosen. But in many instances, there is plenty of room for an array and price per watt will be given higher priority than module efficiency. Temperature Coefficients Modules are directly affected by both irradiance and temperature, and because of environmental fluctuations, also experience power output fluctuations. When exposed to full sun, the cells will reach temperatures above the STC temperature of 25°C. And sometimes cell temperatures are lower than 25°C, such as on cold winter days.
Temperature coefficients are used to mathematically determine the power, current, or voltage a module will produce at various temperatures deviating from the STC values. The temperature coefficient of open-circuit voltage is used to figure out the PV array’s maximum system voltage at a site’s lowest expected temperatures. The temperature coefficient of power can be used along with pyranometer-measured irradiance to calculate the power an array should be producing, which can be compared to actual output to verify proper performance.
 
Warranty
A limited warranty for module power output based on the minimum peak power rating (STC rating minus power tolerance percentage) means that the manufacturer guarantees the module will provide
at least a certain level of power for the specified period of time. Many warranties are stepped—covering a percentage of minimum peak power output within two different time frames. For example,
a common warranty guarantees that the module will produce 90% of its rated power for the first 10 years and 80% for the next 10 years. A 200 W module with a power tolerance of +/-5% means that
the module should produce at least 171 W (200 W × 0.95 power tolerance × 0.9) under STC for the first 10 years. For the next 10 years, the module should produce at least 152 W (100 W × 0.95
power tolerance × 0.8). Module replacements are frequently done at a prorated value according to how long the module has been in the field. More manufacturers are now offering linear power warranties,
which are represented by a maximum percentage power decrease per year for a set number of years, for example, that module power output shall not decrease by more than approximately 0.7% per year
after the initial year of service, for the first 25 years.
 
At the end module specs are designed to help customers choose the appropriate product for their installations. The most important factors when choosing solar modules should not only the price per watt but the craftsmanship, efficiency and warranties. However, no matter how appealing a module is, it’s crucial how many years the producer was has been on the market and if the company is in good economic and financial standing. Some questions to ask: what are the warranties good for (what does it cover)? Is there an insurance company to backstop the company in case they go under? Do they have a linear warranty? How many years workmanship?
While quality of solar cells is crucial, the quality of connectors (quick connects) and wiring for instance cannot be underestimated since they also have influence on safety and efficiency of the whole system.
Unnecessary repairs due to poor quality of these components might cause unexpected and frustrating delays in power production. From an installers point of view, specs provide crucial information on how to connect modules to the inverter and how to design electrical layouts. Moreover, test conditions under which solar cells were tested are quite often misunderstood.   STC testing conditions, while idealistic and rarely fulfilled in the real life conditions provide common ground for testing all solar modules, so different manufacturers can be compared to the same point of reference. To conclude, understanding and getting as much useful information from the specifications will result in better design and overall success of the whole installation. The next article we will discuss the "ins and outs" of micro inverters and power optimizers.
November 16th, 2011 at 11:33 am

 

New innovations and technologies will be necessary for solar PV-based energy to flourish and attract even more diverse implementations.  Based on print and internet research, solar manufacturing is indeed entering a very important transition in its way to lower real overall costs of solar celsl and in turn the solar modules.  True, module pricing has been declining rapidly but this has been based on declining revenues and over capacity in the global solar crystalline space rather than cost reducing innovations.
One of the keys to increasing competitiveness is to draw down the costs of production. The U.S. Energy Information Administration recently concluded that the ‘cost of generation’ (in US$/MWh) of solar PV will make it 2 times as expensive as wind, more than 3 times as expensive as nuclear, and slightly less than 4 times as expensive as conventional coal by 2016.
Taking into account only the solar cell itself, there are two main ways to lower the cost of energy generation: 1) make more efficient solar cells, or 2) lower the costs to produce them. As silicon is the largest cost in conventional solar cell production, (making up 50%-60% of the overall cost), it is pivotal that costs associated with its use be lowered.  Currently, solar cell wafers must be thick enough to survive the direct contact metallization processes. Industry standard solar cell manufacturing processes use screen printing equipment which directly contacts the wafer and can exert enough force to cause breakage for thin wafers. If metallization could be done without touching the wafer, it would allow for silicon solar cell wafers to be much thinner than they are today, which could reduce the overall costs of the device.
Applied Nanotech is pioneer in so called non-contact print techniques, where processes like inkjet, aerosol jet, and spray coating offers several important advantages over traditional manufacturing approaches. These techniques provide a route to realize thin-sillicon wafer, which directly transforms to lower module costs. Implementation of this technology is a good 2 to 3 years away. Let’s see if it makes it into a solar cell near you….
November 1st, 2011 at 3:42 pm

                  All contemporary modules utilize silver as a conductor in manufacturing solar cells. It is less resistive than copper, which directly translates to better efficiency but unfortunately, it increases module prices significantly. In order to decrease the price of the module, researchers in Germany began investigating where copper can be an alternative to silver. If the project is successful, the affiliated companies expect to be able to cut the costs of solar cell manufacturing by around 10%.

Another improvement in increasing efficiency of solar cells comes by way of Las Vegas. No, not sin city but what is dubbed “LasVeGas”. It is a German acronym standing for:”long-term stable front – side metallization on the basis of environment-friendly galvanic layers”. Both projects are still in theoretical phase, thus it will be a few more years before practical implementation will see the day light. In first phase, researchers will study the depositing of copper on existing cell structures and secondly, interconnection of the new cells into modules. This will entail transferring the results into actual production. A grant of 1.8 million Euros  was set up by German Federal Research Ministry, which will be used by joint venture of the companies Schott Solar, Rena GmbH and CiS Research Institute.
July 12th, 2011 at 2:57 pm

         The average installed cost of a photovoltaic (PV) system has declined substantially since 1998 — by almost 30 percent. Early indications show that the rate of decline accelerated in 2010. This historical trend suggests that PV policies have achieved some success in fostering competition within the solar industry and have satisfied a key goal: encouraging cost reductions over time.


           An annual report identifying trends in the installed cost of grid-connected PV systems in the United States - “Tracking the Sun III” confirms that the installed cost of PV systems declined substantially since 1998. Roughly 75 percent of this cost reduction was associated with a decline in non-module costs; these may include inverters and mounting hardware, and also labor, permitting and fees, shipping, overhead, taxes and installer profit. Starting in 2005, cost reductions began to stall, as the supply-chain and delivery infrastructure struggled to keep pace with rapidly expanding global demand.

 

Installed Cost Trends over Time for Customer-Sited PV

 

 

                  Over the past year, consumers in the United States finally started to reap the benefits of declines in module prices. Based on preliminary data, average installed costs fell dramatically in 2010. “Tracking the Sun III” presents partial-year cost data for systems installed during 2010 in California and New Jersey, the two largest markets in the United States (figure 2). For systems installed through the California Solar Initiative program during the first 10 months of 2010, average installed costs were $1 per watt below the 2009 average. Similarly, in New Jersey, average costs through June 2010 were down $1.20 per watt from 2009 levels.

 

The report also finds that PV systems demonstrate economies of scale. Systems smaller than 2 kilowatts (kW) that were installed in 2009 averaged $9.90 per watt, while systems larger than 1,000 kW averaged $7 per watt, or about 29 percent less. Additionally it shows that installed costs for residential systems declined significantly when the PV systems were installed on new structures. Among residential systems in the 1–kW to 3–kW range funded through two California incentive programs (the New Solar Home Partnership Program and the California Solar Initiative) and installed in 2009, PV systems installed on new residential structures cost $1.60 watt less than comparably sized residential retrofit systems (or $1.90 per watt less for rack-mounted systems).

The report also describes trends in PV incentive levels and the net installed cost paid by system owners after receipt of such incentives. The combined post-tax value of all levels of incentive — state/utility cash incentives plus state/federal income tax credits — averaged $3.90 per watt for both residential and commercial PV systems installed in 2009. This translates into an average net installed cost of $4.10 per watt for residential PV and $4.00 per watt for commercial PV. For commercial PV, this represents virtually no change from 2008, as the average incentive and pre-incentive cost remained relatively flat. However, for residential PV, the average net installed cost in 2009 represented a historic low, having declined $1.30 per watt, or 24 percent, in only one year. This trend is largely a consequence of lifting the $2,000 cap on the federal investment tax credit for residential PV systems beginning in 2009.

Trend toward declining installed costs, along with the narrowing of cost distributions, suggests that PV deployment policies have achieved some success in fostering competition within the industry. In other words, overall prices declined and  improved PV delivery considerably. The fact that states with the largest PV markets have somewhat lower average costs than states with smaller markets lends credence to the premise that state and utility PV deployment policies can affect local costs. However, installed costs in Japan and Germany are significantly lower than in the United States, suggesting that deeper near-term cost reductions may be possible here. Indeed, further cost reductions will be necessary if the PV industry is to continue expanding in the customer-sited market, given some policymakers’ desire to further ratchet down the financial support offered to PV installations.

 

 

By Konrad Gornicki
June 15th, 2011 at 6:00 pm

Roughly two and a half ago, photovoltaic panels cost about US$3.50 a watt. Today they hover around US$2 a watt, and by sometime in 2012 they're predicted to be less than US$1 a watt.

 

Last July, the Chinese government stated it would subsidize 50% of investments for solar power projects. Between now and 2015, the administration plans to more than double its “environmental protection” spending to as much as $454 billion. This will result in mandates for using renewable energy generation sources, including solar. They're so low that European and Japanese suppliers can't compete with the low cost of Chinese products. Only the best equipment is used in China. The Chinese solar panel quality is as good as or better than the top brands in Europe or Japan. One of the most labor intensive elements of solar panel manufacturing is the final assembly. Despite China's greatest advantage being its low cost of labor and output, Chinese companies are beginning to do final assembly in the United States in order to sell into municipal and government projects through the ARRA (American Recovery and Reinvestment Act) requirements. 

 

A good example of Chinese solar entrepreneurship is Yingli Green Energy. With global demand up, Yingli doubled production capacity and ran its factories 365 days a year, 24/7. The company claims that they sold everything, and Europe seems to be the largest market since they provide generous subsidies for solar-energy producers, for instance 60 percent of Yingli's revenues last year came from Germany. Yingli plans to expand production another 70 percent this year, and it isn't alone: Other Chinese solar companies, including Suntech Power Holdings and LDK Solar, plan double-digit production boosts in 2011. Suntech is expanding U.S. market; the company opened an 117,000-square-foot panel plant in Arizona last year and is doubling its U.S. head count to 150 people. "All of the major Chinese producers are engaged in massive, very aggressive capacity-expansion programs," says Paul Leming, an analyst with Soleil Securities in New York. Tellingly, Chinese-based Suntech Power Holdings will become the second-largest supplier of photovoltaic (PV) cells in the world this year behind Arizona-based First Solar, Inc. Our purchasing department has seen an increased amount of newer Chinese manufacturers looking to stock and list their modules on our website. Our decision to list modules on our website includes reviewing the Fraunhofer Institute in Germany to determine if they have experience evaluating these lesser known brands. Second, we speak to our European customer base and have them give us testimonials on certain name brands new to the North American scene. The selections are daunting, however having Aten Solar as a source for information and reviews allows installers or “do it your selfers” a level of comfort and assurance when deploying their next solar array.
May 17th, 2011 at 5:02 pm

The global market this year will be dramatically different than 2010. Rapid production expansion in 2010 and sluggish demand in Germany and Italy in 2011 has led to a build-up of module inventory globally. We estimate there are more than 500 companies manufacturing modules at the moment. In the global market place, Aten alone has designed and sold products from 22 different brands last year. 2011 will see many new module brands appearing on the US market as manufacturers who had focused on the European market shift towards the US. Some manufacturers will go to market based on containerized orders (over 500 modules per order) while others will sell pallet quantities of 20.  Aten Solar plans on being the go-to source for sorting through this increasingly complex and volatile market.

 
May 10th, 2011 at 6:32 pm

Dear friends and dealers,

I got a first-hand look at the M215 with some hands-on demonstrations in NJ. Here's a quick rundown of M215 info that I've got:

*  recommended DC input is up to 260W - while module right-sizing for the M190 continues to be 125% of inverter rating, on the M215 it's 120% because...
*  the M215 is more efficient than the M190 - CEC weighted efficiency at 96.5%, and beta tests are looking even higher
*  the M215 is both smaller and lighter than the M190, has a single mounting point, and has improved communications software
*  it is made for 60-cell panels only
*  S22 for MC4 (rather than S12) and S23 for Tyco (rather than S13)
*  string configurations are 26 panels for 208V, or 17 panels for 240V
*  like the D380, the inverter is phase-agnostic; the cable determines the phase
*  using the 20A breaker

There is no longer an AC interconnect or an Enphase extension cable in the M215 world.  Instead, cable will be sold in spools or rolls that can be cut to length to fit your installation, with drops spaced evenly apart.  Cables are available for both portrait and landscape installations (where the drops in landscape are further apart).  This cable will be run through a strain relief and into a J-box (acting as the AC interconnect).  It can also have drops capped off to act as an extension cable between rows.  This will cut down on the number of parts that need to be ordered.  Cable will be available in several lengths, including a 240 drop "bulk roll," and smaller 30 and 40 drop rolls.

I've attached a cut sheet for the M215 here, and if you are looking for an Enphase Road Show to get to, check this link:  http://enphase.com/next-gen/

 

 

Product Details
April 29th, 2011 at 5:12 pm

The Enecsys micro-inverter represents a breakthrough in inverter design for residential and commercial solar photovoltaic (PV) installations. Its patented technology has, for the first time, eliminated components that limit inverter life, namely electrolytic capacitors and opto-couplers.  Originally developed at Cambridge University, UK, the Enecsys micro-inverter enables solar PV systems to harvest between 5% and 20% more energy over their lifetime. The electrical components of Enecsys design are also worth mentioning since electrolytic capacitors were replaced by their much more reliable ceramic counterparts, significantly prolonging the life of the micro-inverter. Shading caused by clouds or obstructions have minimal impact on overall system performance because power is harvested from each module individually, rather than from groups of modules strung together. This also means that installations can mix and match different modules and do not need to be on the same roof plane, multiple planes can be used to harvest more energy and systems are scalable. A potential single point of failure – the central inverter – is eliminated and dangerous high-voltage DC is not produced.The Enecsys micro-inverter is the only product of its kind, available in both Europe and North America that matches the operating life of solar modules (more than 25 years), operates from -40 to +85 degrees C and and has a warranty for 20 years. Enecsys micro-inverters are installed on the rack behind solar modules, either one inverter per solar module, or one for every two modules.

The following is sample systems applying two competitive micro-inverter technology and regular string size inverter.

1)       Enphase system:  20 x REC 230W , 20 micro-inverters  M190-72 with Envoy;  total  $15,350 plus mounting and other BOS.

2)      Enecsys system: 20 x REC 230W – $9154.00, 20 micro-inverters  Enecsys SMI-S240W -72 plus;  total $16,343 plus mounting and other BOS

3)      Kaco with Watchdog :   20 x REC 230W – $9154.00, Kaco 5002i inverter;  total $14,161 plus

Mounting and other BOS.

 

At first regular string inverter seems to be the most economical. It will harvest the least amount of power though, since shading and other factors will have effect on the whole system, so the price per kilo watt/hr is actually higher than other two systems. The micro-inverter technology allows Enphase and Enecsys work more independent from mentioned factors since power is harvested at each and every module. It seems that Enphase has Enecsys beat in terms of  pricing, but during days when maximum power output can be expected i.e. 230W per module, the Enecsys has upper hand because it can gather all energy from modules, while Enphase will cut of at 190W. It is worth mentioning that Enphase is not easily available and potential clients have to wait several weeks before they can implement the system. Enecsys on the other hand is available with no delays. So therefore buyers finally have options when it comes to their micro inverters pv projects. We predict this is just the start of an explosive sub market.

 

Written by

 

Konrad Gornicki

 

 

 
April 1st, 2011 at 3:50 pm

 

 

Over the past year, there has been an explosion in the popularity of solar inverter solutions with MPPT tracking for each module. This technology has significant benefits in output, reliability, and flexibility over standard centralized inverter options, especially in partially shaded environments. Of course, there is a cost drawback to every new and complex entry into the market, but cost-benefit analysis will show that in some cases the extra investment will pay for itself handily.

            There are three types of MPPT-per-module systems on the market: standalone MPPT controllers such as Tigo products, per-module microinverters like Enphase, and the SolarEdge system, which has a central inverter connected to MPPT trackers per module. The most popular of these by far is Enphase, and for good reason: the flexibility is unparalleled. Enphase sells microinverters in single-phase and three-phase configurations with power levels at 190W and 210W and with MC4 or Tyco connectors. Modules can be mixed and matched, and the inverters are inexpensive to replace if they fail out of warranty. Unfortunately, availability is still extremely tight, so if you are an installer or a homeowner who is looking for Enphase, you better get in line.

            Let’s see what happens when we implement Enphase and Tigo solutions on a typical 4 kWp system located in central NJ with a 30˚ pitched roof and partial (50%) shading on two modules on one string and one module on another for 3 hours during the peak of the day:

 

            1) Enphase system parts: 18x Gloria Solar 230W, 18x Enphase M190 with Envoy and cabling: approx. $13,500 plus mounting and other BOS.

            2) Tigo system parts: 18x Gloria 230W, 18x Tigo ES050V, Tigo monitor, Kaco 3502xi: approx. $13,100 plus mounting and other BOS.

3) Control system parts: 18x Gloria 230W, Kaco 3502xi: approx. $11,700 plus mounting and other BOS.

 

            The Enphase output will only decrease by the lack of energy going out from the three shaded modules, or approximately 1.08 kWh per day at 3.9h insolation and an 80% derating factor. The Tigo system will operate slightly differently—because the output is stil DC, it will regulate the voltage and current on the affected modules until the string is uniform. Tigo calls the technology “impedance matching” since it observes and matches impedance seen at each energy maximizer connection, but the current in the string does not need to stay uniform since the maximizer will bypass current around modules as suited. As a result, the system will lose 1.08 kWh plus impedance matching losses. Unfortunately, the exact losses are rather difficult to calculate, especially since Tigo’s algorithm is proprietary. The control system, without any MPPT per module device, will lose approximately 6.5 kWh per day, or about 50% of the maximum without shading.

In this sense, both Enphase and Tigo systems are both winners because they give significantly lower costs per kWh even if costs per peak kW are slightly higher. In fact, with SREC prices at $500 per 1000 kWh, the Enphase system will pay for itself over the control system in about two years. If you or your clients have significant shading, please consider investing in one of these solutions—your mileage may vary, but in the end, you will benefit.
January 22nd, 2011 at 5:20 pm

 

  
    Transformerless PV inverters have been available in ROW markets for several years now, but a change to the NEC guidelines for PV has allowed these units to be produced for use with the 60 Hz grid in the US and Canada. They are significantly lighter than their galvanically isolated counterparts and can offer a wider range of operating voltages than traditional inverters because of their advanced switching circuitry. However, there has been reluctance among installers to implement these units, mostly due to lack of necessity and perceived safety concerns. This article will explain the differences between galvanically isolated and transformerless inverters to better inform the installer.
 
       The idea behind transformerless switching has existed long before the PV market was even developed. Device engineers have known that a pair of field-effect transistors operates most efficiently in a complete ON or OFF state, when no current flows through them, and they dissipate no power. Thus, amplifying an ideal square wave would theoretically be 100% efficient. If a signal is modulated by a much higher-frequency square wave, the result is pulse width modulation (PWM), and the corresponding circuit is called Class D. In this manner, it is possible to convert DC to DC, or efficiently switch DC to AC. For solar inverters, the technology was not available in the past because of the high cost of the switching MOSFETs and IGBTs. These, however, are getting cheaper and faster every year, so the technology has become more cost-effective than analog switching into large masses of copper and iron. The same technology is making electric cars feasible.
 
        The downside of not having galvanic isolation is the possibility of a ground fault destroying the inverter and causing an electrical fire. With a transformer, if the secondary is shorted, then all of the current will flow through the primary and will (hopefully) be stopped by a thermal disconnect once the transformer overheats. Without one, if no protection exists or if the protection fails to detect the ground fault and trip, the large MOSFETs or IGBTs will immediately fail in a rather catastrophic manner. Fortunately, the likelihood of such an event occurring is extremely remote, and all such inverters are required to have ground fault protection as per UL 1741 requirements. The burden, however, remains on the installer to insure that backfeed current in the case of an undetected ground fault is taken into account when sizing combiner and disconnect fuses.
 
         Thus, provided that the correct simple calculations are performed, there are few downsides and numerous benefits to transformerless inverters. Crews will certainly notice the reduced weight and size of these new inverters, and home and business owners will see increased yields over traditional designs due to increased efficiencies and wider operating voltage ranges. In short, there are always early adopters of new technologies, as well as holdouts who refuse to let go of their horse buggies when the rest of the world is already driving cars. Here, the cars are well proven.

 
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